Europe

Primary energy consumption (EJ/yr)

The primary energy mix has been dominated by fossil fuels, but their share will drop from two-thirds today to a third in 2050 – coal will then be at negligible and oil demand a third of what it is today. Natural gas will retain share longer as a less polluting option to coal-fired firm power capacity. The fossil energy will be replaced by wind and solar, whose combined share reaches 50% in 2061. Bioenergy and nuclear energy will remain more stable, together growing by about 10% per decade.

Final energy demand (EJ/yr)

The strategic path forward for Europe is continuing and ramping up electrification. After having been stable around 21%, electricity’s share in final energy demand will double by 2050. This is, however, 10 years later than the EU’s ambition (EC, 2026a). Through electrification of end-uses, energy consumption becomes more efficient. This leads to decline in final energy demand from 2030, even though the useful work will increase. Hydrogen and its derivatives will start to play a role in a few specific hard-to-abate sectors, reaching 1% of final energy demand in 2040 and 5% in 2055.

Electricity generation (PWh/yr)

Electricity generation will almost double by 50. The power sector itself is seeing a true transition – solar and wind are not only replacing fossil power but also adding more generating capacity on top. In 2031, wind and solar will generate 50% of power on the grid. Consequently, solar PV installed together with energy storage (solar+storage), will be increasingly common to offset price cannibalization. Offshore wind will grow beyond onshore wind, tripling total wind capacity by mid-century.

CO₂ emissions by sector (GtCO₂/yr)

Europe’s emissions will continue to decline rapidly, but not fast enough to achieve the region’s prevailing climate ambitions of net zero by 2050 (Figure 4). Going sector by sector, the picture is more nuanced. The power sector will be net-negative by 2050, aided by CCS from bioenergy. Similarly, the manufacturing sector also reaches net zero by 2058, aided by CCS. However, although transport and building emissions also decrease through widespread electrification of their energy demand, these sectors are not enroute to reach net zero within our forecast period. In total, there will be 0.8 GtCO₂ remaining emissions in 2050, that is after 25 MtCO₂ of direct air capture (DAC). Europe reaches net-zero first in 2067, factoring in 90 MtCO₂ DAC.

Europe as a region is behind individual climate ambitions throughout our forecast period. Keeping in mind that our predictions exclude country-specific emissions, that Europe's domain extends beyond the EU, and that our forecast only includes energy- and process-related CO₂ emissions after CCS, not Land Use, Land-Use Change, and Forestry (LULUCF), our forecasted emissions are:

• 1990 to 2030: We forecast That is less than the EU and UK commitments in Nationally Determined Contributions (NDCs) aim for GHG emission reductions of 55% and 68%, respectively.
• 1990 to 2035: We forecast 50% reduction. In comparison, the UK has set a target of 81% GHG reduction, including LULUCF, and the EU has committed to reducing emissions by 66.25% to 72.5%, including LULUCF. These targets represent a 68% decrease in emissions, excluding LULUCF, in Europe.
• 1990 to 2050: We forecast 82% reduction to 0.8 GtCO₂ after DAC. This indicates that Europe will not fully achieve the prevalent net-zero pledges among its nations.

European energy import dependency

Increasing the security of energy supply by reducing import dependency is an important reason for the acceleration of the European energy transition. The region has been a net energy importer, and more than 50% of its primary energy demand is still met by imports.

Europe depends principally on fossil fuels, primarily from the Middle East, Russia, and the US (see Fig. 5). Less than half of Europe’s natural gas and refined oil products come from the region itself, and only a quarter of its crude oil demand is met by its own production. In 2025, the cost of fossil fuel imports was EUR 340bn (EC, 2026b). Nuclear are also largely imported but their security of supply is less fragile because just-in-time delivery of them is less prevalent than for fossil fuels. Once the fuels are imported, Europe as a whole, not only the EU, is self-sufficient in power generation and currently has a small margin for electricity export, with most power trading being between countries within the region.

Russian supplied more than a third (37%) of Europe’s natural gas in 2019. After the invasion of Ukraine, Europe halted Russian LNG imports by ship, and the EU started phasing out imports of all Russian coal, gas, and oil. This caused a gas supply crisis and higher power prices in 2022. Since then, LNG imports from the US have replaced half of the previous supply from Russia (see Fig. 5).

The oil supply is similarly exposed to geopolitical disruption. First, oil imports from Russia were phased out and partially replaced by additional volumes from the US. Oil product imports were not replaced at all (see Fig. 5). This year has seen the blockade of the Strait of Hormuz, through which around a fifth of global seaborne crude oil normally passes. After a recent drone attack on a pipeline in Saudi Arabia, crude exports to Europe through the Red Sea will also be affected from (Su, 2026).

Nuclear fuels are almost entirely sourced from raw uranium mined outside Europe, mainly from Canada, Kazakhstan, Niger, and Russia. Furthermore, a large share of processing to enriched uranium occurs outside Europe’s borders, mainly in Russia. It is more difficult to reduce the dependency on Russia for nuclear services, particularly as some European countries still operate Russian-designed nuclear power plants (EC, 2026c).

High power prices

High power prices are one consequence of Europe’s dependency on imported natural gas. The spike in power prices during the 2021–2022 gas crisis (see Fig. 6), was exacerbated by the reduction of imports from Russia after the invasion of Ukraine. Some countries – examples being Canada, China, South Korea, and the US – did not see a similar price spike during this period.

European power prices have recently been closely connected to the high cost of natural gas. That is due to Europe’s dependency on natural gas-fired power, the way the European power system works, and the high cost of natural gas. Natural gas supplies a large share of the power on the grid – 20% at the start of the 2020s. In the European power system, the most expensive power plant needed to meet the total demand dictates the price for all generators. Since the price spike for natural gas, gas-fired power plants have often been the most expensive generating unit needed.

The higher power prices strain household budgets as a larger share of income is spent on basic utility bills. This triggers social consequences, as low-income households are less able to afford investment in energy-saving solutions such as retrofits, EVs, and electric heat pumps. National governments have implemented various policies to shield consumers from rising energy prices (Twidale, 2022). One consequence of this is a reduced incentive to invest in energy saving measures, as the payback period increases.

The consistently higher power prices over the last five years (see Fig. 6) have also been detrimental to industrial competitiveness, reducing Europe’s economic security. Higher living standards and wage expectations also add to higher production costs. While it may be logical to buy cheaper products from abroad, particularly as the quality gap is decreasing or even reversing, this is a poor solution for the competitiveness of the region as a whole in a world with increasing regional rivalry.

Industrial competitiveness challenged by carbon pricing

It is important for Europe to maintain or even increase its strategic autonomy by regaining its position as a leader in cleantech supply chains for energy systems, computer hardware, software, AI, and other industries. Therefore, European policymakers are listening to European industry leaders arguing for lower energy costs and greater predictability of what rules they have to abide by.

Our expectation for Europe’s expected carbon price trajectory is lower than last year, following the reviewed EU Emissions Trading System (ETS) reform (see Fig. 7). As discussed in the Policy Observations section, the EU ETS-1 reform proposal reflects the balancing of climate and competitiveness objectives by softening stringency. Consequently, our outlook falls from last year’s 160 USD/tCO₂ to 145 USD/tCO₂ in 2035, the typical cost of carbon removals, with the gap widening thereafter, signalling a more flexible European transition rather than a retreat from carbon pricing.

The Carbon Border Adjustment Mechanism (CBAM) is implemented to protect European industry. Its aim is to level the economic playing field and prevent ‘carbon leakage’ by preventing companies from moving industrial production to countries with weaker environmental rules. This is necessary because Europe’s carbon prices are several times higher than in other regions (see Fig. 7). CBAM came into effect from January 2026 and will equalize carbon costs between domestic and foreign producers through a carbon cost on specific imported goods. However, until CBAM’s effectiveness is proven, the ETS reform will continue free allowances for sectors exposed to possible carbon leakage.

The European Commission also proposes to establish an Industrial Decarbonisation Bank (IDB) with EUR 100bn in funding. This EU-level entity will support the scale-up and deployment of technologies, processes and techniques that directly reduce emissions in stationary installations covered by the EU ETS.

The automotive industry is one example of an industry where the market share of European manufacturers is declining (Bjerkan-Wade et al., 2026). China’s domestic market grew 1,000% between 2020 and 2025 (see Fig. 8), but with low penetration by foreign brands, while Chinese manufacturers have captured additional 5% of the European market from 2025 to 2026, now holding 14% in total (Jolly, 2026). With the transition from internal combustion engine vehicles (ICEVs) to electric vehicles (EVs), new car brands have leapfrogged existing manufacturers. The existing industrial supply chains for ICEVs are thus becoming obsolete, while Chinese brands are exploiting cheaper labour, domestic subsidies, and China’s leading role in battery manufacturing.

Europe is already deploying renewables

Adding renewables capacity is no longer the main problem. The expected capacity additions of wind and solar in 2026 add up to 130 GW, five time greater than the average in the 2010s and equal to the average additions we forecast per year until 2060 (see Figure 9). While higher capacity additions would be necessary to reach Europe’s goal of 46% electrification by 2040 (EC, 2026a), these additions lead to the power generation mix in Fig. 3.

As (variable) generation from solar and wind increases, the role of coal- and gas- fired power plants in particular will change (see Fig. 10). Instead of continuous power generation, the fossil-fuelled plants will provide flexibility, generating power when other sources cannot, leading to an overall lower capacity factor (i.e. the share of time that this capacity produces power). The renewables will continue to produce when they can, meaning when the sun shines and the wind blows. With enough installed capacity, the renewables will be sufficient to meet the demand some of the time. In addition, nuclear power will continue to have the highest capacity factor by providing baseload, as it is not as flexible as thermal power generation.

European countries will not only add variable renewables, but also nuclear and gas-fired power for firm capacity. Countries with existing nuclear power are likely to install more, but so too will Poland, which currently has no operating nuclear plants. Nuclear generation can provide both firm capacity and, in theory, energy security. However, the energy security of nuclear power has been challenged this summer as droughts have left European rivers with insufficient water to cool several nuclear plants. While the capacity additions for nuclear power in Fig. 9 look small, the capacity factor is three times higher for nuclear than for solar power.

Energy import dependency falling

We forecast that the share of primary energy that Europe can supply itself will increase (see Fig. 11). While less than half has been domestically sourced in the last two decades, the share will grow to 50% in 2031, 60% in 2042, and 70% in 2053.

The reduced demand for primary energy imports is caused by greater demand for electricity and less for fossil fuels (see Fig. 2). The increased supply of electricity comes mostly from domestic solar and wind farms, not imported fuels (see Fig. 3). On the other hand, Europe will continue to import almost two-thirds of its fossil fuel requirement. Even though demand for coal, oil and gas is falling, so too is the European supply of these. Hence, it is only by transitioning to renewables that Europe becomes less dependent on primary energy imports.

However, Europe is still dependent on green technology imports. The EU imported EUR 14.6bn worth of green energy technology in 2024, mostly solar PV, of which 98% was from China (Eurostat, 2025). This dependency is less of a risk for supply security than the import dependency on fossil fuel, since solar PV can continue to produce power for decades. Nevertheless, depending on one supplier in particular represents technological and economic risk.

Energy prices decoupling from natural gas

European power prices will decouple from the cost of natural gas and decrease (see Fig. 12). High power prices in the beginning of the 2020s, were caused by a price spike for natural gas, exacerbated by the phase-out of Russian energy imports following the Ukraine war (EC, 2026d). With the forecast additions of renewable power and changed role of fossil-fired power plants, the link between the price of power and the price of natural gas will begin to break.

The cost of electricity from gas-fired power plants has frequently set the electricity prices in Europe. Power prices are set in the market by matching demand and supply – see more details in our global ETO report (DNV, 2026, Ch 4.11). Gas-fired power has often been the marginal generating unit necessary to meet the demand. During the gas price spike in 2022, they operated at a capacity factor of 42% and provided 20% of Europe’s power.

Going forward, the average wholesale electricity price will become decoupled from the wholesale price of natural gas (see Figure 12). This is due to more locally generated renewable power and other flexibility mechanisms, such as batteries. The role of natural gas will therefore change, from supplying base load capacity continuously, to supplying firm capacity when other sources do not. This is reflected by the declining capacity factor for gas-fired power plants, going below 20% in 2035. As a result, gas-fired power plants will operate when other power generation is insufficient and will be able to charge the highest average capture price in Europe when they operate. However, the average wholesale power price will be lower, going below 100 in the 2030s.

Spain illustrates how more renewable power leads to less dependency on imported natural gas. The wholesale power price and natural gas price in Europe from 2018 to 2024 are shown in Fig. 13 (EC, 2025a; Jagtenberg et al., 2025). The EU average power price tracks the cost of natural gas. In Spain, the average power price tracked that of natural gas in Q1 of 2022, but it did not experience the price spikes in the second half of 2022. This happened as Spain doubled its solar power production from 22 GWh in 2021 to 43 GWh in 2023 (IEA, no date-a). Within the EU, the maximum power prices during the gas price spike in 2022 were charged in Italy, where 44% of power was generated from natural gas in 2024 (IEA, no date-b). In comparison, the minimum prices during most of the gas price spike were charged in Slovakia, where only 9% of power was generated from natural gas in 2024 (IEA, no date-c).

European industry will remain  

We expect manufacturing industry to continue in Europe despite competitive pressures. However, the growth in secondary GDP is slower than in other regions; Greater China has already surpassed Europe and the Indian Subcontinent is soon to follow (see Fig. 14).

Europe will aim to keep some manufacturing output to ensure technological and economic security, despite the region’s higher carbon pricing and other production costs. Europe’s policymakers will continue to monitor the global transition and adjust incentives to support European manufacturing. The recent adjustments to the ETS are an example. Industrial competitiveness will be helped further by power prices declining as they decouple from the cost of natural gas.

However, to maintain its global position, strategic systems thinking for the manufacturing sector is needed. Europe has lost ground in general manufacturing to long-term strategic plans, cheap labour, subsidies, and foresight from Asia. It has also lost ground in technology like software and AI. One aspect of strategic planning is to build today for the world of tomorrow, exemplified through Europe’s aim to transition to domestic renewables rather than increase domestic fossil production. Another aspect is providing industry and the finance sectors with enough confidence and predictability to make investments, which has possibly improved this year through the amended ETS system. 

Electrification of end-uses

We forecast that the share of electricity in final energy demand will be 31% in 2040, far behind the target of 46% (EC, 2026a). To increase this share, it is not sufficient to supply more: end-users must also be ready to consume more of it. That readiness often comes at high upfront investment costs, preventing low-income households from participating in the transition, even if the total cost of ownership would be lower.

Among the main energy consumers, road transport will increase electricity demand the most by 2040 (see Fig. 15). Because personal vehicles are easier to electrify than commercial ones, they will transition to EVs slightly faster (see Fig. 16). However, even though the total cost of ownership can be lower for EVs (Furuseth, 2025), the high upfront investment prevents many from taking part in this transition. Since we forecast electricity to provide only a sixth of final road transport energy demand in 2040, this subsector has potential upside for faster transition if new incentives materialize.

The second greatest increase in electricity demand by 2040 will come from residential and commercial buildings due to increased demand from appliances, heating, and cooling. Space and water heating have the greatest potential exists for electrification by displacing natural gas as an energy source, but this transition is slow. While the cost of running an electric heat pump is lower, the high upfront investment cost is preventing households from making the change. We made similar observations for investments in rooftop solar and batteries last year (Furuseth, 2025). However, with the right support systems in place, the transition to electric heating could go faster.

The third greatest increase in electricity demand by 2040 will come from data centres. However, unlike road transport and buildings, data centres already only use electricity (see Fig. 16). Hence, the additional 230 TWh/yr for them does not represent an energy transition but an energy addition. Depending on how they are introduced, and how much added value they provide to society, data centres in Europe could experience ‘not-in-my-backyard’ opposition similar to what has already been seen, particularly in North America (Jones, 2026).    

Grid reinforcement

Europe can achieve a highly renewables-based power system and increased electrification of demand, but success increasingly depends on whether it can expand and modernize its grid fast enough. The transmission grid, in particular, needs major investment to increase cross-border connection and to connect renewable generation located far from demand centres. The limiting factor is shifting from permitting to build-out capacity.

The transmission grid will require the biggest expansion, to keep up with the new European energy system (see Fig. 17). Wind and solar generation are increasingly located far from demand centres. In addition, an expanded transmission grid can provide geographical balancing of weather patterns, from an area with sunshine and wind to one experiencing dunkelflaute (a period of little wind and no sun).

The distribution grid will also require expansion (see Fig. 17). The current loads are divided into approximately two-thirds for evenly distributed buildings and one third for scattered manufacturing. The added load (see Fig. 15) comes primarily from road transport, buildings, and data centres. Vehicles will charge at home and close to big roads, while data centres can be placed close to power generation. Furthermore, urbanization is the demographic trend in Europe. Hence, the distribution grid mostly needs reinforcement locally, not expansion over long distances like the transmission grid.

While permitting remains a challenge, grid build-out is increasingly constrained by delivery bottlenecks, causing the delay of transmission grid build-out in Fig. 17. As noted in our global ETO report (DNV, 2026, Ch. 4.9) the most severe equipment constraints are for large power transformers and high-voltage cables necessary to build-out transmission grids. Procuring transformers and high-voltage cables can take four and more than five years, respectively. This bottleneck follows from the vast build-out of renewable generation combined with permitting delays. As a result, the supply chain has not scaled up, and the cost of available equipment has risen sharply.

Once the equipment is delivered, lack of sufficient skilled labour is the next bottleneck. In a 2025 European industry consultation, 96% of participants said skilled-workforce shortages were already slowing progress towards energy-transition targets (ENTSO-E et al., 2025). Europe needs to expand the grid with more transmission and distribution line, as well as replacing ageing infrastructure. This work requires power-system planners, protection and control engineers, relay technicians, high-voltage cable jointers, substation commissioning specialists, tower and line crews, and workers capable of manufacturing and testing large transformers. There is a continent-wide shortage of these skills.

Generation management and system operation

Europe's electricity challenge is shifting to maintaining system adequacy in a highly electrified and renewables-dominated system. The region will have one of the world’s cleanest electricity systems, reaching almost complete decarbonization by the mid-2050s, with high shares of wind and solar. This transition shifts the challenge towards ensures electricity is available when needed.

Energy storage becomes a cornerstone for adequacy. More storage, both short-duration and longer-duration, is needed in the grid as more solar and wind capacity is added (see Fig. 18). Currently, solar and wind combined produce only a third of European power, and there is more installed capacity of other sources. However, with the forecast build-out rate, wind and solar capacity dominate capacity by 2029, and wind and solar together will generate more power than other generation combined in 2031. As these variable renewables dominate, the need for grid-connected storage power capacity grows, staying above 40% of the continuously growing wind and solar capacity. This storage has historically been mostly pumped hydropower, but will increasingly be batteries, often co-located with solar PV (‘solar+storage’). In addition, we forecast vehicle-to-grid (V2G) charging, which involves selling stored power from battery vehicles to the grid.

Flexibility in supply and demand will become more important and thereby valuable. Firm capacity generation, in the form of hydropower and thermal power generation, will play an important role in reducing the hourly variability of supply. As a result, it will receive the highest average capture prices. Similarly, flexibility in demand is already paying off; for example, by smart charging EVs at night when electricity prices are lower.

Market design that considers energy systems thinking will become part of ensuring adequacy. Europe will increasingly require 1) capacity markets, paying firm unused capacity for long-term availability, and 2) flexibility markets, paying for rapid responsiveness to short-term fluctuations. There is also need for revenue streams beyond the market-set volatile capture prices. While a purely LCOE (levelized cost of energy) consideration makes renewables investment look profitable, the investment will stall as average capture price becomes cannibalized.

Renewable investors will increasingly earn revenue not for each kWh sold but for delivering electricity at the right time in the right place. One response to this paradigm shift is to delay the electricity sales through strategies such as solar+storage, which stores power generated during the day and selling it later in the evening. Another response is to stabilize the capture-price erosion by striking purchasing power agreements (PPAs), particularly with data centres. That way, the energy system can benefit from installing more generation capacity with the lowest LCOE.