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Methodology

Generation, imports and demand

Annual data from 1990 to 2023 is gross generation, published primarily by Eurostat with wind generation data from IRENA. 2024 data is an estimate of gross generation, based on net generation gathered from monthly data. This estimate is calculated by applying absolute changes in net generation to the most recent gross baseline.

Net imports from 1990 to 2023 are also published by Eurostat, with recent data estimated in the same manner as generation. Demand is calculated as the sum of generation and net imports, and validated against direct demand figures published by ENTSO-E.

Monthly data is gathered from a number of sources, including both centrally reported ENTSO-E data and directly reported national transmission system operators. In some cases data is published on a monthly lag; here we have estimated recent months based on relative changes in previous years. These cases are flagged in the dataset.

Monthly published data is often reported provisionally, and is far from perfect. Every effort has been made to ensure accuracy, and where possible we compare multiple sources to confirm their agreement.

Below is a list of countries included, and sources for monthly data:

• Austria: ENTSO-E, Eurostat, E-Control GmbH
• Belgium: ENTSO-E
• Bulgaria: ENTSO-E
• Croatia: ENTSO-E
• Cyprus: Eurostat; hourly data used in analysis from Cyprus Transmission System Operator
• Czechia: ENTSO-E
• Denmark: ENTSO-E
• Estonia: ENTSO-E
• Finland: Biomass, gas, hydro, solar and wind from Eurostat; other fuels from ENTSO-E; hourly biomass data used in analysis based on ENTSO-E and Eurostat
• France: ENTSO-E
• Germany: Gas and solar from Energy-Charts; other fuels from Agora Energiewende; flow data from ENTSO-E; yearly gas generation data from the Energy Institute
• Greece: ENTSO-E
• Hungary: Solar data before 2020 from Eurostat; other fuels from ENTSO-E
• Ireland: Generation and flow data from Sustainable Energy Authority of Ireland; hourly data provided by Green Collective
• Italy: Bioenergy and solar from Terna; other fuels from ENTSO-E; flow data from Terna
• Latvia: solar from AST; other fuels from ENTSO-E
• Lithuania: ENTSO-E
• Luxembourg: ENTSO-E
• Malta: Eurostat; no hourly data available for use in analysis
• Netherlands: Base data provided by Statistics Netherlands (CBS); more recent months estimated based on data from EnergieOpwek; hourly data from the nationaal energie dashboard from 2021 onwards, pre-2021 data is based on ENTSO-E and CBS. 
• Poland: Solar data from ARE via Instrat; other fuels from ENTSO-E; pre-2021 hourly solar data used in analysis modelled based on capacity from Instrat and insolation data from Open-Meteo
• Portugal: ENTSO-E
• Romania: ENTSO-E
• Slovakia: ENTSO-E
• Slovenia: ENTSO-E
• Spain: ENTSO-E; flow data from Red Eléctrica
• Sweden: ENTSO-E; hourly solar data used in analysis from Elstatistik

Wind installed capacity data

Actual and projected installed wind capacity is based on the data provided by Wind Europe in Wind energy in Europe: 2023 Statistics and the outlook for 2024-2030. Updates to expected gross 2024 additions by country were published in their autumn update and where these differed to the previous forecast gross additions, this difference was applied to expected net additions to calculate installed 2024 total capacity. This report also takes into account the estimated gross wind capacity additions for the EU as a whole, published January 2025.

Wind auction data

The basis of the wind capacity auction data is Wind Europe. For 2024 and 2025 Ember supplemented this with awarded and announced capacity auctions from national agencies in charge of the tendering process. The average strike price is calculated as the capacity-weighted strike price in EUR/MWh. Offshore refers to both floating and fixed-foundation offshore wind. The total auctioned capacity for 2024 may still increase, as results from some auctions, particularly those scheduled for December, are yet to be announced. Auctions with tender applications extending into 2025 are categorised under 2025.

Solar installed capacity data

Capacity numbers presented are in units of direct current (DC, gross output). Due to the lack of transparency on this issue in national reporting, not all capacity data in national energy and climate plans can be guaranteed to be in units of DC.

As part of the REPowerEU plan, EU solar strategy aims to bring online over 320 GWac of solar photovoltaic by 2025 (more than doubling compared to 2020) and almost 600 GWac by 2030. Those official numbers refer to units of alternating current (AC) and have been converted to units of direct current (GWdc) by multiplying by 1.25.

The source used for solar capacity data is SolarPower Europe.

Annual capacity additions translated in number of panels added per day, assuming an average panel size of 400 W.

The source for national solar targets is Ember’s Live EU NECP Tracker.

Behind the meter solar

We implemented adjustments for behind the meter solar not accounted in official statistics  for six countries (Austria, Croatia, Portugal, Spain, Slovenia, Romania), affecting 2022-2024.

Gas demand and imports

EU total gas demand: 2019-2023 based on Eurostat;  2024 calculated based on IEA forecast for 2023/2024 year on year change (-2%) and Eurostat data for 2023. 

Share of Russian gas in EU power sector’s gas demand: gas import data by departure and destination country provided by the Centre for Research on Energy and Clean Air (CREA) was used to calculate Russian share of imports. This was scaled to share of consumption using country import dependencies derived from Eurostat gas consumption and production data. Import dependencies for 2024 were taken from 2023 due to Eurostat reporting lag. The percentage of Russian gas burnt for power generation is assumed to be the same as the percentage of Russian gas in total consumption per country. This percentage is then applied to country gas in power demand and values summed across the EU to get the share of Russian gas in EU gas in power demand.

The LNG share in EU gas imports was calculated using Bruegel’s gas import tracker.

Avoided fossil fuel import costs

This method estimates avoided fossil fuel import costs due to added wind and solar capacities between two chosen years. For each fuel (onshore wind, offshore wind and solar), additional capacity is defined on a monthly basis as the difference between installed capacity in a given month, compared to the same month in an earlier reference year. Monthly capacity data from various country sources is available for Belgium, Denmark, Finland, France, Germany, Poland, Portugal and Spain. Where monthly capacity data is not available, a linear interpolation is performed across the year in question. Projected installed wind capacities for the end of 2024 are taken from WindEurope’s Autumn 2024 report as this is the latest country-level information available. Solar yearly capacities come from SolarPower Europe’s EU Market Outlook 2024-2028. 

This approach provides a scaling factor for each month of the year of interest, which is then applied to actual hourly generation data to estimate the volume of generation from new additions of each technology. It is assumed that if the new wind and solar hadn’t been installed, the resulting generation gap would have been filled with another fuel. To determine which fuel would have replaced it, the following steps are applied, in order, to each hour of generation data:

• If fossil generation accounts for <5 % of hourly generation, it is assumed that extra wind and solar did not displace fossil, as it is likely other clean sources or imports – lower in the merit order than fossil – would have produced instead
• If fossil generation is within 5% of its yearly minimum, it is assumed that additional wind and solar did not displace fossil, which is assumed to be operating at a minimum ‘must run’ level. This takes into account, for example, combined heat and power plants which must often run at minimum capacities. 
• If a country has no coal or gas capacity (eg Cyprus), all additional wind and solar is assumed to have replaced ‘other fossil’ 
• Short run marginal costs (SRMCs) for gas and hard coal are then used to determine which fuel would be setting the marginal price. It is assumed throughout that lignite is cheaper than hard coal and gas and would therefore not be the marginal price setter. 
• If gas is the most expensive SRMC and gas generation is not zero in the given hour, it is assumed that gas is the marginal price setter and therefore has been displaced by added wind and solar capacity in that hour. The same logic applies to hard coal if it has a higher SRMC than gas.
• If gas is the most expensive SRMC but is not generating in the given hour, it is assumed that hard coal (so the second most expensive technology) would be displaced, and vice versa. 
• In both points above, an installed capacity check is made to ensure there is sufficient hard coal or gas capacity available such that it could have generated more in the absence of the added wind and solar. Capacities are taken from GEM’s coal and gas trackers. In the rare case there is insufficient capacity for one of these fuels, the gap is made up using the other, or if there is insufficient of either, then ‘other fossil’ is used.

The above steps are applied, and summed over the hours of the year, to calculate the amount of hard coal and gas generation avoided by new wind and solar capacities added between a historical reference year (e.g., 2019) and a chosen year of interest (e.g., 2024). 

To estimate the share of this avoided gas and hard coal generation that would have used imported fossil fuels, the avoided generation values are multiplied by gas and hard coal import dependencies per country per year. Import dependencies are derived from Eurostat data, so values are not available for 2024 due to data reporting lags. To fill this gap, values are carried over from 2023, which represents a conservative approach as indigenous production is generally in decline across the EU. 

To calculate avoided fossil fuel import costs, the avoided gas and hard coal generation in TWh are first divided by assumed plant efficiencies of 50% (Higher Heating Value) for gas and 40% for hard coal to estimate the volume of fuel avoided, and this value then multiplied by respective fuel costs. These are taken from day ahead TTF prices for gas, unless specific country market data is available, and daily front month API2 prices for hard coal. 

Avoided gas imports are converted from TWh to bcm using a calorific value of 35.17 MJ/m3. Avoided coal is converted from TWh to million tonnes by multiplying by 0.122.

To calculate total avoided fossil fuel import costs thanks to wind and solar added since the start of the Green Deal, the above methodology is applied to each year from 2020 up to 2024 inclusive, using the historical reference year of 2019. Malta is excluded from this calculation due to a lack of data.

Solar capture rates calculations

Solar capture rates reflect the market value of solar energy when sold on the day-ahead market. Solar capture prices are the average prices that a solar generating unit earns for each kWh sold to the market, determined by its hourly production profile and the hourly spot power prices over a specific period. They are calculated using hourly day-ahead prices from ENTSO-E and hourly generation data as described above. Our model shows the one-year rolling average to give a better understanding of the long term development of solar capture rates. A marginal price-taking solar with a co-located battery storage unit is modelled with the following assumptions:

• 90 MW AC solar array with output based on national generation data
• 60 MW AC battery with 1 hr (60 MWh) energy capacity
• 100 MW AC inverter
• 87% round trip efficiency, implemented on charging side, such that the battery charge rate is 87% of the panel discharge rate into the battery (i.e. a maximum charge rate of 52.2 MW)
• 0 MWh minimum state of charge

The cycle strategy is as follows:

• Peak charging and discharging hours are parameterised by finding average minimum daytime and maximum evening price hours per quarter per country. These tend to be around midday and 6-7pm.
• Charge symmetrically around peak hours, maintaining a level output profile to the grid. Any generation that would otherwise be curtailed (e.g. when the array output is bigger than the inverter capacity) is used to charge the battery if possible. The battery is charged as much as possible.
• Discharge symmetrically around peak hour at maximum possible rate
• No charging from the grid is allowed

This strategy is intentionally simple and is not optimised with real-time price information. It therefore represents an underestimate of the true marginal value of battery storage.

Power price data

Wholesale electricity prices are average day-ahead spot prices per MWh sold per time period, cleaned and sourced from ENTSO-E. These are the prices paid to electricity generators, and are not the same as retail electricity prices or total costs to end users.

Within-day power price spreads refer to the difference between the maximum and minimum day-ahead electricity prices within a day. Price spreads not computed for Cyprus, Malta, Luxembourg due to lack of reliable price data.

Corrections

A previous version of the graphic ‘EU coal power is on its way out’ said that 6 EU countries never had coal in their electricity mix. This was corrected to 5 EU countries on April 2 2025 as Malta phased out coal power in 1995, before the time series in the graphic began.