Differences in turbine size, weather models and wind wake effects can significantly alter offshore wind output estimates in the North Sea, with implications for Europe’s energy planning and investment strategies
How offshore wind output estimates vary across Europe
In the offshore wind sector, energy production estimates can shift by as much as 15 GW when key modelling assumptions change, including turbine characteristics, meteorological inputs and the way wind wake effects are simulated.
This is the main finding of a study published in Wind Energy Science, which focuses on the North Sea and highlights how technical parameters can substantially influence projections of electricity generation.
For the European energy system, this is not a marginal issue. Errors at this scale directly affect investment decisions, grid planning, auction design and industrial strategy. The study shows that the largest discrepancies stem from turbine configurations, while atmospheric conditions and wake interactions between neighbouring wind farms also play a significant role.
The North Sea study and Europe’s offshore wind targets
The research, conducted by the Helmholtz-Zentrum Hereon and the University of Hamburg, starts from a clear policy and industrial benchmark. Countries within the North Seas Energy Cooperation aim to increase offshore capacity from 26 GW in 2022 to at least 60 GW by 2030, and up to 300 GW by 2050 in the North Sea basin.
Such expansion implies denser clusters of wind farms, stronger interactions between installations and increased pressure on forecasting systems.
To assess these dynamics, the authors used the COSMO6.0-CLM regional climate model, enhanced with a dedicated wind farm module capable of simulating different turbine types, rotor diameters, hub heights and the gradual deployment of installations over time.
Turbine design drives most of the uncertainty in offshore wind output
The study finds that the combined uncertainty linked to meteorological datasets and turbine design reaches around 15 GW, equal to 10% of the simulated total capacity of 150 GW.
Of this variation, approximately 11 GW is driven by differences in turbine technology, while around 4 GW depends on the meteorological data used in the model.
Researchers compared scenarios ranging from 3.6 MW turbines to next-generation 15 MW machines. Even with identical total installed capacity, larger turbines deliver higher output. The reasons are structural: fewer turbines are needed, reducing mutual interference, while larger rotors and higher hub heights capture stronger and more stable wind flows.
In the simulated scenarios, average annual production rises from 62.6 GW with 3.6 MW turbines to 73.7 GW with 15 MW units.
Offshore wind capacity factor improves with next-generation turbines
The study also evaluates the load factor, defined as the ratio between actual energy production and theoretical installed capacity.
Using ERA5 meteorological data, the average capacity factor increases from 0.42 with 3.6 MW turbines to 0.49 with 15 MW turbines. Without wake effects, these values would rise to 0.57 and 0.61 respectively.
This indicates that a significant share of production losses is not due to limited wind availability, but to interactions between wind farms. This has direct implications for developers, utilities and grid operators, as it affects expected revenues and integration costs within electricity markets.
Offshore wind wake effects can extend beyond 50 km
One of the most critical aspects analysed is the wake effect. When a turbine extracts kinetic energy from the wind, it leaves behind a trail of slower, more turbulent air. Downstream turbines therefore receive less available energy.
Simulations and aerial measurements show that these wakes can extend for more than 50 kilometres in the North Sea. In the analysed cases, wind speed deficits immediately downstream of clusters reach around 1 m/s, while vertical reductions can reach 2.8–2.9 m/s, roughly 45% lower compared to scenarios without wind farms.
This makes the geographical layout of offshore installations not only a technical parameter, but also a key economic variable.
Seasonal impacts on offshore wind performance
Atmospheric conditions significantly affect offshore wind performance. During summer, average wind speeds are lower and atmospheric stability is higher. Under these conditions, natural turbulence decreases and wakes dissipate more slowly, amplifying their impact on downstream turbines.
The study shows that adjusting the turbulence parameter in the model reduces average production by around 2 GW, just over 1% of installed capacity. The relative impact is stronger in summer than in winter, as wind speeds more often remain below turbine rated power thresholds.
Why offshore wind output estimates matter for Europe’s energy system
For the European electricity market, the difference between simulated outputs of 62 GW and 74 GW is substantial. It affects project valuation, revenue forecasts, storage sizing, cross-border electricity flows and grid congestion costs.
Overestimating offshore wind output risks flawed business plans and underestimation of flexibility needs. Underestimating it may slow down investments and industrial development.
For this reason, the authors call for wind farms to be explicitly represented both in meteorological models and in historical reanalysis datasets.
What this study means for Europe’s offshore wind future
The expansion of offshore wind in Europe will not depend solely on permitting, ports and supply chains. It will also depend on the accuracy of forecasting models.
With expected capacity reaching up to 300 GW in the North Sea, even small percentage errors can translate into tens of gigawatts.
In this next phase of Europe’s energy transition, selecting the right turbine technologies and optimising the spatial planning of wind farms will be as critical as adding new capacity.
