Techno-Economic Assessment of Offshore Wind Expansion in the North Sea
DOI:
https://doi.org/10.5281/zenodo.22793109Keywords:
offshore wind energy, levelized cost of electricity, floating wind turbines, fixed-bottom foundations, wake losses, North Sea, interconnector grid integration, energy transition scenariosAbstract
The North Sea basin is expected to carry a large share of Europe's offshore wind build-out through mid-century, but
published cost estimates for that expansion diverge widely depending on assumed foundation mix, wake losses and
grid integration costs, making it difficult to judge whether current 2040 and 2050 capacity targets are cost credible
rather than aspirational. We built a bottom-up levelized cost of electricity (LCOE) model covering capital
expenditure, operating expenditure, decommissioning, and financing cost for fixed-bottom monopile, fixed-bottom
jacket, and floating semi-submersible foundation types, parameterised against 41 operating and under-construction
North Sea projects and reanalysis-derived wind resource fields at 3 km resolution, with farm-level capacity factors
adjusted for wake losses using a Jensen-type analytical wake model calibrated against measured production data
from four reference wind farms. We then combined the LCOE model with a discrete-choice build-out allocation
routine and an interconnector cost module to compare three stylised pathways to 90 GW of installed North Sea
offshore capacity by 2040: a shallow-water-first pathway, a floating-early pathway, and a cost-minimising pathway
unconstrained by water depth. Fixed-bottom monopile projects in water depths under 35 m achieved a median
modelled LCOE of 74 EUR/MWh in 2023 terms, compared with 127 EUR/MWh for floating semi-submersible
projects in depths exceeding 60 m, though the gap narrowed to roughly 35 EUR/MWh under the most optimistic
2040 floating cost-reduction assumptions. Wake losses reduced farm-level annual energy production by a mean of
11.8 percent across the fleet, rising above 15 percent for the most densely packed clusters in the German Bight, a
factor that shifted the cost-minimising pathway toward wider turbine spacing than commercial developers currently
favour. Interconnector and onshore reinforcement costs added a further 9 to 18 EUR/MWh depending on
landing-point congestion and the degree of multi-purpose interconnection assumed. Under our central assumptions,
the cost-minimising pathway reached the 90 GW target at roughly 6 percent lower cumulative system cost than the
shallow-water-first pathway, primarily by deferring floating deployment until unit costs fall, though this advantage
depends sensitively on how quickly floating technology costs actually decline, which remains the largest single
source of uncertainty in our results.
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