Offshore Wind Explained: Turbines, Foundations, Costs and Output

No part of the wind industry went from niche to utility scale faster than offshore. The first offshore farm, Vindeby in Denmark (1991), used eleven 450 kW turbines. The machines now going up in Europe and China are rated at 14–16 MW, with rotors more than 230 m across, and single projects exceed 1 GW. This guide covers why developers pay the premium to build at sea, how the hardware differs from onshore wind, what output and costs look like, and where the real constraints are.

Why the wind is better at sea

The power in the wind scales with the cube of wind speed, so a small gain in speed brings a large gain in energy. Open water is extremely smooth: surface roughness is around 0.0002 m for calm sea, against 0.03–0.1 m for farmland and 0.5 m or more for forest. With less friction, wind speed is already high close to the surface and changes less with height. Turbulence is lower too, which cuts fatigue loads on blades and drivetrains.

Power density in the wind: P/A = ½ × ρ × v³ ρ ≈ 1.225 kg/m³ (sea level, 15 °C) v = 7 m/s → ½ × 1.225 × 343 ≈ 210 W/m² v = 10 m/s → ½ × 1.225 × 1000 ≈ 613 W/m²

So a site with a 10 m/s mean wind speed at hub height carries roughly three times as much power per square metre of rotor as a 7 m/s site. Good North Sea sites sit in the 9–11 m/s range; many onshore sites in Europe average 6–8 m/s. Our wind speed at height calculator shows how mean speed changes with height and terrain, and you can explore wind resources on the world energy map or by clicking a point in the Energy Explorer.

The payoff is a much higher capacity factor, the share of its theoretical maximum that a turbine actually delivers over a year (see what capacity factor means).

Technology	Typical capacity factor	Notes
Onshore wind, older fleet	20–30%	Smaller rotors, lower hubs
Onshore wind, new projects	30–45%	Large rotors relative to generator rating
Offshore wind, fixed-bottom	40–55%	North Sea projects often above 45%
Floating offshore (early arrays)	45–55%	Hywind Scotland posted some of the highest UK factors in its first years

These ranges are indicative, drawn from IEA’s Offshore Wind Outlook 2019, IRENA cost reports and NREL’s Annual Technology Baseline. Weather moves individual years by several percentage points.

The hardware: turbines, foundations and cables

Turbines

Offshore turbines are the same three-bladed, upwind, horizontal-axis design used on land, only bigger. Installation and foundations are a large fixed cost per position, so fewer, larger turbines mean fewer foundations, fewer cable runs and fewer vessel trips. In 2020 NREL and IEA Wind Task 37 published a public 15 MW reference turbine with a 240 m rotor and a 150 m hub height, representative of the machines entering service in the mid-2020s.

How they differ from onshore machines:

Direct-drive or medium-speed generators are common, because every gearbox part that can fail is far from shore.
Corrosion protection: sealed, dehumidified nacelles and towers, marine coatings and cathodic protection on foundations.
No transport limit: blades over 100 m long would be close to impossible to move by road, but they can be shipped straight from quayside factories.

Foundations

Foundation	Typical water depth	How it works
Monopile	up to ~40–60 m	Single steel tube, 8–11 m diameter for the largest turbines, driven or drilled into the seabed
Jacket	~30–60 m	Steel lattice with three or four legs pinned by piles
Gravity base	shallow, firm seabed	Heavy concrete base held down by its own weight
Floating spar	100 m+	Deep ballasted cylinder, very stable, but needs deep water at the quay too
Semi-submersible	~50 m+	Three or four columns, assembled in port and towed out
Tension-leg platform	~50 m+	Buoyant hull pulled down by taut tendons, small footprint

Foundations and installation often account for a quarter or more of project capital cost. Monopiles dominate installed capacity today because they are simple to fabricate in volume.

Electrical system

Each turbine feeds an array cable (typically 66 kV in newer projects, up from 33 kV) that links turbines to an offshore substation. There the voltage is stepped up to 132–275 kV for the export cable to shore. Beyond roughly 80–100 km, high-voltage direct current (HVDC) beats AC on cost, because AC cables draw large capacitive charging currents that eat into transfer capacity. HVDC, however, needs large and expensive converter platforms at sea, which makes AC versus DC one of the main design decisions on any project.

Cables cause a disproportionate share of lost generation. A fault on the export cable can take a whole farm offline for weeks while a repair vessel is mobilised, so newer projects increasingly install two export cables or link substations together.

Worked example: annual energy of a 1 GW offshore farm

Take a hypothetical North Sea project: 67 turbines of 15 MW each (1,005 MW) and a long-term mean wind speed of 10 m/s at hub height.

Gross energy: combining a Weibull wind distribution with the turbine power curve, a 15 MW machine on a 10 m/s site might reach a gross capacity factor of around 55–60%.
Wake losses: downstream turbines sit in slower, more turbulent air. Large arrays typically lose 8–15% to wakes, and neighbouring farms add “external” wakes on top.
Availability: wave height limits when crews can reach turbines, so offshore availability of 93–97% is common, against 97–99% onshore.
Electrical losses: array and export cables plus transformers lose 2–4%.

Net CF ≈ 0.58 (gross) × (1 − 0.11 wakes) × 0.95 availability × (1 − 0.03 electrical) Net CF ≈ 0.58 × 0.89 × 0.95 × 0.97 ≈ 0.476 Annual energy ≈ 1,005 MW × 8,760 h × 0.476 ≈ 4.19 TWh

For scale, about 4.2 TWh a year is close to Cyprus’s annual electricity consumption, or roughly half of Estonia’s (compare on our country profiles). Displacing gas-fired generation at roughly 350–400 g CO₂/kWh, it avoids about 1.5–1.7 million tonnes of CO₂ per year. You can redo that arithmetic for any grid with the electricity CO₂ calculator. For a single turbine at your own site, the wind turbine calculator runs the same Weibull and power-curve method.

What offshore wind costs

The fairest comparison is the levelised cost of electricity (LCOE): lifetime cost divided by lifetime output (see LCOE explained). In offshore wind, capital dominates:

Cost element	Approx. share of lifetime cost	Drivers
Turbines	30–40%	Steel and rare-earth prices, turbine OEM margins
Foundations and installation	20–30%	Water depth, soil, vessel day rates
Electrical (array, substation, export)	10–20%	Distance to shore, AC vs HVDC; sometimes paid by the grid operator
Operations and maintenance	20–30%	Distance, weather windows, crew transfer vessels or service operation vessels
Development, financing, decommissioning	remainder	Interest rates, consenting time

Shares vary widely by project and country. These are indicative ranges from published cost breakdowns (NREL ATB, IRENA).

Two points matter when you read headline prices:

Auction prices are not LCOE. Contract-for-difference strike prices bundle inflation indexation, grid arrangements and risk premia that differ from country to country. The UK and Germany treat transmission assets differently, so the same farm can look cheaper or dearer on paper.
Costs rose after 2021. IRENA tracked a long fall in offshore LCOE through the 2010s. Then higher interest rates, steel prices and supply-chain bottlenecks in 2022–2024 pushed costs back up, and several developers cancelled or renegotiated contracts in the US and UK. Offshore wind is so capital-intensive that a few percentage points on the cost of capital move LCOE a lot. Try it in the LCOE calculator: on a capital-heavy project, raising the discount rate from 5% to 8% typically lifts LCOE by roughly a quarter.

Floating wind still costs substantially more than fixed-bottom because volumes are small. NREL’s ATB projects large declines as arrays grow to hundreds of MW, but those are projections, not observed prices.

Strengths and limitations

Strengths

High capacity factors and steadier output than onshore wind or solar.
In northern Europe output peaks in winter, alongside demand and heating loads, which makes it a good partner for solar.
Large single sites close to coastal demand centres, with little competition for land.
Strong benefits for industry and port economies. The IEA’s 2019 outlook put the technical potential of near-shore offshore wind at many times global electricity demand.

Limitations

Variability still matters. Calm spells lasting several days across the whole North Sea do happen, so offshore wind needs backup capacity, interconnection, storage or demand flexibility like any variable source. Our guide to the power grid explains how operators balance it.
Grid connection. Bringing gigawatts ashore often means new onshore transmission lines, which can take longer to permit than the wind farm itself.
Supply chain. Only a handful of vessels can install the largest turbines, and port space for assembly is scarce.
Other ocean users. Shipping lanes, fishing grounds, military zones and radar all limit where farms can go.
Sensitivity to the cost of capital, as described above.

Where offshore wind is built

Through the early 2020s, installed offshore capacity has been concentrated in China, the UK, Germany, the Netherlands and Denmark, and GWEC’s Global Offshore Wind Report shows China taking the largest share of new additions in several recent years. Taiwan, South Korea, Japan, Vietnam, the US East Coast, Poland and the Baltic states are building their first large projects. Geography decides a lot here: shallow, windy continental shelves win. The North Sea has large areas under 50 m deep with mean winds near 10 m/s, close to ideal for fixed-bottom foundations. The US West Coast and Japan’s Pacific coast drop off quickly into deep water and depend on floating technology.

Compare how much of each country’s electricity comes from wind on the rankings pages, or open a country profile to see its generation mix over time.

Key takeaways

Offshore wind pays higher capital and maintenance costs for stronger, steadier wind: net capacity factors of 40–55% against 25–45% onshore.
New fixed-bottom projects mostly use 14–16 MW turbines on monopile or jacket foundations. Floating platforms open up deep coastlines but remain costly.
Wake losses, availability and cable reliability decide how much of the gross wind resource reaches the grid.
Almost all the cost is up-front, so interest rates matter as much to the price of offshore power as turbine technology does.

Calculators for this topic

Wind turbine energy & payback Pick a site and a turbine: we download a full year of hourly NASA wind at 50 m, shear it to your hub height, correct for air density and losses, and turn it into kWh, capacity factor, revenue and payback. Wind speed at height Convert a measured wind speed to any height from 0 to 200 m with both the Hellmann power law and the logarithmic wind profile, and see what the extra height does to available power. LCOE calculator Capex, fixed and variable O&M, fuel and heat rate, capacity factor, lifetime, WACC, construction time, degradation and carbon price → the levelized cost per MWh, broken down by component and compared across 11 technologies. Electricity kWh → CO₂ Converts any amount of electricity into CO₂ using the latest average grid carbon intensity of 210+ countries, and shows how the same kWh would score on cleaner and dirtier grids.

Frequently asked questions

Why build wind farms at sea when land is cheaper?

Wind over open water is stronger and steadier. The sea surface is smooth, and there are no hills, trees or buildings to slow the air down. Capacity factors rise from roughly 25–40% onshore to 40–55% offshore, and at sea you can install far larger turbines than roads and planning rules allow on land. Offshore sites can also sit close to coastal cities that have little room for onshore wind.

How much electricity does one offshore wind turbine produce?

A modern 15 MW offshore turbine at a 45–50% capacity factor produces roughly 59,000–66,000 MWh a year (15 MW × 8,760 h × 0.45–0.50). With a typical European household using 3,500–4,000 kWh, that covers the annual demand of about 15,000–18,000 homes.

What is the difference between fixed-bottom and floating offshore wind?

Fixed-bottom turbines stand on monopiles, jackets or gravity bases anchored to the seabed, and they pay off in water up to roughly 50–60 m deep. Floating turbines sit on buoyant platforms (spar, semi-submersible or tension-leg) held by mooring chains and anchors. That opens up deep-water coastlines such as Norway, Japan, California and the Mediterranean, but floating projects currently cost well above fixed-bottom ones.

How long do offshore wind turbines last?

Design life is typically 25–30 years, and many newer projects are permitted for 30–35 years. Foundations and export cables can outlast the turbines, so developers increasingly look at repowering existing sites with new nacelles and blades.

Is offshore wind more expensive than onshore wind?

Per MWh, usually yes. IRENA's cost reports show offshore wind's levelised cost falling steeply during the 2010s, yet it still sits above onshore wind in most markets. A higher capacity factor and a better fit with Europe's winter demand partly offset the higher capital and maintenance costs.

Does offshore wind harm marine life?

The main impacts are underwater noise during pile driving (managed with bubble curtains, soft starts and seasonal restrictions), collision risk for some seabirds, and habitat change. Foundations also become artificial reefs, and fishing bans inside some farms create de facto protected areas. Impacts depend on the site and are assessed in environmental impact studies before consent.

Sources & references

Figures in this guide are typical ranges drawn from the sources above; your own numbers depend on location, prices and equipment. Use the linked calculators for site-specific estimates.