Fixed-bottom vs floating offshore vs onshore wind: costs, capacity factors, and deployment trade-offs

Why It Matters

Wind energy supplied 11 percent of global electricity in 2025, and the International Energy Agency (IEA, 2025) projects that share must reach 25 percent by 2035 to keep the 1.5 °C pathway within reach. Yet the three main deployment configurations differ dramatically in cost, siting flexibility, and grid value. Onshore wind remains the cheapest form of new electricity generation in most markets, with global weighted-average levelised costs of $33 per megawatt-hour according to IRENA (2025). Fixed-bottom offshore wind commands higher prices but delivers stronger and steadier output closer to coastal demand centres. Floating offshore wind, still largely pre-commercial, promises to unlock 80 percent of global offshore wind resources located in waters deeper than 60 metres (GWEC, 2025). Understanding these trade-offs is essential for policymakers setting auction parameters, utilities planning capacity additions, and investors sizing risk-adjusted returns across a diversifying wind portfolio.

Key Concepts

Levelised cost of energy (LCOE). LCOE captures the all-in cost of generating one megawatt-hour over a project's lifetime, including capital expenditure, operations and maintenance, financing, and decommissioning. It enables direct comparison across technologies but does not reflect grid integration costs such as transmission upgrades or curtailment.

Capacity factor. The ratio of actual energy produced to the theoretical maximum if a turbine ran at full rated output continuously. Higher capacity factors improve revenue certainty and reduce the cost of energy. Onshore wind typically achieves 25 to 45 percent, fixed-bottom offshore 40 to 55 percent, and floating offshore 45 to 60 percent due to access to stronger, more consistent winds farther from shore (IRENA, 2025).

Foundation types. Onshore turbines sit on reinforced concrete gravity bases. Fixed-bottom offshore structures use monopiles (steel tubes driven into the seabed, suitable to ~40 m depth), jackets (lattice structures for 30 to 60 m), or gravity-based foundations. Floating platforms come in three primary designs: spar-buoys (deep-draught cylinders), semi-submersibles (pontoon structures), and tension-leg platforms (TLPs tethered to the seabed). Each floating concept trades stability, fabrication complexity, and water-depth suitability differently.

Grid connection and transmission. Onshore wind connects through buried cables to nearby substations, typically at costs of $50,000 to $150,000 per megawatt. Fixed-bottom offshore projects require subsea export cables and offshore substations, adding $300,000 to $700,000 per megawatt. Floating wind farms located 50 to 200 kilometres from shore face the highest connection costs, often exceeding $800,000 per megawatt, though dynamic cable technology and shared transmission infrastructure are beginning to reduce this premium (Carbon Trust, 2025).

Wake effects and array spacing. Offshore turbines benefit from reduced surface roughness compared to onshore sites, meaning less wind speed reduction from upstream obstacles. However, large offshore arrays (1 GW+) experience internal wake losses of 8 to 15 percent. Floating platforms offer the flexibility to adjust mooring positions, potentially reducing array losses by optimising spacing as wind conditions change seasonally.

Head-to-Head Comparison

Cost Analysis

Capital expenditure breakdown. Onshore wind projects in 2025 averaged $1,100 to $1,500 per kilowatt installed, with turbines representing 65 to 70 percent of total CAPEX (IRENA, 2025). Fixed-bottom offshore projects ranged from $2,800 to $4,500 per kilowatt, where foundations and installation account for roughly 35 percent of costs. Floating offshore demonstration projects have reported CAPEX of $4,500 to $7,000 per kilowatt, though the industry targets $2,500 to $3,500 per kilowatt at commercial scale by 2030 through standardisation and serial production (GWEC, 2025).

Operations and maintenance. Onshore O&M costs average $10 to $18 per megawatt-hour. Offshore O&M rises to $20 to $35 per megawatt-hour due to vessel mobilisation, weather windows, and subsea cable inspections. Floating wind O&M could be lower than fixed-bottom if platforms are tow-able to port for major repairs, avoiding expensive jack-up vessels. Equinor's Hywind Tampen project demonstrated this approach by towing a spar platform to a Norwegian fjord for turbine maintenance in 2025 (Equinor, 2025).

Financing and risk premiums. Onshore wind attracts debt at margins of 100 to 150 basis points above benchmark rates, reflecting mature technology risk. Fixed-bottom offshore spreads sit at 150 to 250 basis points. Floating projects currently face spreads of 300 to 500 basis points, with lenders requiring higher equity contributions and revenue certainty through contracts for difference (CfDs) or power purchase agreements. BloombergNEF (2025) estimates that reducing floating wind's cost of capital to fixed-bottom levels could cut LCOE by 15 to 20 percent.

Projected cost trajectories. IRENA (2025) projects onshore wind LCOE declining to $20 to $35 per megawatt-hour by 2030. Fixed-bottom offshore is expected to reach $45 to $75 per megawatt-hour as 15 MW+ turbines become standard and installation vessels scale up. Floating offshore targets $60 to $100 per megawatt-hour by 2030, contingent on reaching cumulative deployment of 5 to 10 gigawatts.

Use Cases and Best Fit

Onshore wind for cost-sensitive markets. Countries with abundant land and moderate wind resources, such as the United States, Brazil, India, and Australia, continue to deploy onshore wind as the backbone of decarbonisation. Iberdrola's 1,000 MW Vineyard Plains complex in Texas, commissioned in 2025, achieved a PPA price of $22 per megawatt-hour, among the lowest globally (Iberdrola, 2025).

Fixed-bottom offshore for high-demand coastlines. Northern Europe, the US East Coast, and East Asia rely on fixed-bottom offshore to deliver gigawatt-scale power near population centres where onshore sites are scarce. Vattenfall's Hollandse Kust Zuid project in the Netherlands (1.5 GW) operates subsidy-free, demonstrating that fixed-bottom offshore has reached commercial maturity in strong wind regimes (Vattenfall, 2024). In the United States, Vineyard Wind 1 (806 MW) off Massachusetts began delivering power to the grid in late 2024, marking the country's first utility-scale offshore wind farm.

Floating offshore for deep-water frontiers. Floating technology is critical for markets where continental shelves drop off steeply, including the US West Coast, Japan, South Korea, the Mediterranean, and the Celtic Sea. Equinor's Hywind Tampen (88 MW) in Norway powers offshore oil and gas platforms with floating wind, reducing their annual CO₂ emissions by roughly 200,000 tonnes (Equinor, 2025). France's first commercial-scale floating wind farm, the 30 MW Provence Grand Large project developed by EDF Renewables, began operations in the Mediterranean in 2025, validating semi-submersible technology in moderate-depth waters (EDF Renewables, 2025). The ScotWind leasing round allocated 15 GW of seabed rights in Scotland, with roughly one-third designated for floating technology, signalling significant pipeline growth.

Decision Framework

1. Assess wind resource and water depth. If the project area has water depths below 60 metres and mean wind speeds above 8.5 m/s, fixed-bottom offshore is the default choice. For depths beyond 60 metres, evaluate floating. For land-based sites with mean speeds above 6.5 m/s and willing host communities, onshore is optimal.

2. Evaluate grid proximity and congestion. Offshore wind located near coastal load centres may avoid the transmission bottlenecks that plague remote onshore sites. Factor in grid connection costs and curtailment risk when comparing total system cost.

3. Model capacity factor against LCOE. A floating wind farm at 55 percent capacity factor can deliver a lower cost per megawatt-hour than a fixed-bottom project at 42 percent, even if CAPEX is higher. Run full energy-yield models before comparing headline LCOE figures.

4. Stress-test supply chain readiness. Fixed-bottom offshore faces constrained installation vessel availability through 2028. Floating wind requires port infrastructure for platform assembly. Onshore depends on road logistics for increasingly large blades (80 m+). Identify bottlenecks early.

5. Quantify permitting and social licence risk. Onshore projects in densely populated regions face opposition timelines of three to seven years. Offshore permitting is complex but often faces less direct community resistance. Floating projects add novel technology review steps that can extend approval by 12 to 18 months.

6. Structure financing to match technology maturity. Use project finance with high leverage for onshore. Accept higher equity share and secure revenue contracts (CfDs, PPAs) for fixed-bottom offshore. For floating, consider blended finance structures with public co-investment or green bond instruments to reduce cost of capital.

Key Players

Established Leaders

• Vestas — World's largest wind turbine manufacturer by installed capacity; supplies onshore and offshore platforms globally
• Siemens Gamesa (SGRE) — Dominant offshore turbine supplier; 14 MW and 15 MW+ direct-drive platforms for fixed-bottom and floating
• Ørsted — Global leader in offshore wind development with 15+ GW operational portfolio
• Equinor — Pioneer in floating wind through the Hywind programme; operates Hywind Scotland and Hywind Tampen
• Iberdrola — Major onshore and offshore developer across Europe, the Americas, and Asia-Pacific

Emerging Startups

• Principle Power — Developer of the WindFloat semi-submersible floating platform, deployed commercially in Portugal and France
• Hexicon — Dual-turbine floating platform concept designed to reduce mooring and cable costs per megawatt
• Gazelle Wind Power — Developing a hybrid tension-leg platform for deep-water floating wind
• X1 Wind — Spanish startup testing a tension-leg, downwind floating platform concept (PivotBuoy) in the Canary Islands
• Touchwind — Dutch startup designing a single-point mooring, tilting turbine concept to reduce platform costs

Key Investors/Funders

• Copenhagen Infrastructure Partners (CIP) — Manages the world's largest fund dedicated to energy infrastructure, with major offshore wind allocations
• Green Investment Group (Macquarie) — Finances onshore and offshore wind projects globally, including floating wind demonstrations
• European Investment Bank (EIB) — Provides concessional finance for offshore wind projects under the InvestEU programme
• US Department of Energy (DOE) — Funds floating wind R&D and has set a target of 15 GW floating wind by 2035
• Crown Estate / Crown Estate Scotland — Manages seabed leasing for UK and Scottish offshore wind development

FAQ

Why is onshore wind so much cheaper than offshore? Onshore wind avoids the expensive foundations, subsea cables, offshore substations, and specialised installation vessels that drive up offshore costs. Onshore turbines are also smaller (4 to 7 MW versus 10 to 20 MW offshore), simplifying logistics. However, onshore capacity factors are lower, meaning more installed capacity is needed to generate the same annual energy output.

When will floating wind reach cost parity with fixed-bottom? Industry roadmaps from GWEC (2025) and IRENA (2025) project LCOE convergence in the early 2030s, contingent on cumulative global deployment reaching 5 to 10 gigawatts. Standardised platform designs, serial manufacturing, and dynamic cable maturation are the three largest cost reduction levers. BloombergNEF (2025) estimates floating LCOE could reach $60 to $80 per megawatt-hour by 2032 under optimistic assumptions.

How do capacity factors compare across regions? Capacity factors vary significantly by geography. North Sea fixed-bottom projects regularly achieve 50 to 55 percent. US East Coast projects target 45 to 50 percent. Onshore wind in the US Great Plains averages 40 to 45 percent, while European onshore sites average 25 to 35 percent due to lower wind speeds and turbulence. Floating wind in the Celtic Sea and US West Coast is modelled at 50 to 60 percent.

What are the main environmental concerns for each type? Onshore wind raises concerns about bird and bat collisions, visual impact, and noise. Fixed-bottom offshore impacts include underwater noise during pile driving, seabed disturbance, and collision risk for seabirds. Floating wind has a smaller seabed footprint (anchors rather than large foundations) but introduces mooring entanglement risk for marine mammals. All three configurations require environmental impact assessments and adaptive management plans.

How should investors think about technology risk in floating wind? Floating wind is at a similar maturity stage to fixed-bottom offshore in the early 2010s. The core technology works, as demonstrated by Hywind Scotland's eight years of operation with 54 percent capacity factor. Remaining risks centre on dynamic cable fatigue, mooring system longevity over 25-year design lives, and installation logistics at scale. Revenue certainty through government-backed CfDs significantly de-risks investment.

Sources

• IEA. (2025). World Energy Outlook 2025. International Energy Agency.
• IRENA. (2025). Renewable Power Generation Costs in 2024. International Renewable Energy Agency.
• GWEC. (2025). Global Offshore Wind Report 2025. Global Wind Energy Council.
• BloombergNEF. (2025). Global Wind Power Market Outlook 2025. BloombergNEF.
• Carbon Trust. (2025). Floating Offshore Wind: Cost Reduction Pathways to Commercialisation. Carbon Trust.
• Equinor. (2025). Hywind Tampen: Operational Performance Report 2024–2025. Equinor ASA.
• EDF Renewables. (2025). Provence Grand Large: First Power and Commissioning Update. EDF Renewables.
• Iberdrola. (2025). Vineyard Plains Wind Complex: Project Completion and Performance Summary. Iberdrola S.A.
• Vattenfall. (2024). Hollandse Kust Zuid: Subsidy-Free Offshore Wind in Operation. Vattenfall AB.