These costs were calculated in 2023, they represent a snapshot of the industry at the time and have not been adjusted since to account for industry developments, commodity pricing or geopolitical events. Therefore, while the broad trends and assumptions used remain relevant, care should be taken if quoting costs directly.
This page contains information about wind farm costs (both as lifetime costs and a detailed cost breakdown) and about levelised cost of energy.
Costs
Site definitions
We have calculated a set of costs for a floating offshore wind farm, based on the following site conditions and assumptions:
| Parameter | Data | Unit |
|---|---|---|
| Year of FID | 2025 | |
| First operation date | 2028 | |
| Wind farm rating | 450 | MW |
| Turbine rating | 15 | MW |
| Water depth at site | 100 | m |
| Annual mean wind speed at 100 m height | 10 | m/s |
| Distance from offshore substation to shore | 60 | km |
| Distance from shore to onshore substation | 10 | km |
| Distance from wind farm to construction port | 60 | km |
| Distance from wind farm to O&M port | 60 | km |
| Floating substructure material and type | Steel semi-submersible | |
| Mooring system | 3 point mooring with drag embedment anchors | |
| Floating substructure manufacturing location | Asia | |
| Floating substructure assembly location | Europe | |
| Offshore substation foundation type | Fixed jacket foundation | |
| Ground conditions | Benign, allowing a piled substructure for the substation and drag embedment anchors for the floating offshore wind turbines |
Lifetime costs
The pie chart below shows the contribution of each major cost element to the total lifetime cost of a floating offshore wind farm based on the site conditions and assumptions in the above table.
Detailed cost breakdown
A more detailed breakdown of typical costs is presented in the table below.
- All costs are real 2021 prices.
- Figures presented are rounded, hence totals may not equate to the sum of the sub-terms.
- There can be a range in prices of any element between projects, due to specific timing, local issues, exchange rates, competition and contracting conditions, so values stated should only be seen as indicative.
- Prices for large components include delivery to nearest port, and supplier and warranty costs.
- Developer costs (including internal project and construction management, insurance, typically spent contingency and overheads) are included in the highest-level boxes but are not itemised.
| Category | Rounded cost | Unit |
|---|---|---|
| Development and project management | 150,000 | £/MW |
| Development and consenting services | 68,000 | £/MW |
| Environmental impact assessments | 10,000 | £/MW |
| Development activities and other consenting services | 58,000 | £/MW |
| Environmental surveys | 8,800 | £/MW |
| Offshore species and habitat surveys | 7,000 | £/MW |
| Onshore environmental surveys | 1,100 | £/MW |
| Human impact studies | 700 | £/MW |
| Resource and metocean assessment | 6,600 | £/MW |
| Structure | 3,300 | £/MW |
| Sensors | 2,700 | £/MW |
| Maintenance | 650 | £/MW |
| Geological and hydrographical surveys | 8,800 | £/MW |
| Geophysical surveys | 2,400 | £/MW |
| Geotechnical surveys | 4,700 | £/MW |
| Hydrographic surveys | 1,800 | £/MW |
| Engineering and consultancy | 8,800 | £/MW |
| Project management | 45,000 | £/MW |
| Wind turbine | 1,300,000 | £/MW |
| Nacelle | 760,000 | £/MW |
| Rotor | 370,000 | £/MW |
| Tower | 210,000 | £/MW |
| Balance of plant | 1,700,000 | £/MW |
| Array cable | 71,000 | £/MW |
| Export cable | 200,000 | £/MW |
| Cable accessories | 44,000 | £/MW |
| Interface | 8,900 | £/MW |
| Cable protection | 17,000 | £/MW |
| Buoyancy | 5,500 | £/MW |
| Connectors and joints | 13,000 | £/MW |
| Floating substructure | 960,000 | £/MW |
| Structure | 790,000 | £/MW |
| Secondary steel | 67,000 | £/MW |
| Systems | 58,000 | £/MW |
| Corrosion protection | 48,000 | £/MW |
| Mooring systems | 180,000 | £/MW |
| Anchor systems | 38,000 | £/MW |
| Mooring lines and chains | 110,000 | £/MW |
| Jewellery | 19,000 | £/MW |
| Topside connection | 6,700 | £/MW |
| Installation aids | 3,100 | £/MW |
| Offshore substation | 150,000 | £/MW |
| HVAC electrical system | 45,000 | £/MW |
| Auxiliary systems | 7,500 | £/MW |
| Topside structure | 70,000 | £/MW |
| Foundation | 27,000 | £/MW |
| Onshore substation | 82,000 | £/MW |
| Electrical system | 57,000 | £/MW |
| Buildings, access and security | 24,000 | £/MW |
| Installation and commissioning | 370,000 | £/MW |
| Inbound transport | 8,700 | £/MW |
| Offshore cable installation | 140,000 | £/MW |
| Export cable installation | 46,000 | £/MW |
| Array cable installation | 74,000 | £/MW |
| Cable pull-in | 11,000 | £/MW |
| Electrical testing and termination | 9,700 | £/MW |
| Mooring and anchoring pre-installation | 68,000 | £/MW |
| Floating substructure - turbine assembly | 68,000 | £/MW |
| Heavy lifting and moving equipment | 28,000 | £/MW |
| Technician services | 4,700 | £/MW |
| Marshalling port | 30,000 | £/MW |
| Other | 4,900 | £/MW |
| Floating substructure - turbine installation | 53,000 | £/MW |
| Offshore substation installation | 24,000 | £/MW |
| Onshore export cable installation | 5,700 | £/MW |
| Offshore logistics | 2,200 | £/MW |
| Sea-based support | 1,400 | £/MW |
| Marine coordination | 450 | £/MW |
| Weather forecasting and metocean data | 150 | £/MW |
| Marine safety and rescue | 200 | £/MW |
| Operations and maintenance | 71,000 | £/MW/year |
| Operations | 24,000 | £/MW/year |
| Operations control centre | 1,200 | £/MW/year |
| Training | 2,400 | £/MW/year |
| Onshore logistics | 1,200 | £/MW/year |
| Technical resource (onshore and offshore) | 6,000 | £/MW/year |
| Admin and support staff (onshore) | 7,200 | £/MW/year |
| Insurance | 6,000 | £/MW/year |
| Maintenance | 44,000 | £/MW/year |
| Turbine maintenance | 31,000 | £/MW/year |
| Balance of plant maintenance | 13,000 | £/MW/year |
| Statutory inspections | 450 | £/MW/year |
| Offshore logistics and vessels | 2,200 | £/MW/year |
| O&M port | 400 | £/MW/year |
| Decommissioning | 150,000 | £/MW |
| Floating substructure - turbine decommissioning | 7,000 | £/MW |
| Mooring and anchoring decommissioning | 40,000 | £/MW |
| Cable decommissioning | 73,000 | £/MW |
| Substation decommissioning | 26,000 | £/MW |
| Contingency and insurance | 270,000 | £/MW |
Levelised cost of energy
Purpose of LCOE
Levelised cost of energy (LCOE) is defined as the revenue required (from whatever source) to earn a rate of return on investment equal to the discount rate (also referred to as the weighted average cost of capital (WACC) over the life of the wind farm. Tax and inflation are not modelled. In other words, it is the lifetime average cost for the energy produced, quoted in today’s prices.
LCOE is used to evaluate and compare the cost of electricity production from different technologies and at different locations. It is a good way to compare the cost of a unit of energy (say in pounds per megawatt hour of electricity (£/MWh)) produced. LCOE does not consider costs relating to balancing supply and demand.
Lower LCOE benefits the electricity consumer (and tax payers if any subsidy is paid to generators), so decreasing LCOE is a key focus for the offshore wind industry.
LCOE combines costs and energy production into one metric, rather than comparing cost and energy production separately. It is used by technology players and industry enablers, but typically not by project investors who may be more interested in internal rate of return (IRR) or net present value (NPV) of an investment, taking into account more company-specific features like tax.
Subsidy for offshore wind farms in the UK is currently provided through UK Government Contract for Difference (CfD) auctions. CfD bid price is the revenue (£/MWh) sought by the developer for a 15 year duration. Revenue after this will come from the open market. The bidder’s prediction of future market prices and its approach to risk and competition will determine how it sets its CfD bid price. The CfD bid price therefore is not equal to LCOE, though there is a relationship between the two. In different markets, the scope of supply of the project developer and the terms of the competition vary, meaning that there is a different relationship between CfD bid price and LCOE.
Definition of LCOE
The technical definition of LCOE is:
Where:
It Investment expenditure in year t
Mt Operation, maintenance and service expenditure in year t
Et Energy generation in years t
r Discount rate (or WACC), and
n Lifetime of the project in years.
Drivers of LCOE
LCOE reduction can come from reduced costs, increased energy production, or changes in financing and lifetime of the project. Reduced cost can result from process or technology changes during the manufacturing, installation or operations phase. Increased energy production may result from technology or by reducing lost energy via better operational processes. Reducing project risk is the main way to affect financing cost.
The chart below shows BVGA’s LCOE forecast for floating offshore wind from 2027 (when the next pre-commercial floating offshore wind farms in the UK are expected to be commissioned) to 2035. LCOE varies between individual projects but overall LCOE is continuing to reduce significantly over time. The band shows the variance in LCOE that could occur for floating offshore wind projects driven by different site conditions, support mechanisms and local requirements that all impact LCOE. The variance is expected to tighten over time as the industry standardises across different technologies, and their associated manufacturing, installation and maintenance processes. The cost breakdown shown below reflects the higher commodity prices and altered market dynamics experienced by the industry post-2020. While some level of reduction in future commodity prices is expected, it is unclear on the timing or magnitude of this.
Some of the key drivers of cost are:
Site conditions
In waters less than 70 m deep, the mooring of some floating substructure types becomes more expensive because of the dynamic response to waves in these shallower waters.
Easy ground conditions, such as dense sand with low gradients on homogeneous or stiff clay containing few or no boulders, offer cost benefits because a range of anchoring solutions can be used and there is high confidence of long-term mooring system stability. Difficult conditions can add to cost significantly by driving a need for alternative designs and installation methods, such as suction or piled anchors.
Wind and wave conditions, tidal ranges and tidal flows also impact LCOE. Higher mean wind speeds increase cost but have a net benefit for LCOE due to increased energy production. In some markets (for example in Asia), typhoon winds drive design changes that add cost. Large tidal ranges can add to cost because turbines are required to keep a minimum clearance from sea level to blade tip at all times and so require more flexibility in the mooring system. Tides and waves make it harder to access turbines, especially for unplanned maintenance and repair activities in bad weather, adding cost and reducing energy production.
Likewise, projects further from shore take longer to access which adds cost, and increases downtime which reduces energy production. At about 60 km, it may be most cost effective to use a service operation vessel (SOV) spending weeks at sea, rather than crew transfer vessels (CTVs) travelling to and from port daily. Projects further from shore typically also have longer grid connections, adding to transmission CAPEX and OPEX.
Over time, there has been a move by governments from providing an agreed fixed-value market mechanism to supporting offshore wind to auctions where project developers bid a price for electricity they will generate. This change drives competition at project level which is passed down through the supply chain. Also, as the industry matures, what used to be highly differentiated areas of supply become commodities, driving further competition.
In some supply chain areas, such as turbine supply, the market is not big enough to have more than a handful of suppliers competing globally. This limits competition. In other areas, such as cables and foundations, transport costs are low enough to enable a geographically diverse supply base to bid for supply. In locations where ports have drafts suitable for floating substructure-turbine installation and can support the provision of O&M port services, distance to the wind farm is key which localises competition.
Vessel charter prices are a good example of the impact of pan-sector competition. Whether considering large floating vessels or common tugs, cyclic variations in regional wind and oil and gas activity can have a significant effect of price.
Supply chain evolution
Over time, the supply chain will mature, as it did in fixed offshore wind, with larger players taking on wider scopes and more risk. Wider scope within one supplier has enabled more cross-disciplinary collaboration to reduce cost. Also, larger volumes have facilitated investment in design, manufacturing and installation tooling suited to higher-volume process repetition. Large offshore wind farms may use 100 sets of identical (or similar) components, quite different from the more common practice in oil and gas of constructing one-offs.
Technology development
To date, the biggest driver over time of cost of energy reduction has been the development of new technology. The most visible sign of this has been the increase in turbine rating, increasing from 2 MW turbines 20 years ago to 15 MW turbines for projects reaching FID in 2025.
Larger turbines help drive down the per MW cost of floating substructures, installation and operation, whilst reaching higher into the wind field, so increasing energy production per MW installed. Larger turbines drive a need for technology development at a component level, as offshore wind turbines use the largest castings, bearings, generators and composite structures in series manufacture in any industry.
Technology development in floating substructure design and manufacture will have a major impact on LCOE. This cost element is specific to floating offshore wind and currently makes up a very large proportion of CAPEX. As the industry scales up and optimises this component, significant cost reductions will happen, just as they have for cost components in fixed offshore wind.
Industry incorporation of digital, autonomous, artificial intelligence and other applicable technologies is also enabling significant cost reduction, especially through improved wind farm operation and control.
Time
Considering the supply chain and technical factors described above, LCOE is projected to reduce over time.
The chart below shows BVGA’s LCOE forecast for floating offshore wind from 2027 (when the next pre-commercial floating offshore wind farms in the UK are expected to be commissioned) to 2035. LCOE varies between individual projects but overall LCOE is continuing to reduce significantly over time. The band shows the variance in LCOE that could occur for floating offshore wind projects driven by different site conditions, support mechanisms and local requirements that all impact LCOE. The variance is expected to tighten over time as the industry standardises across different technologies, and their associated manufacturing, installation and maintenance processes. The cost breakdown shown below reflects the higher commodity prices and altered market dynamics experienced by the industry post-2020. While some level of reduction in future commodity prices is expected, it is unclear on the timing or magnitude of this.
