Wind farm costs

The pie chart shows the contribution of each major cost element to levelised cost of energy (LCOE).

The cost is comprised of:

  • The capital expenditure (including development expenditure) (CAPEX)
  • The cost of finance for that CAPEX
  • The operational expenditure (OPEX), and
  • The decommissioning expenditure (DECEX)

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.

Purpose of LCOE

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:


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.

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.


Typical costs have been provided based on a floating offshore wind farm in the UK with the following parameters:

Year of FID2025
First operation date2028
Wind farm rating450MW
Turbine rating15MW
Water depth at site100m
Annual mean wind speed at 100 m height10m/s
Distance from offshore substation to shore60km
Distance from shore to onshore substation10km
Distance from wind farm to construction port60km
Distance from wind farm to O&M port60km
Floating substructure material and typeSteel semi-submersible
Mooring system3 point mooring with drag embedment anchors
Floating substructure manufacturing locationAsia
Floating substructure assembly locationEurope
Offshore substation foundation typeFixed jacket foundation

Detailed, bottom-up assessment of this project gives the following inputs to the LCOE equation:

  • Total CAPEX = £3,810,000 /MW (with spend spread realistically over the years leading up to first energy production)
  • Annual average OPEX = £71,000 /MW
  • Lifetime = 30 years
  • WACC = 7.0%
  • Net annual average energy production = 4,434 MWh/year/MW

As discussed above there can be a range in prices of any element, due to specific timing, local issues, exchange rates, competition and contracting conditions. 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.

Cost breakdown

A more detailed breakdown of typical costs is presented in the table below. Note that figures presented are rounded, hence totals may not equate to the sum of the sub-terms. As discussed above, there can be a large variation in costs between projects, so values stated should only be seen as indicative.

CategoryRounded costUnit
Development and project management150,000£/MW
Development and consenting services68,000£/MW
Environmental impact assessments10,000£/MW
Development activities and other consenting services58,000£/MW
Environmental surveys8,800£/MW
Offshore species and habitat surveys7,000£/MW
Onshore environmental surveys1,100£/MW
Human impact studies700£/MW
Resource and metocean assessment6,600£/MW
Geological and hydrographical surveys8,800£/MW
Geophysical surveys2,400£/MW
Geotechnical surveys4,700£/MW
Hydrographic surveys1,800£/MW
Engineering and consultancy8,800£/MW
Project management45,000£/MW
Wind turbine1,300,000£/MW
Balance of plant1,700,000£/MW
Array cable71,000£/MW
Export cable200,000£/MW
Cable accessories44,000£/MW
Cable protection17,000£/MW
Connectors and joints13,000£/MW
Floating substructure960,000£/MW
Secondary steel67,000£/MW
Corrosion protection48,000£/MW
Mooring systems180,000£/MW
Anchor systems38,000£/MW
Mooring lines and chains110,000£/MW
Topside connection6,700£/MW
Installation aids3,100£/MW
Offshore substation150,000£/MW
HVAC electrical system45,000£/MW
Auxiliary systems7,500£/MW
Topside structure70,000£/MW
Onshore substation82,000£/MW
Electrical system57,000£/MW
Buildings, access and security24,000£/MW
Installation and commissioning370,000£/MW
Inbound transport8,700£/MW
Offshore cable installation 140,000£/MW
Export cable installation46,000£/MW
Array cable installation74,000£/MW
Cable pull-in11,000£/MW
Electrical testing and termination9,700£/MW
Mooring and anchoring pre-installation68,000£/MW
Floating substructure - turbine assembly68,000£/MW
Heavy lifting and moving equipment28,000£/MW
Technician services4,700£/MW
Marshalling port30,000£/MW
Floating substructure - turbine installation53,000£/MW
Offshore substation installation24,000£/MW
Onshore export cable installation5,700£/MW
Offshore logistics2,200£/MW
Sea-based support1,400£/MW
Marine coordination450£/MW
Weather forecasting and metocean data150£/MW
Marine safety and rescue200£/MW
Operations and maintenance71,000£/MW/year
Operations control centre1,200£/MW/year
Onshore logistics1,200£/MW/year
Technical resource (onshore and offshore)6,000£/MW/year
Admin and support staff (onshore)7,200£/MW/year
Turbine maintenance31,000£/MW/year
Balance of plant maintenance13,000£/MW/year
Statutory inspections450£/MW/year
Offshore logistics and vessels2,200£/MW/year
O&M port400£/MW/year
Floating substructure - turbine decommissioning7,000£/MW
Mooring and anchoring decommissioning40,000£/MW
Cable decommissioning73,000£/MW
Substation decommissioning26,000£/MW
Contingency and insurance270,000£/MW

Guide to a floating offshore wind farm