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For genuinely deep water, floating offshore wind is usually the technically suitable option. Its buoyant platform is held by mooring lines and anchors instead of a rigid foundation fixed to the seabed. Fixed-bottom wind remains the more mature, generally lower-risk and often lower-cost choice wherever water depth, seabed conditions, vessels and installation methods make a seabed foundation practical. Use roughly 60 metres as an initial screening boundary—not a universal cutoff—then compare the actual site’s geology, metocean conditions, grid route, ports, vessels, schedule and financing.
The short answer: depth favors floating, maturity favors fixed-bottom
Offshore wind developers are not choosing between two interchangeable products. They are choosing how the turbine will be supported, installed, connected, operated and eventually removed in a particular marine environment.
A fixed-bottom turbine transfers loads through a rigid foundation attached directly to the seabed. A floating turbine sits on a buoyant platform and is restrained by mooring lines connected to anchors. That distinction becomes decisive as water gets deeper: the steel, piling, installation equipment and seabed work required for a rigid foundation become more difficult, while a floating design can keep the turbine at the surface without a full-height seabed support structure.
NREL’s 2023 Annual Technology Baseline (ATB) uses water shallower than 60 metres for fixed-bottom resource classes and water deeper than 60 metres for floating classes. This is a useful first-pass convention, not a law of physics. The U.S. Department of Energy (DOE) says the economic crossover is becoming blurred: new fixed-bottom designs are reaching deeper water, and floating projects may be viable in water shallower than 60 metres.
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The practical conclusion is therefore conditional:
- Choose fixed-bottom first when the site is relatively shallow, the seabed can accept the foundation, and existing fabrication, installation and maintenance infrastructure is available.
- Evaluate floating seriously when depth, seabed geology or distance from shore makes a rigid foundation technically difficult or uneconomic.
- Do not choose from depth alone. Wind resource, waves, cable routes, ports, vessels, permitting, construction finance and the project schedule can move the crossover point.
What “deep water” means for offshore wind
The 60-metre screening convention
The most commonly cited dividing line is approximately 60 metres. NREL’s 2023 ATB places fixed-bottom resource classes below 60 metres and floating resource classes above 60 metres. DOE’s 2023 Offshore Wind Market Report uses the same threshold when describing the large share of U.S. offshore wind potential located in deeper water.
More than 65% of the U.S. offshore wind resource lies over water deeper than 60 metres, according to the DOE/NREL 2023 market report. DOE’s Floating Offshore Wind Shot describes the figure in broader terms, saying about two-thirds of U.S. offshore wind potential is too deep for today’s fixed-bottom foundations secured directly to the sea floor.
Those figures explain why floating technology matters strategically in the United States, but they do not mean every project beyond 60 metres must float. Depth changes foundation loads, pile length, jacket geometry, installation vessels and cable design; it does not independently determine the lowest-cost solution.
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Operating and announced depth examples
Most offshore wind projects operating through 2022 were in water no deeper than 45 metres. DOE/NREL’s 2023 report cites Seagreen as the deepest operating fixed-bottom example, with a jacket depth of 58.6 metres. The same report notes that announced fixed-bottom projects could exceed 70 metres. These examples show why 60 metres should be treated as a screening boundary rather than a hard technical limit.
| Reference point | What it indicates |
|---|---|
| NREL 2023 ATB | Fixed-bottom resource classes shallower than 60 m; floating resource classes deeper than 60 m |
| Projects operating through 2022 | Most were no deeper than 45 m |
| Seagreen | 58.6 m cited as the deepest operating fixed-bottom jacket example in DOE/NREL’s 2023 report |
| Announced fixed-bottom projects | Some could exceed 70 m, according to the same report |
The correct question is not “Does 60 metres automatically require floating?” It is “At this site, do the additional foundation and installation costs of fixed-bottom remain lower than the platform, mooring, cable, port and towing costs of floating?”
How fixed-bottom offshore wind works
A fixed-bottom turbine is supported by a rigid structure installed in the seabed. The foundation carries the turbine’s weight and resists wind, wave and current loads through steel or concrete members embedded in or resting on the seabed. The turbine, transition piece and electrical connection remain in a fixed position relative to the sea floor.
Common foundation families
- Monopiles: large steel piles driven or otherwise installed into the seabed. They are the dominant foundation type in the operating fleet.
- Jackets: lattice structures with several piles, suited to conditions where a single monopile becomes less practical.
- Pile caps, tripods and gravity-base foundations: other fixed-bottom arrangements used for particular depth, soil or installation requirements.
In DOE/NREL’s 2023 operating-capacity dataset, monopiles represented 60.2% of capacity, jackets 10.4%, pile caps 8.6%, tripods 1.8% and gravity-base foundations 1.4%. Substructure type was unreported for 17.6% of operating capacity. The figures describe the installed fleet, not a forecast of future market share.
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Why fixed-bottom is mature
Fixed-bottom wind benefits from a large operating base and a relatively established chain of foundation fabrication, heavy-lift installation, cable work, commissioning and maintenance. Export cables have a static interface at the turbine and array cables do not need to accommodate platform movement. Established methods also simplify engineering standards, permitting familiarity and bankability in many markets.
Its limits are practical rather than a single maximum depth. Developers must account for seabed soil and rock, scour around foundations, pile-driving or drilling constraints, vessel reach, weather windows, environmental restrictions and the availability of ports and installation vessels. As depth increases, foundations generally require more material and more demanding installation procedures, while the seabed investigation becomes more consequential.
How floating offshore wind works
In a floating project, the turbine is mounted on a buoyant substructure. The platform remains on the water surface and is held in position by mooring lines connected to anchors on the seabed. NREL’s cost framework models spar and semisubmersible platforms among the principal floating options.
Platform and mooring system
A floating system must provide buoyancy, stability and controlled motion while supporting the turbine and transmitting wind and wave loads into the mooring system. The anchors and lines keep the platform within its design position. Because the platform moves, the electrical system must accommodate motion, especially the dynamic section of the export or array cable.
Port assembly and tow-out
One potential advantage is that the turbine and platform can be assembled or commissioned in port and towed to the offshore site. This can reduce some offshore heavy-lift work and may allow certain maintenance activities to be performed by towing a unit back to port. It also creates requirements that fixed-bottom projects may not have: adequate water depth at the quay, high quay and laydown capacity, platform fabrication space, tow-out routes, anchor-handling vessels and suitable weather windows.
Why floating is still maturing
DOE describes floating substructures as moving from demonstration projects toward commercial scale. NREL’s 2024 ATB treats U.S. floating projects as nascent and presents floating cost projections from 2030 onward, when gigawatt-scale construction could become feasible. The technology therefore offers major access to deep-water resources but carries more development, supply-chain and execution uncertainty today.
Floating versus fixed-bottom: the decision factors
| Factor | Fixed-bottom | Floating |
|---|---|---|
| Best depth range | Usually shallower water; NREL’s screening class is below 60 m | Usually deeper water; NREL’s screening class is above 60 m |
| Seabed dependence | High: foundation must be installed in or on suitable seabed material | Lower for turbine support, but anchors and mooring lines still depend on seabed conditions |
| Commercial maturity | Commercially mature at gigawatt scale | Nascent in the U.S.; progressing from demonstrations toward commercial scale |
| Typical electrical interface | Static cable connection | Dynamic cable sections must accommodate platform motion |
| Installation approach | Foundation and turbine work performed offshore with specialized vessels | Potential for port assembly and tow-out, plus offshore anchoring and hook-up |
| Current cost certainty | Generally higher certainty because designs and supply chains are established | Greater uncertainty from platforms, moorings, dynamic cables, ports and towing |
| Access to deep-water wind | Becomes more challenging as depth and foundation demands rise | Primary technical advantage |
| Maintenance options | Established offshore access methods | May permit tow-to-port maintenance for some designs, but adds mooring, motion and dynamic-cable work |
Are floating turbines cheaper than fixed-bottom?
Generally not in the near term. Floating projects currently face higher costs and wider uncertainty because the platform, mooring system, dynamic cables, tow-out operation, ports and vessels are less standardized than the fixed-bottom chain. Floating also requires new fabrication and logistics capacity at the scale needed for commercial arrays.
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That does not make floating a poor investment. A floating project can access stronger wind farther from shore or avoid a fixed foundation that is exceptionally expensive at a deep or difficult site. The relevant comparison is the full project cost at the same location, including energy production, export-cable length, foundation or platform, installation, operations, financing and schedule risk.
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DOE’s Floating Offshore Wind Shot seeks a greater than 70% reduction in the cost of floating offshore wind energy, to $45 per megawatt-hour by 2035 for deep-water sites far from shore. This is a policy target. It is not an observed current price, a guaranteed project tariff or a statement that floating electricity already costs $45/MWh.
What can change the comparison
- A deep fixed-bottom design may require substantially more steel, longer piles, specialized installation vessels or difficult weather windows.
- A floating design may reduce offshore heavy-lift work but require a major port upgrade, large assembly area, new mooring fabrication and dynamic-cable capability.
- Floating may reach a higher-quality wind resource or a site with a shorter or more practical export route.
- Schedule delays and financing costs can outweigh a nominal equipment advantage, especially when a technology is still scaling.
NREL’s cost methodology varies estimates with wind resource, water depth and distances to infrastructure. That approach reflects the central point: there is no universal floating-versus-fixed price without a site, design, construction year and commercial assumptions.
Supply-chain and construction implications
Fixed-bottom supply chain
The fixed-bottom industry can draw on serial monopile fabrication, established jacket yards, heavy-lift vessels, cable-installation contractors and an extensive operating record. The 60.2% monopile share in DOE/NREL’s operating-capacity dataset illustrates how strongly the installed fleet has standardized around one foundation family, although local soil and depth conditions still determine the appropriate design.
At deeper sites, developers must check whether available vessels can handle the foundation dimensions and whether ports can receive, store and load the components. A technically suitable foundation is not practical if installation vessels, pile-driving equipment or weather windows are unavailable when the project needs them.
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Floating projects need platform fabrication, mooring-line and anchor production, dynamic-cable manufacturing, anchor-handling or installation vessels, deepwater quays, large laydown areas and a tow-out route. The turbine may be assembled in port, but that shifts more work to onshore industrial sites and can make port selection a defining project decision.
Commercial-scale deployment also depends on serial production. A single demonstration can use bespoke engineering and scarce equipment; a large array needs repeatable platforms, predictable inspection regimes, reliable towing procedures and a workforce trained for the complete mooring and cable system.
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Operations, maintenance and reliability
Fixed-bottom operations
Fixed-bottom turbines use established access strategies for vessels and technicians. The static foundation and cable interface simplify inspection compared with a moving platform, although corrosion, scour, foundation fatigue, cable burial and seabed conditions still require monitoring. Deeper water can make transfers and weather-dependent access more difficult.
Floating operations
Floating wind adds inspection and maintenance tasks for mooring lines, anchors, platform structure and dynamic cables. Platform motions influence turbine loads, cable fatigue and safe access procedures. A potential benefit is the ability to tow some units to a port for major maintenance rather than performing every intervention offshore. Whether that benefit is realized depends on the platform design, tow distance, port capacity, weather and the cost of disconnecting and reconnecting the unit.
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Operations planning must therefore compare the complete lifecycle, not just installation. A floating project with easier heavy maintenance may still have more frequent or complex inspections; a fixed-bottom project with familiar access may face higher vessel time at a remote, deep site.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Eight checks to make before selecting a substructure
1. Map depth and seabed geology
Start with a depth profile rather than a single average. Identify slopes, irregular seabed areas, soil layers, rock, scour risk and anchor conditions. A site that is mostly 55 metres deep but contains difficult geological zones may not have the same optimum as a uniform 65-metre site.
2. Characterize wind, waves and extremes
Compare mean wind speed, turbulence, wave climate, currents and extreme metocean conditions. Floating platforms must control motion in waves and transmit those loads through moorings and anchors. Fixed foundations must resist the corresponding loads through the seabed structure. The turbine rating and platform or foundation design must be evaluated together.
3. Trace the export cable and grid connection
Measure the distance to shore, landfall constraints, water-depth changes and grid-connection route. Floating projects need dynamic cable sections near the platform and may benefit from a different array layout. A longer export route can dominate cost and electrical losses even when the support structure is technically feasible.
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For fixed-bottom, check component storage, load-out, heavy-lift access and installation-vessel draft. For floating, also check quay load, water depth at the berth, platform fabrication space, laydown area, assembly sequence and tow-out clearance. Port upgrades can become a critical-path item.
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5. Confirm vessel availability
List the installation, cable, anchor-handling, towing and maintenance vessels required during each phase. Confirm their crane capacity, draft, availability windows and ability to work in the project’s metocean conditions. A foundation or platform selected without a realistic vessel plan is not an executable design.
6. Integrate turbine, platform, cable and array design
Turbine rating affects loads, spacing, wake losses, platform dimensions and cable selection. Floating layouts must account for mooring footprints and cable movement; fixed-bottom layouts must account for foundation positions, installation corridors and seabed constraints.
7. Model schedule, financing and policy support
Compare not only levelized energy cost but also construction duration, contingencies, interest during construction, technology risk and available policy support. Floating cost projections in NREL’s 2024 ATB begin from 2030 for U.S. gigawatt-scale feasibility, reflecting the expectation that commercial scale and supply-chain learning are still developing.
8. Resolve environmental, fisheries and navigation constraints
Both technologies require environmental assessment and engagement with fisheries, shipping and other marine users. Floating arrays add mooring corridors and dynamic-cable considerations; fixed-bottom arrays add seabed foundation and installation effects. Permitting timelines and mitigation requirements should be included in the economic comparison.
A practical screening workflow
- Classify the depth range. Use 60 metres as the initial screen, while preserving sites on either side for further analysis because the economic crossover is not fixed.
- Build two conceptual layouts. Prepare at least one credible fixed-bottom concept and one floating concept where depth or seabed conditions make both plausible.
- Test foundation and anchor conditions. Use geotechnical data to estimate pile, jacket, gravity-base or anchor requirements instead of relying on depth alone.
- Price the complete installation chain. Include foundations or platforms, moorings, anchors, cables, vessels, port work, tow-out, commissioning and decommissioning assumptions.
- Estimate energy and losses. Compare wind resource, wake effects, array spacing, electrical losses and availability for each concept.
- Stress-test schedule and weather. Model realistic installation seasons, vessel delays, port constraints and technology contingencies.
- Evaluate operations over the project life. Include inspections, access, cable and mooring replacement, tow-to-port options and remote-site logistics.
- Select the lowest-risk feasible concept. Choose the design that meets technical, environmental, schedule and financing requirements—not automatically the one with the lowest foundation cost.
When fixed-bottom remains the better choice
Fixed-bottom is usually the stronger option when water is shallow enough for a practical foundation, the seabed is well understood, installation vessels and ports are available, and the project benefits from mature suppliers and established financing assumptions. It is also attractive when a static cable interface and conventional offshore maintenance simplify execution.
A project near the 60-metre boundary should not switch to floating merely because a chart labels it “deep.” The Seagreen example at 58.6 metres and the possibility of fixed-bottom projects beyond 70 metres demonstrate that modern fixed foundations can extend the usable range. The decisive issue is whether the additional depth-related foundation and installation work remains competitive at that specific site.
When floating is the better choice
Floating becomes compelling when water depth or seabed conditions make a rigid foundation disproportionately difficult, when the best wind resource lies farther offshore, or when a floating supply chain can deliver a lower-risk construction plan than a deep fixed-bottom alternative. It is particularly important for regions where a large majority of the resource lies beyond practical fixed-foundation depths.
Floating should not be described as universally cheaper or automatically farther offshore. Its value is access: it expands the set of technically reachable sites. The project still needs a suitable port, tow-out route, mooring and anchor plan, dynamic-cable solution, maintenance strategy and financing case.
Common mistakes in technology selection
- Treating 60 metres as a mandatory cutoff. It is a screening convention used by NREL, not a physical rule.
- Comparing only foundation costs. Include cables, vessels, ports, installation, operations, financing and schedule risk.
- Calling the DOE $45/MWh figure a current price. It is a 2035 cost-reduction target for deep-water sites far from shore.
- Ignoring the seabed for floating projects. Anchors and mooring lines still require suitable geotechnical conditions.
- Ignoring motion for floating projects. Platform movement affects turbine loads, cable fatigue, mooring inspection and access.
- Assuming a port can support assembly. Quay load, berth depth, laydown area and tow-out geometry must be verified.
- Using a demonstration project as proof of bankability. Commercial arrays require serial production, repeatable installation and a credible long-term service plan.
Bottom line for deep-water projects
Floating offshore wind is usually the technically suitable technology once water is genuinely deep enough that a rigid seabed foundation becomes the project’s limiting factor. It opens the deeper resource that fixed-bottom systems cannot easily reach and can access strong winds farther from shore. Fixed-bottom remains the more mature and generally lower-risk choice where depth, geology, ports and vessels support a practical foundation.
Use 60 metres to decide which concepts deserve detailed study, not to make the final selection. The final answer comes from a site-specific comparison of seabed and metocean conditions, export route, port and vessel availability, turbine and cable design, environmental constraints, schedule and financing. Floating’s present cost premium and execution uncertainty may narrow as the industry scales, but DOE’s $45/MWh figure remains a 2035 policy target rather than a price developers can assume today.
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