Published: September 22, 2026 | Updated: September 22, 2026
FLOATING WIND
An Irish engineering firm, Dublin Offshore Technology, said on 15 September that it had installed its Load Reduction Device in the mooring of a concrete floating platform off Maine, and that the device cuts peak wave-driven mooring loads by up to half. Take the claim at face value and a question follows immediately: how much of a floating project’s capital cost does a mooring line actually represent? On two independent cost stacks, one global and one built for Japan, the answer lands in the same place. Mooring hardware is a little over 5% of CAPEX. In Japan the hull it hangs from is 43%. The lever is real. It is attached to a small part of the machine.
👉 Floating Offshore Wind in Japan: Market Structure, Costs, and Policy
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BVG Associates’ 2024 reference case puts mooring systems at 411,000 $/MW against a total CAPEX of 7,682,000 $/MW, or 5.35%. DeepWind’s own Japan model, built on NEDO’s cost-evaluation formulation, puts mooring plus anchors at 5.12% for a semi-submersible. Two separately assembled bills of quantity land within a quarter of a percentage point of each other.
The floating substructure is 22.2% of CAPEX in the global reference case and 43.1% in the Japan model, because NEDO assumes a heavy steel semi-submersible. The denominator sits in the hull. A saving on mooring hardware is therefore diluted in Japan relative to the UK case, which is the opposite of how imported cost-reduction claims are usually read here.
BVG’s 2024 guide already lists load reduction devices as a standard mooring component, defines their function, and credits Dublin Offshore among the image sources for that section. What changed in September is narrower than the invention of a category: one of these devices has now been installed and instrumented in a floating wind mooring at sea.
What the 50% Claim Is Attached To
Dublin Offshore’s announcement describes a Load Reduction Device (LRD), a component spliced into a mooring line that behaves like a shock absorber, combining buoyancy and ballast to give the line a deliberately non-linear response to waves. The stated effect is to damp extreme tension spikes before they reach the anchor, which in turn allows lighter chain, smaller anchors, and less capable installation vessels. The company says this reduces peak dynamic loads by up to 50%.
Three qualifications belong on that sentence before any cost arithmetic is attempted. The 50% figure is the company’s own, and the release does not say whether it comes from tank testing, numerical modelling, or measurement; the same release states that live performance data is only now being collected. The DNV approval behind it is a prototype certificate issued against DNV-SE-0422 and DNV-ST-0119, reported in February 2026, and DNV’s own framing describes it as a verified basis for further development and project-specific implementation, which stops short of a clearance for commercial use. And the release names the platform and the sea area but never states the scale: public reporting describes the VolturnUS+ unit as a quarter-scale model of a 15 MW design, moored in about 21 metres of water off Castine in Penobscot Bay. None of that makes the milestone trivial. It does mean this is an instrumented demonstration, and that a commercial-scale proof is still ahead of it.
The Mooring Line Items, and How Big They Are
BVG Associates’ Guide to a Floating Offshore Wind Farm (2024) prices a reference project of 1 GW using 15 MW turbines in 100 metres of water, on a steel semi-submersible with six-point catenary mooring and drag embedment anchors, assuming a UK supply chain and real 2024 prices. Its detailed breakdown is unusually explicit about mooring, which makes it possible to see exactly what a load reduction device would and would not touch.
| Cost line (BVG 2024 reference case) | $/MW | Share of CAPEX |
|---|---|---|
| Mooring systems (total) | 411,000 | 5.35% |
| of which, mooring lines and chains | 227,000 | 2.95% |
| of which, jewellery (connectors, clump weights, LRDs, buoyancy) | 128,000 | 1.67% |
| of which, anchor systems | 45,000 | 0.59% |
| of which, topside connection and installation aids | 11,000 | 0.14% |
| Mooring and anchoring pre-installation | 199,000 | 2.59% |
| Mooring hardware and pre-installation combined | 610,000 | 7.94% |
| Floating substructure (for comparison) | 1,706,000 | 22.21% |
The sub-items sum exactly to the 411,000 headline, which is worth noting because the guide warns that its rounded figures do not always reconcile. Two things stand out. The anchors themselves, the component most often invoked when mooring loads are discussed, are only 45,000 $/MW, or 0.59% of CAPEX. And the devices in question sit inside the “jewellery” line at 128,000 $/MW, alongside connectors and buoyancy modules.
Japan Moves the Answer in the Unhelpful Direction
DeepWind’s viability simulator carries a separate Japanese cost structure, derived from NEDO’s cost-evaluation formulation rather than from European benchmarks. For a semi-submersible it apportions 3.155% of CAPEX to mooring and 1.968% to anchors, a combined 5.12%, against a base of 1,700,085 JPY/kW. For a spar the same two lines total 3.19%. These are DeepWind estimates, and they are procurement items: the model applies a seabed-condition factor to anchors, and carries no separate mooring-installation line, so the installation share cannot be isolated on the Japanese side.
That the two stacks agree on roughly 5% is the more reassuring finding. The more consequential one is where they disagree. The floating substructure is 22.21% of CAPEX in the BVG reference case and 43.09% in the Japan model, because NEDO treats the Japanese commercial baseline as a heavy steel semi-submersible, a reading consistent with MLIT’s own working documents describing a roughly 100 metre square, 35 metre deep hull produced on eight fabrication lines. Nearly half of Japanese floating CAPEX sits in the hull.
The consequence is arithmetic. If mooring hardware is about the same share in both stacks but the hull is twice as large a share in Japan, then any given saving on mooring is a smaller fraction of the Japanese total. A cost-reduction story imported from the North Sea generally reads as though it should travel well. On this particular line item, it travels slightly worse. Note that this is a comparison of composition, not of absolute cost; no exchange-rate conversion is applied, and the BVG figures should not be read as a Japanese price.
One further caution belongs on the comparison itself. The two stacks are not built identically. BVG carries contingency and insurance as a separate line worth 10.32% of CAPEX, while the Japanese structure leaves no residual category at all, a consequence of how NEDO’s buckets were mapped when the model was assembled. Part of the gap between the two hull shares is therefore a matter of definition as well as of physical weight, and the published figures do not allow the two effects to be separated. The direction of the difference is corroborated independently by MLIT’s description of the commercial hull. The exact multiple should not be read as a measured quantity.
👉 Floating Offshore Wind Cost Structure and LCOE
Load Reduction Devices Were Already in the Catalogue
The framing of the September announcement as a world first invites a check against what the industry already documented. BVG’s 2024 guide devotes a subsection to mooring “jewellery” and defines the category directly: LRDs are “components within the load path that modify the mooring stiffness response”, delivering engineered compliance so the mooring can be optimised. The same guide notes that in-line dampers and other load reducing devices were then “being developed” for taut and semi-taut systems, and the photograph illustrating those components credits Dublin Offshore by name among its sources.
So the component class was established, costed, and attributed to this supplier two years before the Maine campaign. What is genuinely new is narrower and more useful: a device of this type has been installed in a floating wind mooring offshore, hooked up with standard support vessels and no heavy-lift tonnage, and is now returning measured motion and tension data. For a category previously priced on modelling, an instrumented installation is the step that matters, and it is a different claim from proving commercial-scale cost reduction.
On these shares, halving peak mooring loads addresses a hardware bucket of roughly 5% of CAPEX, plus a pre-installation line of 2.6% in the global case that the Japanese model cannot separate. Even generous pass-through leaves the effect on total CAPEX in low single digits, which will not move a DSCR on its own. The more material channel for lenders may lie in fatigue and availability, since lower peak tension bears on mooring integrity management and therefore on the P90 assumptions behind debt sizing. That channel is currently unquantified: the company itself states that measured data is still being gathered.
What to Watch
Three things would change the reading. First, the provenance of the 50% figure, and whether the Maine instrumentation reproduces it at scale, outside a tank. Second, whether the certification path moves from prototype certificate toward project-specific qualification on a commercial mooring design, which is the step DNV explicitly flags as outstanding. Third, and most relevant to Japan, whether lighter peak loads widen the range of seabed conditions in which a given anchor type is viable. Japan’s designated and promising zones vary considerably in seabed geology, and the simulator already applies a seabed factor to anchors for exactly that reason.
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In Japan, mooring innovation is worth more for the sites it opens than for the money it saves.
The cost case for load reduction is sound and small. Two independently assembled cost stacks put mooring hardware near 5% of CAPEX, and Japan’s unusually hull-heavy structure dilutes rather than amplifies whatever is saved there. Anyone presenting mooring technology as a route to materially lower Japanese floating CAPEX is working against the composition of the bill.
The more interesting effect is on feasibility. Peak tension is what sizes an anchor and what determines whether a drag embedment anchor is acceptable or a suction pile becomes necessary. Reduce the peak and the set of seabed conditions a standard anchor can serve gets wider. In a market whose zones differ sharply in seabed geology, and where the simulator already adjusts anchor cost by seabed type, widening the envelope of workable sites is worth more than trimming a line item that was never large.
That also sets the standard the Maine data should be judged against. The useful output is not a confirmed percentage. It is whether measured tension histories let a designer specify lighter hardware in conditions that would otherwise have been ruled out, and whether a lender will accept that specification without a commercial-scale reference.
Related DeepWind Articles
- Floating Offshore Wind in Japan: Market Structure, Costs, and Policy Framework
- Floating Offshore Wind Platform Design: 117 Concepts Assessed, Only Three Proven
- Floating Offshore Wind Cost Structure and LCOE
- Floating Offshore Wind in Japan: The 20 kW to 2 MW Gap
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