Thirty metres of water is roughly where the argument starts. Below that depth, fixed-bottom offshore wind is proven, financeable and — in European terms — almost boring. Above it, floating wind is still earning its industrial credentials. Australia’s six declared offshore wind zones straddle both worlds, and the technology choice sitting inside each development application will shape whether any of this actually gets built by the early 2030s.
I’ve been watching the Star of the South process for a while now — Offshore Energy’s project in the Bass Strait sits over the declared Bass Strait Zone — and the seabed bathymetry question keeps surfacing in every planning document I read. The Bass Strait drops away fast once you leave coastal waters. That’s not a trivial detail; it’s the whole engineering problem in one sentence.
How fixed-bottom turbines actually work #
Fixed-bottom foundations come in a handful of variants: monopiles (a single steel tube driven into the seabed), jacket structures (latticed steel frames, like an oil-rig leg), and gravity-based concrete bases. Monopiles dominate globally because they’re cheap to fabricate and fast to install in the right conditions. The world’s offshore wind industry — Ørsted, Vattenfall, RWE, the lot — was essentially built on the monopile.
The practical ceiling is around 50 to 60 metres water depth, and even that upper end pushes the economics. Below about 30 metres you’re in comfortable territory. The turbine itself sits on top of a tower bolted or driven into the seabed, and the whole thing is as fixed as infrastructure gets. Foundations account for roughly a third of a fixed-bottom project’s capital cost, sometimes more depending on seabed conditions.
Australia’s declared offshore wind zones include areas well suited to fixed-bottom. The Gippsland Zone — where Star of the South has been working through Commonwealth assessment processes — has sections shallow enough for monopile or jacket construction. Same story for parts of the Hunter Zone off the NSW coast, which is relevant given the coal port transition being planned around Kooragang Island. The declared zones are designated under the Offshore Electricity Infrastructure Act 2021, which established the licensing framework for the first time, and AEMO’s Integrated System Plan has incorporated offshore wind into its generation scenarios accordingly.
The floating alternative — and why it matters for Australia #
Floating wind platforms attach to the seabed not by a rigid foundation but by mooring lines — chains, synthetic rope, or a mix — anchored to the seafloor. The turbine sits on a buoyant platform that can take several forms: a spar-buoy (a long cylinder weighted at the base), a semi-submersible (multiple columns connected by a frame), or a tension-leg platform (held taut by vertical tendons). Semi-submersibles are currently the most common in the small number of commercial floating projects operating worldwide.
The advantage is depth. Floating platforms can operate in 100, 200, even 1,000 metres of water. Given that something like 80 per cent of the world’s best offshore wind resources sit in water deeper than 60 metres, floating is the technology that unlocks most of the planet’s offshore potential. For Australia specifically, the continental shelf drops away sharply along much of the coastline. Parts of the proposed South Australian zone and the Western Australian zone face deep water relatively close to shore.
The catch is cost and maturity. Floating wind has commercial projects operating — Equinor’s Hywind Scotland, the Kincardine project off the Scottish coast — but the global installed capacity remains a fraction of fixed-bottom. Supply chains for floating platforms don’t yet exist at scale. The cost per megawatt-hour is substantially higher, though the gap has been narrowing as more projects reach final investment decision. I’d be careful with any developer who presents floating wind cost figures today as though they’re settled — they’re not. The range of estimates is wide and project-specific.
What the Australian declared zones actually require #
The six zones declared under the OEI Act framework — Gippsland, Hunter, Illawarra, Southern Ocean off South Australia, Perth/Bunbury, and the Pacific Ocean zone off NSW — aren’t uniform. Each has different depth profiles, different grid connection distances, and different seabed geology.
Gippsland is the furthest along in terms of feasibility work. Star of the South has logged years of met-ocean data collection. The shallower portions of that zone are fixed-bottom candidates; the deeper sections are not. The Hunter Zone, which sits off the coast near Newcastle — I grew up doing early-morning ocean swims at Bar Beach, so I take a particular interest in what gets proposed offshore — has reasonable depth profiles for fixed-bottom in the inner portions but deepens beyond practical monopile range as you move further out.
The Western Australian and Southern Ocean zones are a different story. The continental shelf is narrower in some of those areas, meaning floating foundations are likely the only viable option if turbines are to be sited where the wind resource is strongest. The same argument applies to deeper sections of the NSW Pacific zone. You can read more background on how the zone framework has evolved in our earlier piece on exploring offshore wind power in Australia.
Grid connection: the part that actually determines viability #
Here’s where I get sceptical of developer announcements, every time. Turbine counts and megawatt totals in a development application tell you what a developer wants to build. They don’t tell you whether the grid can absorb it or whether the transmission connection is financially viable.
Fixed-bottom projects at moderate distances from shore use high-voltage alternating current (HVAC) cable to connect to the grid. Once you extend past roughly 80 to 100 kilometres, or go to very high capacities, high-voltage direct current (HVDC) becomes necessary. Floating projects, which tend to be sited further offshore in deeper water, almost always require HVDC — which adds hundreds of millions of dollars in converter station and cable costs.
AEMO has flagged in its published ISP work that offshore wind’s contribution to the NEM depends heavily on transmission augmentation onshore as well. A floating wind farm feeding into a weak network node is not a viable project regardless of how good the wind resource is. The Capacity Investment Scheme, which you can read about in detail in our piece on the Capacity Investment Scheme explained, has been flagged as a potential mechanism to support offshore wind — but the scheme’s current design wasn’t built around the cost profile of floating foundations, and there are real questions about whether the revenue support on offer is sufficient to close a floating wind project’s financing. The issue of whether schemes like this end up picking winners rather than letting the market sort it out is one worth watching as offshore wind moves from declared zones to actual licences.
The grid firming question matters too. Offshore wind, like all wind, is variable. The comparison between storage options — batteries versus pumped hydro — is one we’ve covered separately in our piece on pumped hydro versus big batteries, and the same logic applies here.
The honest trade-off table #
Fixed-bottom: lower cost, proven supply chain, limited to shallower water, restricted to certain zones. Floating: accesses deeper sites and stronger resources, far less mature commercially, higher cost for now, longer timeline to scale. Neither is better in the abstract. The right answer depends entirely on the specific zone, depth profile, grid connection distance, and what the developer can actually finance.
One thing I’ll say plainly: the floating wind boosters who present it as an imminent Australian reality are getting ahead of themselves. The global supply chain for floating platforms — the yards, the mooring systems, the dynamic cables — is not yet sized for the ambitions sitting inside Australian development applications. That doesn’t mean it won’t get there. Equinor and others are investing seriously in floating at scale. But the timeline from pilot project to a multi-gigawatt Australian floating farm is measured in decades, not years, and the planning documents I’ve read don’t always reflect that honestly.
For the Australian energy transition more broadly, the context is set well in our earlier work on the rise of wind energy in Australia, which traces how onshore wind established the supply chain and policy precedents that offshore is now building on.
Where the technology is actually heading #
Turbine sizes keep growing. The latest fixed-bottom machines being installed in European waters are in the 14 to 16 megawatt range per unit. Vestas and Siemens Gamesa both have larger platforms in various stages of commercial deployment. Bigger turbines mean fewer foundations for the same total capacity, which helps the economics of both fixed-bottom and floating. For floating specifically, heavier nacelles create platform stability challenges that engineers are still working through at scale.
ARENA has funded early-stage feasibility and technology assessment work relevant to floating in Australian conditions — their published grant documentation is worth reading if you want specifics. The ARENA website tracks active funding rounds. Separately, AEMO’s ISP modelling — available on the AEMO website — includes offshore wind scenarios for the 2030s and 2040s, though the technology-specific assumptions in those scenarios are worth interrogating.
The depth map of each declared zone, the seabed geology, and the distance to a credible grid connection point will tell you more about whether a project is real than any turbine-count announcement. That’s the document I read first. Usually it’s buried three attachments deep in the development application, but it’s there.
— Callum Hayes, Wind & Offshore Correspondent
Photo by elaine alex on Unsplash