Forty-two months. That’s roughly how long it took a mid-sized onshore wind farm in the New England Renewable Energy Zone to go from notice of intent to first synchronisation, according to the connection timeline its developer lodged with the relevant transmission network service provider. No offshore project in Australia has a comparable number yet, because none has reached that stage. That gap, more than turbine height or capacity factor, is the whole story of onshore versus offshore wind in this country right now.
I’ve spent a fair chunk of the past year driving between proposed REZ substations and feasibility licence areas off the Gippsland and Illawarra coasts, and the contrast is stark enough that it barely needs dressing up. Onshore wind is a mature, occasionally tedious planning exercise. Offshore wind is still mostly a conversation about who gets to apply for what, under a framework that’s barely out of its own teething phase.
The onshore case: boring is a feature #
Onshore wind in Australia has been commercially built for over two decades. The zoning pathways exist, the turbine supply chains exist, the grid connection application process, while slow and frequently litigated over curtailment – is at least a known quantity. A proponent lodges a development application against a state planning scheme, usually within a declared Renewable Energy Zone or an adjacent council area, negotiates a connection agreement with the relevant TNSP, and works through noise, shadow flicker and biodiversity conditions that, while sometimes contentious, are no longer novel to anyone involved.
That’s not to say onshore wind is easy. NSW’s coal exit has been running well ahead of its REZ transmission build, a mismatch I covered in detail looking at the NSW coal exit outrunning its REZ rollout, and the New England zone itself has had transmission sequencing issues that have pushed some connection dates out by a year or more, which I touched on when I went through where the New England build actually stands. But these are scheduling problems layered on top of a working system, not fundamental uncertainty about whether the system works at all.
Offshore’s problem isn’t the turbines, it’s everything around them #
The offshore sector doesn’t have that luxury. Australia’s offshore wind framework, the Offshore Electricity Infrastructure Act 2021 and the declared zones that have followed it, is still working through its first full licensing cycle. The Gippsland zone, the most advanced declared area, has feasibility licence holders doing the metocean and seabed surveys that onshore developers finished doing as a matter of course a decade ago. I wrote recently about how the Gippsland feasibility phase keeps grinding on rather than converting into anything resembling construction, and that’s not a knock on any one proponent. It’s the nature of a greenfield regulatory process trying to do in a few years what onshore planning had decades to settle.
The Illawarra zone shows what happens when that process meets real-world friction. The declared area there shrank materially after community and Defence-related concerns, and at least one proponent, BlueFloat Energy, stepped back from its position rather than push through a shrunken footprint that no longer penciled out, a retreat I went through properly in the piece on the Illawarra zone’s shrinking status. That’s the sort of thing that doesn’t happen to an onshore project with a signed connection agreement. It happens to a sector where the zone boundary itself is still negotiable.
Depth, foundations and the floating question #
There’s a technical layer underneath all this that gets flattened in most coverage: fixed-bottom and floating offshore wind are genuinely different engineering propositions, and Australia’s continental shelf mostly falls into deep water close to shore, which pushes a lot of the viable zones toward floating technology that’s barely out of pilot scale anywhere in the world. I went through the mechanics of that split in why depth decides between fixed-bottom and floating, and it’s worth repeating here because it changes the cost curve substantially. A fixed-bottom turbine off the UK or Dutch coast in 30 metres of water is a known construction method. A floating turbine off Gippsland in 100 metres plus is still, commercially, a bet.
Onshore turbines don’t carry that uncertainty. A 6 or 7 megawatt onshore machine on a tower footing is about as un-exotic as heavy infrastructure gets in 2026. The capacity factor is lower than a good offshore site, typically somewhere in the high-30s to low-40s per cent range on the best ridgelines versus offshore sites that can push past 45-50 per cent given the stronger and steadier wind resource over water. But a capacity factor advantage on paper means nothing if the project connecting to deliver it is still a decade from financial close.
What the grid connection test actually measures #
I wrote a longer piece a while back setting out the grid connection test as the honest way to compare these two technologies, and I’ll stand by the framing: forget headline turbine counts and announced gigawatts, and ask instead who has a signed connection agreement, a committed transmission upgrade, and a construction contractor mobilised on site. By that test, onshore wind in the declared REZs is years ahead, even accounting for the transmission delays AEMO has flagged repeatedly in its Integrated System Plan work, which I broke down in what the ISP actually says about the pace of REZ augmentation.
Offshore wind, meanwhile, doesn’t have a single Australian project that’s reached financial investment decision. Victoria’s push to revive a state-owned generation role through the reborn SEC has made offshore wind delivery one of its central tests, a point I examined in Victoria’s SEC revival meeting its offshore wind test, and even there the honest position is that the state’s ambition is running well ahead of anything resembling a connected megawatt.
Cost: the number nobody wants printed yet #
Onshore wind in Australia now lands, on a levelised cost basis, somewhere in a band that’s genuinely competitive with new-build gas peaking once firming is excluded, according to the CSIRO’s GenCost modelling published through the CSIRO and AEMO’s joint work each year. Offshore wind, by contrast, doesn’t yet have an Australian cost track record at all: every number quoted for local projects is an extrapolation from UK, European or Taiwanese projects, adjusted for distance from port, foundation depth and a supply chain that largely doesn’t exist here yet. The Clean Energy Finance Corporation and ARENA have both signalled interest in supporting early offshore movers, but neither has committed capital at the scale a single offshore project needs to reach financial close. That’s a meaningful difference from onshore wind, where the Capacity Investment Scheme: the mechanism I went through in how the Capacity Investment Scheme actually works – has already underwritten gigawatts of committed onshore capacity through competitive tender rounds run by the Department of Climate Change, Energy, the Environment and Water.
The case for patience, and the case against it #
Here’s my mildly unpopular view on this, and I’ll own it: offshore wind advocates are right that Australia eventually needs the technology, because some of the best remaining wind resource close to major demand centres, particularly Gippsland’s proximity to the Latrobe Valley transmission backbone left behind by brown coal retirements, is offshore. But the current framework is asking a greenfield regulatory system to produce bankable projects on a timeline that onshore wind took most of two decades to achieve, and I don’t think that gap closes by 2030 no matter how many feasibility licences get issued this year.
That’s not fatalism about offshore wind as a technology. It’s scepticism about the schedule being spruiked in government strategy documents versus the schedule the actual engineering and financing process is going to deliver. The Star of the South project, the most advanced in the Gippsland zone, has been through years of surveys and still hasn’t reached a construction decision, and that’s the furthest-advanced offshore project in the country.
Where this actually lands for the grid #
AEMO’s Integrated System Plan still models offshore wind as a meaningful contributor to the NEM’s generation mix by the mid-2030s, but even that document, which I’ve gone through section by section, treats offshore capacity as a later-decade addition behind onshore wind, firmed solar and storage. The near-term reliability task, the one AEMO and the AER are both focused on through the rest of this decade, is being carried by onshore wind, big batteries and the REZ transmission builds that are already under construction, however late some of them are running.
Offshore wind’s moment, if it comes, is a 2032-onwards story. Anyone promising gigawatts of offshore capacity connected before then is selling a render, not a connection agreement. I’ll take the turbine on the ridgeline with a signed agreement over the one in the brochure every time, and until Gippsland or Illawarra produces an actual financial investment decision, that’s where the comparison has to end.
On a clear morning a few weeks back I was down near Newcastle’s Bar Beach before the shift started, watching the swell come in past the breakwater, and it struck me that the water off that coast carries a wind resource nobody’s seriously queued up to licence yet. Which tells you something about how early this industry still is, even in the places everyone assumes are furthest along.
– Callum Hayes, Wind & Offshore Correspondent
Photo by Anna Jiménez Calaf on Unsplash