Onshore wind is, by almost every metric, the most obvious answer to Australia’s energy transition. It is cheaper, faster to build, less complex and supported by a mature supply chain. If decarbonisation were simply a question of cost, the path forward would be straightforward: build more onshore wind.
But that is no longer the system we are operating in. Across the National Electricity Market, the constraints on onshore wind are no longer theoretical, they are binding. Social licence is deteriorating, transmission is delayed and congested, and correlation risk is emerging as renewable penetration increases. The marginal megawatt is no longer defined by resource quality, but by whether it can be connected, approved and delivered.
Recent developments in Victoria and Queensland make the point. Transmission projects such as VNI West have become contested infrastructure. Renewable Energy Zones are slower and more complex than anticipated. Projects are being reshaped, not around where the wind blows best, but around where the grid will accept them.
At the same time, the system is becoming more volatile. Periods of low wind are no longer isolated events; they are increasingly correlated across regions. As more capacity is added, these events matter more. What was once a project-level risk is now a system-level constraint.
None of this undermines the case for onshore wind. But it does change its role. Onshore wind remains essential – but it is no longer sufficient.
A market that is adapting, not improving
Recent market activity might suggest otherwise. There has been a noticeable uptick in onshore wind development and M&A. Capital is rotating back into the sector, and well-positioned projects are attracting strong interest.
This is not a sign that the system has become easier, rather a sign that investors have become more strategic.
Wind is increasingly being acquired as part of a portfolio, not as a standalone asset. For independent power producers and infrastructure funds, it provides diversification against solar, improves contract shape for corporate offtakes and reduces exposure to increasingly volatile merchant markets. In that sense, wind is as much a risk management tool as it is a generation technology.
Scarcity is also reshaping behaviour. Connection access, planning approvals and social licence are now critical path items. As a result, developers are willing to pay for projects that have already secured them. The premium is no longer for resource, it is for deliverability.
There is also a forward-looking element. With coal exits accelerating and transmission timelines uncertain, there is a growing recognition that build-out will be slower and more constrained than previously assumed. A project that can be delivered is becoming more valuable than one that is simply cheap on paper.
And increasingly, onshore wind is being used as a platform. Developers positioning for offshore wind are building domestic portfolios now, establishing market presence, operational capability and revenue base ahead of the next phase of the transition.
In short, activity is increasing, but underlying constraints remain.
Offshore wind: expensive, complex and increasingly misunderstood
This is where offshore wind matters.
On any conventional view, it is expensive. Capital costs are high, supply chains are tight and early projects will require significant policy support. At least for now, it is not a merchant technology.
But offshore wind is not competing with onshore wind. It is solving problems that onshore wind cannot.
It offers a different resource profile, stronger, more consistent winds, often generating at times that complement onshore output. It is located closer to load, particularly in Victoria and New South Wales, reducing reliance on long-distance transmission. And it provides scale, multi-gigawatt capacity in locations where that scale is otherwise difficult to achieve.
There is also a growing recognition that the cost comparison itself is framed too narrowly. While offshore wind remains more expensive on a project-level basis today, recent industry analysis points to rapid cost declines driven by turbine scale and materially higher capacity factors, often exceeding 55%, compared to 35–45% for onshore wind.
More importantly, these comparisons rarely capture system value. Offshore wind’s ability to generate more consistently, closer to load and at different times to onshore generation reduces the need for transmission investment, firming and curtailment. On a system-adjusted basis, it may prove competitive or lower cost, over time.
The mistake is to compare offshore wind to onshore wind on cost alone. The relevant question is what it delivers to the system. On that measure, offshore wind begins to look less like an alternative and more like a requirement.
The policy test: Victoria’s contract for difference
If offshore wind is necessary, it is not yet investable without support. That places significant weight on the design of Victoria’s upcoming offshore wind auction, expected to commence in August 2026.
At its core will be a contract-for-difference (CfD). But this cannot be a simple replication of earlier renewable support schemes.
To be effective, the CfD will need to deliver long-term revenue certainty at a level that reflects offshore cost structures and not onshore benchmarks. That implies higher strike prices, longer tenors and credible indexation.
More importantly, it will need to coexist with the market. Offshore projects will not rely solely on government-backed revenue. They will seek to stack that support with corporate PPAs, retailer offtakes and, potentially, merchant exposure. The CfD must therefore operate as a foundation, not a ceiling.
That points to a hybrid structure: partial volume coverage, flexibility to contract output privately and settlement mechanisms that do not disincentivise bilateral deals. In this model, the CfD underwrites bankability, while the market continues to provide optimisation and upside.
A critical issue will be how volume and basis risk are allocated between the CfD and the market. If the CfD is structured as a firm hedge, it risks misaligning with the variable production profile of offshore wind. If it is too flexible, it may not provide the certainty required for financing. The most workable approach is likely to sit somewhere in between, anchoring revenues while preserving sufficient flexibility for commercial optimisation.
The risk for policymakers is not that the CfD is insufficiently ambitious, but that it is insufficiently workable. Structures that do not accommodate revenue stacking or that create misalignment with actual production profiles risk stalling projects at financial close.
Bankability, not just policy
The more immediate challenge is not policy design in principle, but bankability in practice.
From a financing perspective, the key issue is not long-term economics, but near-term certainty, particularly during construction and early operations.
Offshore wind introduces a risk profile that is fundamentally different to onshore renewables, most notably in construction, interface and supply chain risk. For first-of-a-kind projects in Australia, lenders are unlikely to accept full exposure to these risks on a traditional project finance basis.
As a result, early projects are likely to require a higher proportion of equity, more conservative gearing and potentially alternative financing structures, whether through staged financing, corporate support during construction or quasi-regulated return profiles. In that sense, the CfD is necessary, but not sufficient: it underwrites revenue, but does not solve delivery risk.
The capital structure will also evolve over time. Early projects are likely to follow a two-phase model: risk capital to build, followed by refinancing into more traditional, lower-cost debt once construction and operational risks have been reduced. The success of the sector will depend on how efficiently that transition can occur.
It is also worth recognising that the first wave of offshore wind projects in Australia is unlikely to be economically efficient. That is not a failure of the model, but a feature of market entry. Early projects will carry higher costs, higher risk premiums and more conservative financing structures. The objective is not optimisation, but establishment.
Developers progressing offshore wind projects in Australia will increasingly need to structure projects on the basis that government support will be partial, not complete. Private offtake will be required early, and capital structures will need to accommodate higher equity and staged financing. In practical terms, that shifts focus from optimising levelised cost to optimising bankability.
Projects that assume full revenue underwriting from government, or that rely on traditional fully contracted project finance structures from day one, are unlikely to progress.
In practice, the central question is not whether offshore wind is viable, but how risk is allocated across the contractual chain from seabed licence through to offtake and financing. Misalignment at any point in that chain will ultimately sit with sponsors and lenders and will be priced accordingly.
From optional to inevitable
The energy transition is often framed as a cost optimisation problem. Increasingly, it is a constraint management problem.
Onshore wind remains the lowest-cost source of new generation. But it is being delivered into a system defined by transmission bottlenecks, social licence challenges and growing volatility.
Offshore wind does not solve those problems cheaply. But it does solve them. The question is no longer whether offshore wind stacks up on a narrow economic basis. It is whether the system can function without it.
Increasingly, the answer is no.