Australia does not have a shortage of renewable energy ambition, capital or projects. However, it increasingly has a shortage of projects that banks believe in. A shift now quietly reshaping the market.
For much of the past decade, the constraint was scale – building enough wind, solar and, more recently, storage to meet policy targets and replace retiring thermal generation.
Capital was available, policy support was clear, and lenders were willing to extend a degree of faith: that revenue assumptions would hold, that merchant exposure would be manageable, and that the energy transition’s trajectory was sufficiently certain to underwrite. The pathway to financial close was relatively well understood.
That world has changed. Today, the constraint is different, it is bankability in a system that has become more complex, more volatile and more difficult to underwrite.
The pipeline has never been larger. Development activity is deep, diverse and accelerating. But the proportion of that pipeline that can actually reach financial close, on acceptable terms, is narrowing.
And that distinction is becoming one of the defining features of Australia’s energy transition.
Repricing of risk
We have seen a clear shift in behaviour with banks now declining deals they would have financed previously. In many cases, these are projects that would have been considered financeable in a less complex, less volatile market. This is not a withdrawal, but a repricing.
Lenders are more active in diligence, more focused on downside scenarios, and far less willing to accept structures that rely on optimistic assumptions or post-FID optimisation to work.
Lenders are now pushing back on aggressive merchant assumptions, short or structurally weak offtake arrangements, unresolved grid and connection risk, and complexity that cannot be clearly allocated or appropriately mitigated.
The result is a widening gap between projects that are technically viable, and those that are actually financeable. That gap is no longer marginal, but structural. Sponsors increasingly undertake market soundings with technically viable projects that simply cannot clear credit under current assumptions, and require multiple rounds of restructuring before debt is achievable.
From a build problem to a structuring problem
What sits behind this shift is not a single issue, but a convergence of factors.
The system itself is changing. Higher renewable penetration is driving increased price volatility, more frequent negative pricing events, and greater dispersion between regional and nodal outcomes.
At the same time transmission constraints are becoming more binding, connection processes are more complex and less predictable, and construction risk has increased, driven by supply chain pressures and more fragmented delivery models. Layered on top of this is a shift in revenue structures.
The market is moving away from long-dated, fixed-price PPAs toward shorter tenor contracts, structured or synthetic offtake, and greater reliance on merchant exposure.
The combined effect is that projects are becoming harder to model, contract, and finance.
Revenue still determines outcomes
For all the change in policy and market design, the core principle of project finance remains intact. Risk doesn’t disappear but must be appropriately allocated, and debt is priced based on where it lands.
Physical tolling structures remain the benchmark because they place risk with the offtaker (dispatch risk, price exposure, and often volume risk). For lenders, that translates into predictable cashflows, clear downside protection, and strong debt capacity.
By contrast, offtake structures have evolved dramatically with the emergence of virtual PPAs, capacity-style arrangements, and synthetic products that leave materially more risk within the project (including shape risk between generation and contract profile, basis risk between nodal and regional pricing, and residual merchant exposure).
These structures are not a flaw in the market, but a response to it and have underpinned the growth of the BESS market. But that flexibility comes at a cost: materially tighter terms from lenders who must price the residual risk that sits within the project.
Counterparty strength and contract duration remain decisive. Long-dated agreements with investment-grade or government-backed entities continue to anchor the most efficient financings. Shorter-dated or weaker contracts do not. That hierarchy has not changed. It has simply become harder to satisfy in a more fragmented and volatile market.
CIS – a resilience tool, not a leverage story
The Capacity Investment Scheme has been critical in bringing forward investment and supporting projects that would otherwise struggle to proceed. But it is often misunderstood.
The floor/cap mechanism is not being used to maximise debt, but to support resilience. Lenders are not gearing against the floor, rather to underwrite downside cases, support credit approvals, and provide confidence in stress scenarios.
At the same time, the cap constrains upside, forcing greater discipline in how projects are priced and bid. The effect is subtle but important: the CIS is not making projects more aggressive but making them more defensible.
While the CIS has successfully created a significant pipeline of awarded projects, only a relatively small proportion of those projects have progressed to financial close.
Those that have, have been aggregated into portfolios or supported by sponsor balance sheets. This is not a failure of policy. It is a reflection of a deeper reality that policy support can bring projects to market, but it does not make them bankable on its own.
And where that gap between policy support and bankability is most visible is in the revenue assumptions that sit beneath the capital structure. Assumptions that, in some parts of the market, have already been tested.
Batteries have already shown what happens when value gets competed away
The battery sector offers a cautionary example of how quickly the economics underpinning a project class can shift. When Hornsdale entered the market, FCAS revenues were deep, volatile, and highly attractive. But that did not last.
As more batteries were deployed, FCAS compressed, stabilised, and became more competitive. The market worked as markets should, but it also removed the easy upside.
Today, battery economics are increasingly driven by energy arbitrage, volatility capture, and optimisation strategies (i.e., revenue sources that are inherently harder to contract, model, and underwrite).
This leads to a more fundamental shift: equity is increasingly underwriting trading performance, while debt remains anchored in contracted revenue.
That divergence is significant. A growing portion of project value sits outside traditional debt structures, and it introduces a question that lenders are already asking: what happens if volatility, the very thing batteries monetise, begins to compress as more capacity enters the system?
The same dynamic is now playing out on the supply side. As coal exits the system, new pockets of value are emerging. But as with FCAS, the durability of that value is far from guaranteed.
Coal closures are creating value but not everywhere, and not permanently
The retirement of thermal generation does create opportunity, but not evenly. The value released by exiting coal is increasingly locational. Projects positioned near load centres, within constrained parts of the network, or close to retiring assets can capture a premium through stronger realised pricing and more frequent high-value dispatch opportunities.
For lenders, location is becoming a credit variable. But as with FCAS, these advantages are unlikely to persist indefinitely as more capital targets the same nodes, early-mover premiums will compress.
What connects CIS support, battery revenue evolution, and coal closure opportunity is a single underlying truth: none of them, on their own, resolve the bankability challenge.
What ultimately determines whether a project reaches financial close is whether its structure can withstand the compression, volatility, and complexity that define this market.
Leverage is no longer something to maximise
This recalibration of what project finance requires extends beyond revenue structuring and risk allocation. It is most visible in capital structures.
Historically, the objective was often to maximise leverage and to push debt sizing to the limits of the model. Today, the question is different: what level of leverage actually gets the deal done and survives volatility? In practice, many transactions are now settling in the 60–70% gearing range, rather than pushing to the highest theoretical debt quantum.
This reflects a shift in priorities to execution certainty over optimisation, downside protection over upside stretch, and sponsor commitment over financial engineering. More equity is no longer just a buffer, it is often what allows a deal to clear credit in the first place.
Hybrids redistribute risk
Hybrid projects are often presented as the solution to many of the market’s challenges and in part, they are, as they can smooth generation profiles, reduce curtailment exposure, and provide access to multiple revenue streams.
But from a financing perspective, they do something more nuanced: they move risk around but do not eliminate it. A co-located wind-battery project, for example, may reduce curtailment on the generation side while introducing dispatch optimisation risk on the storage side.
The revenue streams interact, and under stress, they can correlate in ways that models built on independent assumptions do not capture. Lenders are increasingly asking how a hybrid performs not in its optimised case, but in its degraded case. What happens when wind output is low, arbitrage spreads are compressed, and the battery is cycling against a flat price curve?
Offtake structures for hybrids also remain immature. Few counterparties are willing to contract for the combined output on terms that give lenders the clarity they require, and fewer still on tenors that support efficient debt sizing.
Hybrids may strengthen the equity case by broadening the revenue opportunity set. But for lenders, the additional complexity does not simplify the fundamental question, but compounds it.
The more revenue streams a project has, the more ways those streams can underperform simultaneously, and the harder it becomes to construct a downside case that debt can be sized against with confidence. Complexity can create value, but it also makes that value harder to underwrite.
Projects are closing and what distinguishes them is instructive
For all the difficulty described above, projects are still reaching financial close. The deals that clear credit committees tend to share a recognisable pattern: contracted revenue from credible counterparties on tenors that cover (or nearly cover) the debt, conservative gearing that leaves meaningful equity at risk, construction packages with experienced contractors and appropriately allocated liquidated damages, and connection certainty or a credible pathway to it.
These are not necessarily the largest or most ambitious projects. They are the ones where risk has been clearly identified, priced, and allocated and where sponsors have demonstrated willingness to absorb residual uncertainty rather than pass it to lenders.
In many cases, they are also projects where early and disciplined engagement with financiers shaped the structure from the outset, rather than presenting a fully developed proposition and asking banks to react.
The lesson is not that the market is closed. It is that access to capital now requires more than a good site and a willing offtaker. It requires a structure that has been built around the financing, not bolted on after the fact.
Where this is heading
These pressures are unlikely to ease in the near term. If anything, they will intensify. More renewable capacity means more price cannibalisation. More storage means more compressed arbitrage margins. More projects competing for grid access means longer and less predictable connection timelines.
And the continued retirement of thermal generation, while creating opportunity, will also increase system volatility. A dynamic that creates revenue upside for well-positioned projects but introduces the same underwriting uncertainty that lenders are already finding difficult to price.
Over time, standardisation will help. As offtake structures mature, as hybrid contracting frameworks develop, and as lenders build institutional experience with newer asset classes, the friction cost of financing should reduce. But that is a multi-year process, not an immediate correction.
In the interim, the market will increasingly bifurcate: projects that are structured for bankability from inception, and those that are not. The role of advisers (legal, financial, and technical) in bridging that gap is becoming more, not less, critical. Structuring is no longer a downstream exercise. It is a competitive advantage that determines whether a project reaches financial close or remains indefinitely in development.
The bottom line
Australia doesn’t have a capital problem, but a credibility problem. We have a shortage of projects that can demonstrate financeable revenue, disciplined risk allocation, credible construction pathways, and capital structures that can withstand volatility.
The next phase of the energy transition will not be defined by who can develop the most projects, or who can assume the most optimistic scenarios, but by who can structure projects that capital actually trusts. Capital is still available but no longer forgiving.
James Guthrie is a partner at the law firm’s Energy, Resources and Infrastructure group.
This article is part of a series of articles and podcasts sponsored by Gilbert + Tobin. The first can be found here: Hybridisation of wind, solar and battery storage is no longer optional – it’s the new baseline
