Powering the energy transition: bankability in the age of data infrastructure

Australia's energy investment landscape is entering a period of structural change. Against the backdrop of decarbonisation imperatives and the scheduled closure of ageing coal-fired power stations, a surge in electricity demand from hyperscale data centres is reshaping both the scale and nature of investment required. 

Together, these pressures create both extraordinary opportunity and acute challenge. The question for boards, in-house legal teams and project sponsors is whether projects can be structured in a way that attracts private capital in a system where market design, regulatory settings and infrastructure capacity are continuing to evolve in response to this accelerated demand. 

For the first time in decades, electricity consumption across the National Electricity Market (NEM) is rising sharply. The immediate catalyst is the rapid buildout of AI and cloud computing infrastructure, which has positioned Australia as one of the most attractive global destinations for data centre investment. Between 2023 and 2025, announced investment intentions exceeded $100 billion in aggregate, reflecting both the scale and immediacy of this demand shift. 

This trajectory is expected to accelerate. Present consumption of approximately 4 TWh per year – around 2% of NEM load – is projected by the Australian Energy Market Operator (AEMO) to increase to 21.4 TWh by 2034-35 as installed data centre capacity expands materially. Meeting that demand without placing upward pressure on household electricity prices will require substantial network augmentation, together with additional generation and firming capacity, including several gigawatts of new renewables and battery storage.

The significance of this shift lies not only in the scale of new demand, but in its nature. Data centres introduce continuous, high-intensity load profiles that require reliable, firmed and increasingly low-emissions supply, accelerating demand ahead of system and infrastructure capacity and reinforcing that the central challenge is not demand, but the ability to deliver bankable projects that address delivery, regulation and infrastructure constraints.

Project bankability: cost pressures, delivery and connection constraints

The scale of energy infrastructure investment required to meet decarbonisation targets, electrification demand and system reliability needs is unprecedented. Yet the capital expenditure required to deliver projects at that scale is actively undermining their commercial viability. Strong demand signals have not automatically translated into bankable energy projects. The constraint is not always the availability of capital per se, but rather the ability to structure projects whose economics survive the compounding effect of rising construction costs, extended delivery timelines and an increasingly uncertain connection environment.

Construction costs for renewable generation and storage have risen materially. Equipment bottlenecks — particularly for transformers, switchgear, inverters and synchronous condensers, all subject to global supply constraints — have driven unit costs upward at a pace that erodes project margins and challenges base-case financial models. Skilled labour shortages and the technical complexity of integrating new assets with legacy grid infrastructure compound these pressures. Geopolitical disruption has reinforced the trajectory. Supply chain pressures that emerged during the COVID-19 pandemic have been further compounded by renewed volatility in global energy and shipping markets, contributing to extended lead times, cost escalation and increased reluctance from contractors to accept fixed-price risk. The cumulative effect is that the CAPEX envelope for a given project has expanded well beyond the assumptions on which original investment cases were predicated, narrowing debt service coverage ratios, reducing equity returns and, in some cases, rendering projects uncommercial at prevailing offtake prices.

For project sponsors, this has direct implications for contracting strategy. Historically, financiers expressed a preference for single-package, fixed-price, date-certain EPC contracts with clear performance guarantees. As the cost premium demanded by contractors for single-point accountability has increased — itself a reflection of the same supply-side pressures — sophisticated developers have accepted disaggregation as a pragmatic response to preserve the economics of delivery. While bankability challenges remain under multi-contract structures — interface risk, program coordination complexity, and the absence of a single point of recourse — financiers have broadly adapted to this approach. However, disaggregation does not eliminate CAPEX pressure — it redistributes it across a more complex contractual matrix and introduces gap risks that must be managed through careful program design and sponsor capability. These challenges are compounded further by the increasing deployment of hybrid technologies, each with its own contracting considerations, performance metrics and residual risk allocation.

Connection and system integration risk has emerged as a particularly acute constraint on project viability. Queue congestion, uncertainty around marginal loss factors, and the cost and timing of network augmentation all directly affect whether a project can achieve the revenue profile needed to service its capital structure. The issue operates on both sides of the meter: beyond the grid constraints impacting connection timing and subsequent dispatch — including curtailment risk that directly diminishes revenue certainty for renewable capacity — the ability of new load requiring additional generation capacity to connect is itself being constrained. The significant increase in connection requests by data centres in Western Sydney illustrates the point. At the scale of investment now contemplated, these connection constraints do not merely delay projects; they fundamentally alter the CAPEX-to-revenue calculus on which bankability depends.

Revenue models: offtake, pricing and risk allocation

A key challenge for Australian energy projects is the mismatch between the long-term revenue certainty preferred by financiers, the tenor of offtake contracts available in the market and the desire for equity investors to benefit from the upside of merchant risk. This “tenor gap” remains a central challenge for project proponents seeking to convert strong demand signals into financeable projects. 

Battery energy storage systems in particular rely on multiple revenue streams – energy arbitrage, frequency control ancillary services, capacity payments, network support and tolling – several of which remain exposed to wholesale price volatility and merchant revenue risk as new capacity enters the system. While the market response to this challenge has been a diversification of offtake structures (virtual tolls, revenue floor and revenue sharing arrangements), they are often for shorter tenors than the physical tolling agreements, which were the dominant bankability model for utility-scale NEM battery contracts before 2023. The delivery of new and hybrid power plants has also produced increasingly complex offtake models. 

Government underwriting mechanisms have sought to address the issue posed by the tenor gap. Capacity Investment Scheme Agreements (CISAs), NSW Long Term Energy Service Agreements (LTESAs) and Firming Energy Revenue Mechanism Agreements (FERMAs) each provide forms of downside revenue protection that enhance debt serviceability and partially de-risk the revenue profile over the medium term. While these frameworks reflect an increasingly sophisticated allocation of risk between the public and private sectors, they may not always be sufficient, in isolation, to support a final investment decision. The protection they offer is typically limited in duration, scope or quantum.

The interdependence of energy projects and their offtake counterparties compounds the challenge. Co-location of load and generation – particularly data centres paired with batteries and renewables – is an emerging trend aligned with the global ‘build-your-own-power’ (BYOP) model, designed to mitigate grid constraints and accelerate project delivery. This drives project on project risk, which can be compounded given development timelines for generation and storage assets are typically longer than those for data centre facilities, creating a timing mismatch between load certainty and energy supply delivery. 

At the same time, the broader regulatory environment in which these mechanisms operate continues to evolve at pace, with new market mechanisms proposed, underwriting terms refined and connection frameworks updated across jurisdictions. Each iteration requires assumptions to be revisited, financial models updated and contractual arrangements adjusted – reinforcing the need for a more structural market design solution capable of bridging the tenor gap at scale.

While government is actively seeking to support the energy transition on one hand, proposed changes to taxation settings risk undermining that effort on the other. The proposed shift in effective capital gains tax rates (which can be from 0% to 30%) may have a chilling effect on international capital inflows into renewables and energy transition investments in Australia as foreign pension funds and sovereign wealth funds assess capital allocation on a global basis.

ESEM and evolving offtake models 

One consequential market design reform seeking to bridge the “tenor gap” is the proposed Electricity Services Entry Mechanism (ESEM), recommended by the Independent Expert Panel in its December 2025 final report on NEM wholesale market settings. Every NEM jurisdiction bar Queensland has endorsed the proposal in principle, with implementation pathways agreed in March 2026 and industry-led co-design of standardised contracts now underway.

Under the proposed model, a central buyer would award revenue-support contracts (structured as contracts for difference) covering years 8 to 15 of a project’s operation, then on-sell that contracted position into the wholesale market to improve liquidity. It is here that data centre operators may be required to purchase medium tenor contracts covering their energy requirements.

The market recognises the ESEM’s potential, yet it also illustrates a broader dynamic: projects that commenced development under the Capacity Investment Scheme (CIS) framework must now plan for a successor mechanism whose final design is still being co-developed. Each transition between frameworks requires market participants to absorb new contract forms, pricing methodologies and allocation mechanisms. The challenge is therefore one of timing and alignment, rather than appetite for reform, with investors seeking sufficient lead time and design certainty to support long-dated commitments.

Taken together, these developments point to a market that is actively evolving to address the revenue and contracting challenges underpinning project bankability. The critical task is not the absence of mechanisms, but the coordination of these emerging frameworks in a way that supports timely and efficient financial close.

Evolving market design: data centre and energy investment alignment

The Commonwealth has moved swiftly to articulate expectations for the development of data centres and AI infrastructure. In March 2026, the Department of Industry, Science and Resources released formal guidance built around five pillars: national interest, contribution to the energy transition, sustainable and efficient water use, workforce development, and research and innovation. The central requirement is that new facilities avoid placing upward pressure on energy prices while making a net positive contribution to decarbonisation. 

This guidance was reinforced at the Energy and Climate Change Ministerial Council in May 2026, where there is broad consensus from state and federal ministers that data centre operators should be obliged to fully offset their electricity consumption with new renewable generation or storage – solar, wind, or batteries. The Australian Energy Market Commission (AEMC) has been tasked with advising on implementation mechanisms, with design work underway. The ESEM, discussed below, may provide one route to translate data centre consumption obligations into investment in new renewable generation and storage capacity. There is also increasing focus on ensuring that the infrastructure required to connect new data centre load is appropriately funded by proponents, rather than being socialised across the broader consumer base.

On the technical side, reform of NEM connection standards is also progressing. The AEMC’s Package 1 reforms, targeting inverter-based resources, have already commenced, with further changes proposed through Package 2 to address large energy-intensive loads, including data centres and hydrogen electrolysers, through a tiered framework based on load size. 

Viewed together, the direction of reform is broadly constructive. Greater clarity around standards, system integration and market signals all serve long-term investor confidence. The practical challenge is that many of these frameworks are still being finalised, creating a transitional environment in which projects must progress alongside evolving regulatory settings and adapt to evolving market expectations from contract counterparties which are underpinned by this transitional landscape. For sponsors, managing tight financing windows, the cost and potential for delay of re-baselining technical and commercial due diligence is non-trivial.

In that context, regulatory reform is both an enabler and a sequencing challenge. While it is strengthening the long-term investment case for energy transition infrastructure, the immediate task for market participants is to navigate this period of design and implementation in a way that maintains momentum toward financial close.

From financial close to delivery: coordinating capital, policy and infrastructure

The current environment accentuates the interdependence of the workstreams required to reach financial close. Planning, offtake, EPC procurement and grid connection must advance in parallel. Disruption in any one of these areas – whether a connection delay, the loss of a key offtake counterparty, or a shift in market design – can cascade through the project, requiring renegotiation of commercial terms that are already finely balanced. 

This is where coordination introduces a whole additional level of complexity: project sponsors face fundamental strategic questions around their business case (including, increasingly, whether to orient development toward a data centre offtake) and must formulate their response in conditions where the answer may change before the project reaches a final investment decision. It is difficult to set a durable project strategy when the market is moving as fast as it is. Proponents will also need to grapple with inevitable skills shortages, the protection of supply chains in turbulent times, technological change between design and completion and social license issues. For boards and governance committees, this creates a heightened oversight challenge: the assumptions underpinning investment cases may shift materially between approval and drawdown.

While the policy reforms underway are individually well-directed and, in many cases, necessary, the next phase will depend on consolidation – a move from a period of intensive policy design to a more stable investment environment. This includes embedding ESEM in legislation, resolving the regulatory treatment of key technologies such as battery storage, advancing the AEMC's Package 2 connection framework, and progressing the practical application of renewable energy obligations for large-scale energy users.

Despite the challenges, the underlying investment thesis remains sound. Demand is structural, rather than cyclical, and the policy trajectory – while complex – is broadly supportive. As such, Australia’s energy transition continues to provide attractive opportunities for deployment of debt and equity capital by local and international infrastructure investors. Ultimately, the pace of the energy transition will be determined not by the availability of capital, but by the ability to integrate policy, infrastructure and capital structures into bankable projects at scale. 

The projects that progress will be those able to navigate cost pressures, revenue complexity and system constraints while maintaining attractive project economics, and translate that into structures capable of achieving financial close within acceptable risk parameters. These are areas where early legal and structuring input can materially reduce execution risk and strengthen the bankability case presented to financiers.