Investment challenges in Australia's renewable energy sector: market risks perspective for legal and financial professionals

Australia's energy policy environment is dynamic, with frequent updates to federal and state targets, incentive schemes and planning frameworks. The Clean Energy Australia 2025 Report highlights significant new federal commitments, such as the Capacity Investment Scheme (CIS) and hydrogen production incentives^[2]. 

The sector has also witnessed abrupt policy reversals, such as the cancellation of Queensland's Pioneer-Burdekin Pumped Hydro Project^[3]. There is also potential for scrapping of Queensland's 2030 and 2035 renewable energy targets, following the LNP energy minister, David Janetzki announcement on 8 April this year of a review into the Energy (Renewable Transformation and Jobs) Act 2024 (Qld), which sets the State’s renewables target. When questioned on 'whether the government would amend or repeal the laws to change the targets, (he) did not answer either way' and stated 'investment is not driven by renewable targets. It is driven by certainty and stability.'^[4]

The regulatory framework governing renewable energy infrastructure is fragmented across federal, state, and local jurisdictions. The Draft Victorian Transmission Plan (VTP) Engagement and Feedback Report (December 2024) revealed industry concerns regarding the complexity and misalignment of approvals processes, which can delay investment decisions and undermine investor confidence. Interestingly, the Draft VTP released in May 2025 'does not replace statutory planning and environmental approval processes, including approvals and engagement requirements under the Planning and Environment Act 1987 Vic and Environment Effects Act 1978 Vic.'^[5] 

The introduction of new access regimes (ie Victoria’s proposed Grid Impact Assessment) and ongoing reforms to the National Electricity Rules (NER) further complicate the investment landscape. In its response to VicGrid’s Grid Impact Assessment Consultation Paper, the Clean Energy Investor Group wrote the following:

'The framework as currently proposed introduces significant uncertainty for investors. Without a transparent self-assessment tool, developers cannot gauge curtailment risks early, making financing difficult, especially for non-REZ projects. Unclear approval sequencing, potential duplication with AEMO processes, and increased regulatory burdens may delay projects and escalate costs. Additionally, the GIA ignores economic curtailment, such as MLF reductions, which could undermine financial viability for existing generators. The potential disincentive for greenfield projects is another key concern. Many investors diversify between REZ and non-REZ projects to manage risk, yet the GIA could limit flexibility and deter investment outside REZs.'^[6]

Securing and maintaining a social licence to operate is increasingly being recognised as a material risk. Community opposition, particularly in regional areas, can result in project delays, increased costs or even project cancellation. Feedback from the VTP consultation process underscores widespread concerns about land use, biodiversity, agricultural impacts and perceived inequities in the distribution of project benefits, for example:

• communities raised concerns about ‘some community members receiving undisclosed benefits while neighbouring properties were burdened with impacts’;
• ‘some people voiced strong concerns that hosting more renewable generation would significantly impact their sense of place and community including connection to Country because of transmission and generation infrastructure dominating the landscape’; and
• 'there were many concerns raised about natural hazard vulnerability, including bushfires and floods.'^[7]

The lack of effective engagement and benefit-sharing mechanisms has led to distrust and, in some cases, legal challenges. For example, the landmark Uren case in Victoria^[8] established that wind farm noise, even if compliant with planning permit conditions, can still be considered a nuisance if it substantially and unreasonably interferes with a neighbour’s enjoyment of their land, particularly impacting sleep. This means that wind farm operators need to go beyond simply meeting regulatory requirements and consider the impact of their operations on nearby residents. Early, meaningful engagement with local communities including Traditional Owners is essential to mitigate these risks and foster long-term project success. 

The rapid growth of renewable generation has outpaced the development of transmission infrastructure. The Australian Energy Market Operator’s (AEMO) Draft 2025 Electricity Network Options Report and the Clean Energy Australia 2025 Report both emphasise the critical need for 5,000 km of new transmission lines over the next decade. 

Delays in major projects such as the Western Renewables Link and VNI West have already impacted project timelines and increased uncertainty. AEMO announced that the $3.2 billion VNI West transmission project linking Victoria and NSW will only be completed in 2030, instead of 2028. According to Renew Economy, 'the delay adds to the growing problems around key transmission projects in Australia – the backbone of AEMO’s Integrated System Plan, which in turn underpins the federal government target of reaching 82 per cent renewables by 2030.'^[9] 

Grid congestion is also a growing concern, with AEMO projecting that up to 20% of renewable generation output could be curtailed by 2050^[10]. Energy Australia’s submission on AEMO’s Congestion Information Resource Guidelines (January 2025) calls for greater transparency and improved forecasting to enable investors to assess congestion risks and their impact on project revenues. For example, Energy Australia have requested more transparency around AEMO’s forecast methodologies to better understand the transition from the current grid constraints to a more stable grid. The lack of real-time data and clear links between constraints and market outcomes provided by AEMO complicates due diligence and financial modelling. 

Connection to the grid is subject to technical, regulatory and commercial hurdles. The process is often lengthy, with uncertainties around system strength remediation, connection costs and the allocation of network augmentation expenses. The Clean Energy Australia 2025 Report notes that project completion times from financial commitment to commissioning can vary significantly by state and technology, introducing further unpredictability into investment timelines.^[11] 

The transition to a renewables-dominated grid has increased price volatility in the National Electricity Market (NEM). While renewables have contributed to lower average prices, periods of high demand and low renewable output can result in price spikes. The Clean Energy Council’s modelling indicates that delays in renewable buildout could increase retail bills by 30–41% by 2030, highlighting the sensitivity of market outcomes to project delivery schedules.

The traditional model of long-term power purchase agreements (PPAs) is evolving. The Clean Energy Australia 2025 Report observes a polarisation in deal sizes, with large corporates dominating the PPA market and smaller buyers becoming less active. The emergence of the CIS and other government-backed schemes may crowd out merchant projects or alter the risk-return profile for investors. 

The risk of ‘merchant exposure’ – where projects rely on spot market revenues – remains an issue. However, alternatives to long-term offtake contracts such as investing in battery storage and emerging technologies like green hydrogen production as well as the role of Renewable Energy Certificates (RECs) which can be traded separately from the electricity generated, provide additional revenue streams for renewable energy projects and potentially reduce the need for long-term contracts. 

As more renewables connect to the grid, localised congestion and negative pricing events are becoming more frequent. These phenomena can erode project revenues and complicate financial planning. The lack of granular, forward-looking congestion data impedes the ability of investors to accurately price risk and structure hedging arrangements. 

The expansion of renewable energy zones (REZs) and associated transmission corridors has intensified competition for land, particularly in high-value agricultural regions. Submissions from the Victorian Farmers Federation and Dairy Australia highlight concerns about the loss of productive land, impacts on farm operations, and insufficient compensation mechanisms. The risk of legal disputes over land access, compensation, and environmental impacts is not insignificant.

Projects face increasing scrutiny regarding their impacts on biodiversity, endangered species, and cultural heritage sites. The need for comprehensive environmental assessments and the risk of legal challenges under state and federal environmental laws can delay or derail projects. The Clean Energy Australia 2025 Report and Victorian engagement feedback both underscore the importance of early, meaningful engagement with Traditional Owners and local communities. 

Frequent changes to planning, environmental and network access regulations create legal uncertainty. Investors and developers must navigate evolving requirements for project approvals, land access, and community benefit schemes. The risk of regulatory 'creep' and retrospective changes to project conditions is a material consideration for legal advisors. 

The growing number of stakeholders – including landholders, Traditional Owners, local councils and community groups – raises the likelihood of disputes. Parties must be prepared to address challenges related to land acquisition, compensation, environmental compliance, and contractual performance. 

The increasing complexity of offtake arrangements, grid connection agreements, and community benefit schemes requires a careful approach to risk allocation. The potential for curtailment, negative pricing and regulatory intervention must be addressed in contractual frameworks to protect investor interests.