Policy fragmentation, infrastructure constraints and the emerging shape of the future grid
Australia’s electricity system is undergoing its most significant transformation since the creation of the Australian Energy Market Operator (AEMO) and the National Electricity Market (NEM). Renewable generation supplied around 40% of Australia’s electricity in 2023, up from well under 20% a decade earlier, and more than 50 GW of proposed renewable and storage projects now sit in the grid-connection pipeline. Electrification trends, spanning electric vehicles, industrial heat, mining decarbonisation and rapidly expanding data-centre loads, are expected to drive further upward pressure on demand through the 2030s.
While Australia has the technology, resources and project pipeline to deliver a clean and competitive energy system, the transition is now shaped less by the availability of renewables and more by the sequencing of transmission, firming and policy stability. National emissions targets remain legislated, but political divergence has weakened certainty. Transmission projects face cost escalation and delays. System-strength limits and connection backlogs restrict where and when new generation can enter the system. Investors are responding with heightened risk premiums and shortened contracting appetites.
Together, these pressures create a new reality: Australia’s legislated targets will not be achieved unless infrastructure delivery accelerates materially and policy frameworks provide long-term confidence across jurisdictions.
1. National policy: legislated targets in an uncertain political landscape
Federal climate policy remains anchored in the Climate Change Act 2022, legislating a 43% emissions reduction by 2030 (from 2005 levels) and net-zero by 2050. These targets underpin AEMO’s Integrated System Plan (ISP) scenarios and shape assumptions about renewable build-out, coal retirements and transmission requirements. Complementing this framework, the Safeguard Mechanism now applies a default baseline-decline trajectory of 4.9% per year until 2030.
However, the durability of the framework is increasingly uncertain. The Liberal-National Coalition has withdrawn support for the legislated targets and indicated it would repeal the Climate Change Act and revise Safeguard obligations if elected. This introduces volatility into an environment where investors typically model assets over 20-40 year horizons. In practical terms, policy instability influences:
- long-term PPA terms
- discount rates and financing structures
- revenue-support mechanisms (such as the Capacity Investment Scheme, hydrogen programs and the Guarantee of Origin)
- the credibility of ISP pathways
- ACCU demand and emissions-baseline expectations
As a result, capital allocation is becoming more selective, with investors giving greater weight to state-based mechanisms and location-specific certainty.
This evolving political context provides the backdrop for a transition increasingly driven not by federal uniformity, but by state-level leadership.
2. State leadership: The engine practical progress
In the absence of sustained federal alignment, states and territories are increasingly becoming the primary drivers of Australia’s energy transition by setting targets, deploying infrastructure and creating investment frameworks, albeit with varied pace and design across jurisdictions.
- New South Wales (NSW) is advancing Renewable Energy Zones (REZs) supported by Long-Term Energy Service Agreements (LTESAs) for generation, long-duration storage and firming. The timing of the Eraring Power Station closure continues to influence regional planning and system-strength risk.
- Victoria (VIC) has legislated renewable-energy targets of 65% by 2030 and 95% by 2035, and is progressing offshore wind ambitions of 2 GW by 2032, 4 GW by 2035 and 9 GW by 2040. These ambitions sit alongside significant transmission constraints in the state’s north-west region.
- Queensland (QLD) continues to expand publicly-owned renewable and storage assets under its Energy and Jobs Plan, targeting 70% renewables by 2032. While earlier plans envisaged a 5 GW pumped-hydro scheme, current focus is on the 2 GW Borumba pumped-hydro project and an integrated storage-portfolio approach.
- South Australia (SA) regularly records 80-100% instantaneous renewable supply, supported by synchronous condensers and an evolving fleet of grid-forming batteries, providing operational insights for the national transition.
- Tasmania (TAS) is positioning itself as a future provider of firming and dispatchable capability, leveraging hydropower and wind. The pace of the Marinus Link development will determine how quickly Tasmania can support mainland reliability.
- Western Australia (WA), operating outside the NEM (in the SWIS), has committed to retiring all state-owned coal power stations by 2030 (with Collie scheduled for closure in 2027 and Muja D in 2029). Multi-gigawatt-scale storage will be required to replace coal-era capacity and support mining-electrification and critical-minerals processing loads.
Although this state diversity sustains national progress, it introduces fragmentation, particularly in planning, market design and procurement. This fragmentation becomes more consequential as infrastructure constraints tighten.
3. Transmission and system strength: The binding constraint shaping every other decision
Transmission is now widely recognised as the primary constraint on Australia’s decarbonisation trajectory. AEMO’s 2024 ISP identifies around A$16 billion in priority transmission projects and more than 10,000 km of new high-voltage lines as essential to unlocking high-resource zones and enabling coal retirements.
Every major line has faced material cost escalation or delay: the HumeLink project’s capital estimate has increased by more than 30%, the VNI West transmission corridor has been redesign-reviewed, and the Marinus Link has shifted to a staged delivery model following updated cost-benefit analysis. These impacts cascade: generation cannot reach load, firming cannot scale, and coal retirements become riskier.
Beyond transmission, system-strength shortfalls are increasingly influential. In regions such as NW Victoria, SW NSW and central Queensland, available hosting capacity is far below theoretical REZ envelopes. Connection-modelling backlogs are extending three to seven years, delaying financial close, reducing bankability and disrupting sequencing.
In practical terms: Australia is not constrained by renewable resource quality or technology maturity, it is constrained by a grid not designed for large-scale inverter-based generation, and which must evolve rapidly to maintain system security.
4. Coal closures and the escalating demand for firming capacity
Coal-retirement pathways remain major determinants of system security and investment sequencing. The Yallourn Power Station in Victoria is scheduled to close in 2028, the Loy Yang A plant in 2035, while the Eraring Power Station’s eventual closure remains critical to reliability outcomes in NSW. In Queensland, coal units face tightening economic and emissions pressure.
AEMO’s Electricity Statement of Opportunities (ESOO) identifies reliability gaps, including a risk of around 1.7 GW in Victoria during the Yallourn exit window unless new dispatchable resources are delivered ahead of schedule. These gaps are exacerbated when transmission lags or firming investments delay.
Meeting reliability obligations will require a coordinated mix of: short-duration and long-duration batteries; pumped hydro; flexible gas peakers; synchronous condensers; demand response and virtual power plants. South Australia and Victoria already demonstrate how synchronous condensers and grid-forming inverters maintain inertia and voltage stability. As coal exits the system, these technical services become as important as energy itself.
5. Technology mix: rapid growth, shifting economics and increasing integration challenges
Technology deployment trends reflect Australia’s resource strengths and infrastructure limits.
- Solar remains the fastest-growing technology. Utility-scale solar is supported by falling module prices and short construction timelines, while rooftop PV, now exceeding 25 GW across the NEM, is reshaping the demand curve, driving minimum-daytime demand to historic lows and requiring more sophisticated balancing solutions.
- Onshore wind is facing headwinds: global turbine-supply constraints, higher financing costs and community acceptance challenges have slowed final investment decisions. Transmission bottlenecks in high-resource areas such as NW Victoria and SW NSW further limit delivery.
- Offshore wind is emerging as a major new frontier, particularly in Victoria, with targets of 2 GW by 2032, 4 GW by 2035 and 9 GW by 2040. Its success will depend on coordinated port upgrades, transmission availability and long-term policy support.
- Battery energy storage systems (BESS) remain the fastest-growing asset class. A wave of two- to four-hour systems is entering construction, while policy and market signals are shifting towards six- to eight-hour (and longer) long-duration storage, consistent with modeling that anticipates deeper firming as coal retires. Grid-forming inverter capabilities are increasingly incorporated to provide system strength, fast frequency response and synthetic inertia.
Across all technologies, integration, not cost or availability, is the defining challenge.
6. Hydrogen: continued strategic priority with gradual commercialisation
Hydrogen development continues to attract policy support, with federal initiatives such as the Hydrogen Headstart and state-based hydrogen hubs in Gladstone, the Hunter and Kwinana. These programs support early commercial projects and the development of shared infrastructure.
However, large-scale deployment remains constrained by production costs, currently around A$5–6 per kilogram, limited long-term offtake agreements, evolving certification requirements and significant water and transmission needs. Compared with major international incentives (particularly under the U.S. Inflation Reduction Act), Australia faces competitiveness challenges for export-oriented hydrogen and ammonia.
Domestic hydrogen applications, in fertilisers, industrial heat and potential green-steel pathways, appear likely to scale earlier than export markets. Export-oriented hydrogen remains a longer-term prospect.
7. Environmental markets: increasingly central to project feasibility
Environmental-credit frameworks are increasingly central to both national climate policy and renewable-energy project development.
Demand for Australian Carbon Credit Units (ACCUs) is rising under the Safeguard Mechanism, with industrial compliance demand expected to reach multi-million-unit volumes annually by 2030. The Chubb Review strengthened integrity standards and methodology classifications, enhancing confidence in the market.
The Nature Repair Act 2023 introduces a national biodiversity-certificate framework, while state biodiversity offset schemes in NSW, Victoria and Queensland remain critical for planning approvals. Reef Credits support water-quality improvement in the Great Barrier Reef catchment, and natural-capital accounting pilots are emerging across several regions.
For project developers, these frameworks influence feasibility, cost, land-use arrangements and community-engagement strategy.
8. Investor sentiment: appetite remains Strong but more selective
Investment appetite for Australian clean-energy infrastructure remains strong. Capital continues to flow from domestic superannuation funds, global infrastructure investors and specialist renewable-energy funds.
However, the risk environment has shifted. Rising global interest rates and tighter financing conditions have raised the cost of capital versus 2021 assumptions. Investors now emphasise:
- policy durability
- connection certainty
- anticipated congestion and curtailment
- PPA availability and tenor
- merchant-risk exposure
- sequencing of coal retirements relative to firming
State-based procurement schemes such as capacity auctions, firming tenders and REZ underwriting, have become critical to bankability. Projects with strong locational fundamentals, predictable connection pathways and stable policy environments remain competitive; others face elevated risk premia.
The result is an investment environment where capital is available, but selectivity is rising sharply.
Conclusion: alignment, acceleration and the conditions for success
Australia’s energy transition is characterised by technological maturity, expanding project pipelines and sustained investor interest. Yet infrastructure constraints, political fragmentation and system-integration challenges increasingly shape what is feasible.
On current trajectories, Australia will struggle to meet its legislated 2030 emissions target without a significant uplift in transmission delivery, firming investment and system-strength remediation. Electrification pressures, coal retirements and connection backlogs underscore the need to accelerate delivery.
Success depends on whether policy, transmission, storage and state-federal coordination align to deliver at pace:
- Deliver priority transmission and system-strength upgrades
- Scale long-duration storage and flexible firming
- Maintain a durable national policy framework
- Reduce connection timeframes and improve modelling certainty
- Align state and federal mechanisms to provide consistent investment signals
If these conditions are met, Australia is well-positioned to build a clean, reliable and globally-competitive energy system. If not, the likely consequences are higher wholesale prices, slower emissions reductions, lower investor confidence and prolonged reliance on ageing thermal assets.
Next steps
Understanding the infrastructure and policy constraints shaping Australia’s grid is critical to making informed investment and strategic decisions. If you would like to know more about the opportunities and challenges ahead, please reach out to one of our team.
