Australia’s electricity system is undergoing its most consequential restructuring since the National Electricity Market (NEM) commenced operation in 1998. Coal-fired generators that supplied more than four fifths of east-coast electricity two decades ago now provide barely half of it, and the Australian Energy Market Operator (AEMO) anticipates that around 90 per cent of the remaining coal fleet will withdraw by 2035, with the final units gone by 2038 under its central planning scenario (AEMO 2024a). Over the same period, renewable generation has climbed towards 40 per cent of NEM output, underpinned by world-leading household solar uptake and a rapidly expanding pipeline of utility-scale wind, solar and storage. The direction of the transition is therefore no longer seriously contested in Australian policy debate; what remains deeply contested is its management.
This essay examines the tensions that define Australia’s renewable energy transition and argues that they are, at their core, a sequencing problem. The drivers of change, legal, economic and physical, are now firmly established, but the enabling apparatus of transmission, firming capacity and community consent lags behind the pace of coal closure. The essay first outlines the drivers of the transition, then analyses four tensions: grid reliability, the transmission build-out, regional social licence and the contested role of gas. It then evaluates the principal policy instruments before advancing an argued pathway founded on disciplined investment underwriting, social licence treated as core infrastructure policy, and a strictly bounded bridging role for gas.
Drivers of the Transition: Commitments, Closures and Costs
The first driver is legal and diplomatic. Australia ratified the Paris Agreement in 2016, and the Climate Change Act 2022 (Cth) converted its updated pledge into domestic law: a 43 per cent reduction in emissions below 2005 levels by 2030 and net zero by 2050. The Act also requires an annual climate change statement to Parliament, creating a standing accountability mechanism that previous policy regimes lacked (Department of Climate Change, Energy, the Environment and Water [DCCEEW] 2023). Because electricity is both the largest single source of national emissions and the cheapest sector to abate, the legislated targets translate almost mechanically into an expectation that the grid decarbonises fastest. The reformed Safeguard Mechanism reinforces this logic by requiring large industrial facilities to reduce baselines annually, increasing their demand for clean electricity.
The second driver is the physical condition of the coal fleet itself. The Liddell power station closed in 2023 after more than five decades of service, Yallourn is scheduled to exit in 2028, and Eraring, the country’s largest generator, has had its life extended only through a taxpayer-backed underwriting agreement with the New South Wales Government. Ageing units are increasingly prone to unplanned outages, and their owners face escalating maintenance costs precisely as their daytime revenues are eroded by low-cost solar generation (Wood & Dundas 2023). Closure decisions are consequently being driven as much by balance sheets as by climate policy.
The third driver is cost. The CSIRO GenCost series has found consistently that firmed renewables, wind and solar supported by storage and new transmission, are the lowest-cost form of new-build generation in Australia, even after integration costs are included (Graham, Hayward & Foster 2024). No financier will fund a new coal plant, and analysis of Australia’s utility-scale investment cycle shows capital flooding into renewables whenever policy settings are stable and retreating sharply whenever they are not (Simshauser & Gilmore 2022). The drivers of transition are thus aligned; the tensions examined below arise not from whether the system will change but from the pace and coordination of that change.
Tensions in the Transition
Grid reliability and the pace of coal exit
The most politically salient tension is reliability. AEMO’s reliability assessments have repeatedly identified forecast supply gaps emerging later this decade if committed generation, storage and transmission projects are delayed (AEMO 2024b). Coal exit is inherently lumpy: a single closure removes thousands of megawatts overnight, whereas the replacement portfolio of wind, solar, batteries and pumped hydro arrives in hundreds of increments, each with its own approval and connection timetable. The suspension of the entire NEM spot market in June 2022, amid coincident coal outages and fuel price shocks, demonstrated how thin the system’s buffers can become during a poorly sequenced exit.
The Eraring extension illustrates the resulting policy dilemma. Underwriting an ageing coal plant insures against near-term shortfalls, yet it also blunts the investment signal for the very firming assets that would make the extension unnecessary, and it delays emissions reductions. The Energy Security Board canvassed a formal capacity mechanism to manage this problem, but its proposal was contentious precisely because poorly designed capacity payments risk subsidising incumbent coal rather than new dispatchable capacity (Energy Security Board 2021). Reliability anxieties are legitimate, but the evidence suggests they are best answered by accelerating the firming pipeline, batteries, pumped hydro such as Snowy 2.0, and demand-side flexibility, rather than by serially extending coal.
Transmission and the build-out challenge
Reliability cannot be separated from transmission, which has become the binding physical constraint on the transition. AEMO’s Integrated System Plan identifies the need for roughly 10,000 kilometres of new and upgraded transmission by 2050 to connect Renewable Energy Zones (REZs) to demand centres (AEMO 2024a). Yet the flagship projects, HumeLink, VNI West and EnergyConnect among them, have experienced significant delays and cost escalation, reflecting global supply chain pressures, shortages of specialised labour and extended planning disputes. Generation without transmission is stranded capital, and investors increasingly price connection risk into every project.
The Commonwealth’s Rewiring the Nation program, which offers concessional finance of up to 20 billion dollars, lowers the cost of capital for these projects but does not, by itself, shorten approval timelines or resolve landholder opposition. Herein lies a genuine tension: streamlining environmental and planning assessment accelerates the build-out, but streamlining that is perceived as overriding local voices corrodes the consent on which the entire program depends. Transmission policy therefore cannot be treated as a purely technical exercise; it is simultaneously a social one.
Regional communities and social licence
The costs and disruptions of the transition concentrate in regional Australia, while its benefits, cheaper wholesale power and national emissions reductions, are diffuse. Research on Australian communities hosting wind, solar and transmission infrastructure finds that opposition is rarely rooted in climate scepticism; it stems instead from perceived procedural unfairness, inadequate consultation, concerns about agricultural land and place attachment (Colvin & Przybyszewski 2022). Where communities feel that projects are done to them rather than with them, resistance hardens and timelines blow out.
The Community Engagement Review commissioned by the Commonwealth reached a blunt conclusion: developer engagement has too often been perfunctory, benefit sharing inconsistent, and complaint handling opaque, and it recommended developer accreditation, clearer national standards and more meaningful landholder compensation (Dyer 2024). State governments have begun to respond, notably through per-kilometre strategic benefit payments to landholders hosting transmission in New South Wales and Victoria, and through requirements for First Nations participation in REZ planning. The lesson is that social licence is not a communications problem to be managed after routes are chosen; it is a precondition that shapes which routes, and which projects, are feasible at all.
The contested role of gas
Gas occupies the most ambiguous position in the transition. In AEMO’s planning, flexible gas-powered generation persists as a backstop technology: supplying a small and declining share of energy, but providing firm capacity for rare extended periods of low wind and solar output during winter peaks (AEMO 2024a). On this view, a modest gas fleet operating at low capacity factors is insurance that makes deep renewable penetration possible. The Commonwealth’s Future Gas Strategy, however, frames gas as necessary “through to 2050 and beyond”, language that critics read as an expansion signal rather than a managed decline (Department of Industry, Science and Resources [DISR] 2024). The Climate Council argues that new gas basins and long-lived export infrastructure are incompatible with the legislated net zero commitment and risk locking in both emissions and high fuel costs (Climate Council 2024).
These positions can be partially reconciled by distinguishing the capacity role from the energy role. Gas plants held in reserve for reliability, running infrequently, are defensible on system-security grounds; new upstream developments premised on growing domestic demand are not, because they bet against the transition succeeding. Methane leakage across the supply chain further weakens the climate case for expansion. The defensible policy position is a bounded bridge: retain and tightly regulate peaking capacity while refusing to underwrite demand growth.
Policy Instruments: Strengths and Gaps
Australia’s instrument mix has evolved through three phases. The Renewable Energy Target (RET) drove the first investment wave, and its large-scale component was met in 2020. Yet the RET’s fixed endpoint created a post-target cliff: with no successor scheme legislated, utility-scale commitments collapsed, confirming that policy discontinuity is itself a cost, raising the price of capital across the sector (Simshauser & Gilmore 2022). The decade of federal churn that followed taught investors to discount Australian policy promises, a legacy the current framework must still overcome.
The Capacity Investment Scheme (CIS) is the Commonwealth’s answer. It underwrites 32 gigawatts of new capacity by 2030, comprising 23 gigawatts of variable renewables and nine gigawatts of clean dispatchable capacity, through competitive tenders that provide revenue floors and ceilings. Early tender rounds have been heavily oversubscribed, indicating that the scheme has restored bankability. Its weaknesses are the mirror of its strengths: by socialising revenue risk, it shifts investment allocation from market signals to administrative judgment, and it prices nothing on the emissions side, leaving the NEM without any direct carbon signal.
Beneath the federal layer sits an assertive state tier. The NSW Electricity Infrastructure Roadmap established Long-Term Energy Service Agreements and coordinated REZ delivery (New South Wales Government 2020); Victoria has legislated renewable targets and revived the State Electricity Commission as a public investor; Queensland’s Energy and Jobs Plan couples renewable targets with publicly owned storage. This polycentric federalism has real virtues, ambition, redundancy and policy learning, but it also produces a patchwork: states compete for the same turbines, transformers and workers, and coordination with AEMO’s national plan is imperfect. The absence of an economy-wide carbon price means the entire architecture is second-best, substituting layered underwriting for a single coherent signal, an arrangement that works but at higher administrative and fiscal cost.
An Argued Pathway
An orderly transition requires aligning three clocks that currently run at different speeds: the closure clock set by coal economics, the build clock set by planning and supply chains, and the consent clock set by communities. Four commitments follow.
First, underwriting should be extended but disciplined. The CIS should continue beyond 2030 with tender criteria tied transparently to the system needs identified in the Integrated System Plan, so that administrative allocation tracks engineering reality rather than political geography. Its counterpart is structured closure: negotiated exit schedules with coal owners, with penalties for early departure and clear notice periods, so that closures become planning inputs rather than shocks (Wood & Dundas 2023). Over time, as firmed renewables dominate, underwriting should taper to restore market discipline.
Second, social licence must be funded and institutionalised as infrastructure in its own right. The Dyer recommendations, developer accreditation, national benefit-sharing standards and independent complaint handling, should be implemented in full rather than selectively (Dyer 2024). Regional planning should precede route selection, not follow it, and hosting payments should be standardised so that neighbouring landholders are not compensated at radically different rates. The Net Zero Economy Authority’s coordination of worker transition should draw explicitly on the Latrobe Valley experience after Hazelwood’s closure, which demonstrated that credible local institutions, funded before closure rather than after, materially improve regional outcomes.
Third, the gas bridge must be bounded. Peaking capacity that serves identified reliability needs should be retained under clear utilisation expectations and rigorous methane measurement, while public support for new supply premised on demand growth should be withheld. Each Integrated System Plan cycle should function as a sunset review, shrinking the gas envelope as storage duration lengthens.
Finally, the demand side deserves parity of policy attention. More than one in three Australian detached homes now hosts rooftop solar, and household batteries and virtual power plants can deliver firming capacity at the grid edge faster than any transmission line can be built (Climate Council 2024). Tariff reform, minimum standards for rental properties and support for apartment dwellers would broaden participation and address the emerging equity divide between energy asset owners and everyone else.
Conclusion
Australia’s renewable energy transition is no longer a question of direction but of choreography. Legislated targets, an ageing coal fleet and decisive cost advantages have settled the destination; the unresolved work lies in sequencing the exit of coal against the arrival of transmission, firming and community consent. The tensions examined in this essay, reliability, the build-out, regional social licence and gas, are real, but none justifies delay. Each instead defines a design requirement: disciplined and durable underwriting through an extended Capacity Investment Scheme, structured closure agreements, social licence treated as a funded precondition rather than an afterthought, a gas role confined to bounded insurance, and a demand side mobilised as genuine infrastructure. The RET era proved that stable policy unlocks Australian capital at remarkable speed; the decade that followed proved how expensive discontinuity is. If governments hold the current architecture steady, sharpen its coordination and honour the regional communities asked to host the new system, the NEM can complete the fastest decarbonisation of any comparable grid, affordably and with its social fabric intact.
References
Australian Energy Market Operator 2024a, 2024 Integrated System Plan for the National Electricity Market, AEMO, Melbourne.
Australian Energy Market Operator 2024b, 2024 Electricity Statement of Opportunities, AEMO, Melbourne.
Climate Council 2024, Seize the decade: how Australia can cut climate pollution and power ahead this decade, Climate Council of Australia, Sydney.
Colvin, RM & Przybyszewski, E 2022, ‘Local resistance to renewable energy and transmission infrastructure: social licence and procedural fairness in Australia’s energy transition’, Energy Research & Social Science, vol. 89, pp. 1-12.
Department of Climate Change, Energy, the Environment and Water 2023, Annual Climate Change Statement 2023, DCCEEW, Canberra.
Department of Industry, Science and Resources 2024, Future Gas Strategy, DISR, Canberra.
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Graham, P, Hayward, J & Foster, J 2024, GenCost 2023-24: final report, CSIRO, Canberra.
New South Wales Government 2020, NSW Electricity Infrastructure Roadmap: building an energy superpower, Department of Planning, Industry and Environment, Sydney.
Simshauser, P & Gilmore, J 2022, ‘Climate change policy discontinuity and Australia’s utility-scale renewable investment cycle’, Energy Policy, vol. 160, pp. 1-14.
Wood, T & Dundas, G 2023, Keeping the lights on: managing the exit of coal from the National Electricity Market, Grattan Institute, Melbourne.