The Draft 2026 Integrated System Plan (ISP) is the most materially updated planning document AEMO has produced since the 2020 edition. It keeps the overarching structure of the transition intact, renewables as the primary energy source, firmed by storage and supported by flexible gas and smarter networks but shifts almost everything underneath. Costs, demand drivers, sequencing, land availability, expected coal behaviour, financing assumptions, and the value of different technologies all move in ways that make this plan very different from the 2024 ISP.

The document reads less like a projection of the desired future and more like a system model trying to reconcile rising costs, slower development in some areas, increased complexity in others, and a different mix of demand-side drivers. It is still an optimisation exercise, but the constraints are tighter and more explicitly modelled. This is the first ISP where the modelling language clearly reflects the physical, economic, and social frictions shaping the transition.

AEMO continues to find that renewable energy, connected through expanded transmission, firmed with storage, and backed by gas is the lowest-cost path to 2050. But that pathway is no longer framed around unconstrained buildout or optimistic project timing. Instead, the Draft 2026 ISP embeds a realism around cost escalation, sequencing limitations, community impact, and the different risk profiles of the assets that the transition depends on.

The following sections outline the major shifts in the Draft 2026 ISP and the implications for the NEM, investors, developers, network planners, and policy makers.

Transmission as a constrained enabler

Transmission remains the backbone of the future NEM, but the Draft ISP signals a more cautious and selective approach to network expansion. Updated cost data shows real transmission capex has increased by up to 100 percent in some regions. At the same time, the regulated WACC has fallen from around 7 percent to 3 percent, reflecting the low-risk, revenue-certain nature of network assets.

These two movements work in opposite directions: higher project costs reduce the economic case for marginal lines, while a lower regulated WACC expands the envelope of what is financially viable. The result is a reduced, more targeted network footprint. The optimal development path (ODP) now includes roughly 6,000 kilometres of new transmission by 2050, compared with about 7,600 kilometres in the 2024 ISP and close to 10,000 kilometres when all scenario options were considered previously.

Several factors contribute to this shift. The higher capital costs of transmission push the model towards more strategically located storage, which can address local reliability and reduce congestion without the need for long-distance lines. Updated wind traces with better geographic diversity reduce the need for new interconnection to access diversity benefits. Some 2024 ISP projects are now committed or anticipated, removing them from the optimisation set and reducing the amount of “new” transmission still required.

A significant methodological update is the incorporation of land-use complexity and social licence into route selection and cost estimation. The ISP now explicitly models community sentiment, land-use constraints, and the probability of infrastructure encountering contested areas. This changes the relative attractiveness of certain lines and creates a more realistic representation of where transmission can be built.

The broader implication is that transmission remains essential, but its role evolves. The Draft ISP reflects a more measured strategy: fewer total kilometres, but more targeted corridors, more storage complementing the network, and a recognition that the system cannot assume that every desirable line can be delivered on ideal timelines.

Coal behaving differently rather than disappearing early

One of the most notable shifts in the Draft 2026 ISP is the extension of coal’s modeled presence in the system. The final exit of coal is pushed from 2038 (in the 2024 ISP) to 2049. This does not reflect a revival of baseload coal generation; instead, it reflects how coal is expected to operate in a high-renewables system.

Coal’s role becomes almost entirely flexibility-driven. Units are expected to run at lower capacity factors, cycle off during extended periods of high solar production, and provide system strength and inertia services when needed. The shape of coal’s operational profile changes more than its absolute lifespan.

This extension is influenced heavily by Queensland’s Energy and Jobs Plan, which envisages a staged retirement of coal plant with repurposing and hybridisation. It also emerges from a more cautious assessment of real-world project delivery timelines. If large-scale renewables, firming, and transmission do not materialise at the speed assumed in the 2024 ISP, the model retains more legacy plant for longer to manage reliability outcomes.

The ISP now models coal capacity declining more gradually, with a longer tail. While the 2024 ISP saw coal reach zero by 2038, the 2026 draft keeps meaningful residual coal capacity through the early 2040s before tapering to zero by 2049. This is not a system dependent on coal, but a system using coal differently—as a flexible, security-oriented resource rather than an energy source.

The implication is a more complex operational regime. The system must accommodate thermal plant operating in low-minimum, high-ramp environments while simultaneously managing very high renewable shares. Light-load periods become critical, frequency and system strength challenges become more acute, and the thermal fleet’s technical limits matter more.

Demand shifts from hydrogen optimism to visible electrification

One of the most significant conceptual shifts in the Draft ISP is the reframing of long-term demand. The 2024 ISP included the Green Energy Exports scenario, built around large-scale hydrogen export demand, assuming electrolysers would consume very large amounts of electricity by the 2030s and 2040s. That scenario is now removed.

Hydrogen remains present in the model, but as industrial demand rather than as a national export driver. The large-scale hydrogen export narrative is effectively absent. In its place is a more grounded set of demand drivers that reflect real-world electrification trends already visible in industrial facilities, transport, and large loads.

AEMO now introduces a dedicated demand-side factors statement, which includes electrification of buildings, transport electrification, industrial process heat, behind-the-meter behaviour, energy efficiency, rooftop solar self-consumption, and flexible demand. This represents a notable methodological elevation: demand-side resources are treated as integral components of the future system, not marginal adjustments.

A particularly important addition is the formal inclusion of data centres as a distinct load class. While the ISP does not forecast data centre consumption explicitly in the detail seen in some international markets, their inclusion signals recognition that hyperscale computing is becoming a material part of electricity consumption growth.

The distribution network is also included in the ISP’s analytical scope for the first time. Distribution network constraints, hosting capacity, and CER integration are treated as relevant inputs to system-level outcomes. This means that the ISP is no longer solely a transmission-centric document; it now acknowledges that local network conditions materially shape national outcomes.

The combined effect of these changes is that total demand does not collapse even though hydrogen export demand disappears. Instead, demand becomes more balanced, more domestically focused, and more dependent on electrification trends that are already observable.

Distributed energy reshapes operational and investment patterns

Distributed energy resources (DER) continue to expand, with rooftop solar projected to reach around 87 GW by 2050—up significantly from the 72 GW forecast in the 2024 ISP.

This sustained growth reshapes the operational profile of the NEM, raising issues of minimum demand, flexible ramping, and daytime voltage management.

Storage at customer level grows materially, both behind-the-meter and in community-scale deployments. The Draft ISP acknowledges this through demand-side modelling attributes and by expanding its assumptions about dispatchable CER storage. As rooftop penetration grows, the value of mid-scale and local storage increases, reducing the need for some long-run transmission while raising the complexity of operational coordination.

Land-use complexity and social licence constraints also become structural considerations. Large-scale renewable projects increasingly face delays arising from land-use conflicts, biodiversity considerations, cultural heritage requirements, and local community sentiment. AEMO incorporates these factors into its cost and timing assumptions, which affects the relative competitiveness of different REZs and the sequencing of renewable build.

The main implication is that distributed energy is no longer just an offset to grid demand—it is a fundamental element of system operation, influencing investment decisions in generation, storage, and network infrastructure.

Generation and storage: the same scale, in a tougher environment

The total scale of new generation and storage required remains broadly unchanged from the 2024 ISP. The Draft ISP points to approximately 120 GW of new grid-scale renewables by 2050, alongside 55 GW / 618 GWh of storage and around 14 GW of flexible gas.

What changes is the investment environment that must deliver it. While the regulated WACC for transmission is reduced, the assumed cost of capital for renewables and storage increases. This reflects higher merchant exposure, increased congestion risk, more uncertain price outcomes, rising EPC costs, and more challenging financing conditions. AEMO explicitly increases the WACC for generation and storage to reflect higher risk premia.

This creates an asymmetry: transmission becomes cheaper to finance because it is regulated and revenue certain, while renewables become more expensive to finance because they are exposed to market risk. The ISP assumes the renewable build proceeds regardless, but that assumption is sensitive to investor confidence, technology cost trajectories, and policy stability.

The Draft ISP also reflects stronger modelling of storage value. As transmission deployment becomes more selective, storage plays a larger role in balancing local and regional supply-demand conditions. This raises questions about integration: whether storage can be deployed in the right locations and whether regulatory frameworks for shared assets can mature fast enough to support the required buildout.

The gas requirement, around 14 GW, is driven by reliability needs during multi-day renewable droughts and during periods of very low wind and solar correlation. Gas is no longer a baseload provider; it is a security resource that fills the gaps when renewables are insufficient or when transmission constraints isolate parts of the system.

The key implication of this section is that the generation and storage build remains large in absolute terms, but execution risk is now more visible. The system may depend just as much on capital availability and project timing as it does on technology costs or learning curves.

The project pipeline reshapes around sequencing, not volume

The Draft ISP revisits the status of actionable, future, committed, and anticipated projects. Several projects listed as actionable in the 2024 ISP—including HumeLink and Marinus Stage 1—are now classified as committed or anticipated, taking them out of the immediate decision-making space.

Other projects, such as QNI Connect and the Northern Transmission Project, are now under review. Their net market benefits depend heavily on the timing of coal retirement, industrial load growth, and policy direction in New South Wales and Queensland. AEMO reflects this uncertainty by not endorsing these projects outright.

Conversely, the Western Victoria Transmission Reinforcement and the Gippsland Offshore Wind Transmission line move into the actionable window. These projects support strong resource zones—onshore wind capacity in western Victoria and offshore wind development in Gippsland.

These shifts illustrate how project sequencing matters as much as total build. The Draft ISP models a future where local constraints, policy timelines, and renewable resource availability shape which projects move forward and when. The network is no longer a linear “build everything” stack; it is a selective program prioritised around timing, land availability, and reliability needs.

System implications and emerging risks

The Draft 2026 ISP presents a power system that is still on track for deep decarbonisation but is increasingly shaped by cost, timing, and complexity. The optimism of earlier ISPs around unconstrained buildout is replaced with a more mature treatment of risk. Three systemic implications stand out:

First, the transition is more capital-intensive under higher financing costs. The asymmetry between low-risk transmission and higher-risk renewable generation raises sequencing challenges. The system can only decarbonise at the rate at which private capital can be deployed into renewable and storage projects under acceptable risk conditions.

Second, land-use and community sentiment are now structural constraints, not peripheral ones. The ISP recognises this, but the real-world impact could be even stronger than modelled. This creates pressure to improve consultation, planning, and co-design processes around large infrastructure.

Third, demand is more diversified and more domestic. While hydrogen exports fall away, electrification across households, transport, industry, and data centres drives sustained growth in consumption. This creates opportunities for flexible demand and distributed storage but places pressure on distribution networks and connection processes.

Overall, the Draft 2026 ISP presents a system model that is still optimistic but bounded by more realistic constraints. The future NEM remains a renewables-dominated system supported by storage, transmission, and flexible gas. But its delivery depends on more than technology cost curves—it depends on capital markets, social licence, project sequencing, and the speed at which real-world infrastructure can be financed and built.