Introduction
Australia is offering one of the clearest real-world examples of how the future electricity system is emerging, with valuable lessons for countries that will face similar energy transition challenges. High rooftop solar penetration, rapid battery deployment, and rising demand from EVs and data centers are driving practical changes across the power system.
These changes show that the transition is not only about producing more renewable electricity. It is also about coordinating Distributed Energy Resources (DERs), such as rooftop solar, batteries, EV chargers and flexible loads, as part of the power system.
Here are seven key insights from Australia for the New Energy Landscape—and how standards can help DERs connect faster, operate safely, and work together under common rules.
1. Rooftop solar has become system-scale
Australia now has more than 4 million rooftop solar systems, and rooftop solar supplied around 12% of the country’s electricity in 2024 and the first half of 2025. It is a major part of the national electricity mix.
That changes the role of consumers. Homes, commercial and industrial buildings are becoming prosumers: they consume, generate, export and store electricity. The grid must be able to manage this two-way flow safely and predictably.
At this scale, rooftop solar changes distribution grid operation: midday exports can create reverse power flows, voltage issues and the need for dynamic export limits or curtailment.
This deployment is also linked to Australia’s generation starting point. The power system has historically relied on coal- and gas-fired plants, and is now moving toward higher shares of renewable, decentralized and inverter-based generation. As this shift continues, the electricity system must be able to operate reliably with more variable generation.
Figure 1: International Energy Agency (IEA), Electricity generation, Australia, 2024, license CC BY 4.0.
Australia is among the world leaders in solar electricity, with solar providing around 17% (rooftop and utility-scale solar) of total electricity generation in 2024. Solar output varies during the day and with the weather. This requires more flexibility, including storage and inverters that can support grid stability and help manage congestion. Compared with Europe, Australia has fewer options to share electricity across regions (the National Electricity Market connects the eastern and southern states, but Western Australia and the Northern Territory are separate systems) and no international interconnection. As a result, grid stability and congestion constraints can be harder to manage than in more interconnected power systems.
2. Electrification and data centers are reshaping electricity demand
Electricity still represents only about 22% of Australia’s total energy use. Decarbonizing power generation is therefore only the first step: transport, buildings and industry must also shift from fossil fuels to clean electricity where technically feasible.
This shift will significantly increase electricity’s role. Government plans identify electrification of transport, buildings and industry as a key pathway to decarbonization, while global scenarios show electricity’s share of final energy rising strongly by 2030. For Australia, this means new loads will grow as coal retires and end uses electrify.
The challenge is therefore not only how much new electricity will be needed, but where, when and how this demand appears on the grid.
The most visible change will come from electric mobility and data centers. When many EVs charge at the same time, they can create local peaks on the grid. These peaks can be managed by controlling charging in homes, buildings and charging hubs, and by coordinating it with the grid. Local storage and on-site electricity generation will also help reduce the impact on the grid. Data centers are already significant: they account for about 2% of Australia’s grid-supplied energy today and could reach around 6% by 2030.
These new loads will increasingly need to become more flexible and responsive. EV chargers, industrial sites and data centers must be able to interact with the grid: communicate with energy management systems, adjust their consumption when the grid is constrained, and contribute to grid stability during disturbances. For large continuous loads such as data centers, this means defining not only connection capacity but also expected behavior during grid disturbances. Standards define common rules for connection, communication, control and grid response, so demand growth can be integrated safely and consistently.
3. Batteries are moving from backup to core infrastructure
Battery deployment is accelerating at both household and grid scale.
Home battery sales rose from 46,127 units in 2023 to around 75,000 in 2024, and 85,000 units were sold in the first half of 2025 alone. The Cheaper Home Batteries Program, launched in July 2025 with an approximate 30% discount for eligible systems, quickly generated more than 55,000 applications and over 1 GWh of distributed storage capacity.
Grid-scale batteries are also becoming central to system operation. By the end of Q3 2024, 14.6 GW of battery projects were progressing through the National Electricity Market (NEM) connection process. In Q1 2026, the Australian Energy Market Operator (AEMO) reported 4.4 GW of new battery capacity added over the previous 12 months.
Their value is visible in the duck curve. Batteries charge when rooftop and utility solar are abundant, then discharge during the evening peak. In Q1 2026, batteries more than tripled daytime-to-evening energy shifting and delivered 1.1 GW into the evening peak, helping reduce wasted solar, evening stress and price volatility.
The trend is: batteries are increasingly moving beyond their traditional role as backup assets. At residential and commercial level, their value depends on coordinated control with rooftop solar, EV charging, heating, ventilation and air conditioning (HVAC) and other flexible loads through a Home Energy Management System (HEMS) or Energy Management System (EMS) for Commercial and Industrial buildings. At grid scale level, batteries are becoming core electricity infrastructure, able to reduce curtailment, soften peaks, improve use of existing grid capacity and support system stability. Standards are therefore needed to define how batteries connect, communicate, respond to grid signals and participate safely in coordinated flexibility schemes.
4. Flexibility is becoming essential
Where regulation and connection agreements allow it, flexibility can help connect large new loads faster without waiting for full grid reinforcement. For example, electric truck charging hubs or data centers may be easier to connect if part of their demand can be controlled, shifted or temporarily limited when the grid is constrained. Instead of sizing the connection only for worst-case operation, flexible interconnection allows assets to use available grid capacity more dynamically.
Flexibility has value at two levels. At system level, it helps maintain the balance between supply and demand in a power system with more intermittent generation and new electric loads, which is essential to keep frequency within acceptable limits. At grid level, it helps avoid local voltage issues and congestion by adjusting EV charging, batteries, industrial demand or data-center load when the grid is under stress. Standards are needed to make these flexible assets predictable: how they receive signals, how they respond, how performance is verified and how grid operators can trust their behavior.
5. Home Energy Management Systems coordinate rooftop solar, batteries and flexible loads
A Home Energy Management System (HEMS) acts as the local coordination layer between rooftop solar, batteries, EV charging, HVAC, other flexible appliances and user preferences. It can help households optimize consumption, reduce bills, increase self-consumption and respond to tariffs or grid signals.
At scale, HEMS can also help the grid. If homes can export, consume or store electricity in a predictable way, they become part of a coordinated flexibility resource. This is one of the clearest examples of how the New Energy Landscape connects individual choices with system-level performance.
Figure 2: The central role of HEMS
6. DC distribution can improve resilience and reduce grid impact
Many new energy assets are naturally direct current (DC)-based: solar PV, batteries and high-power EV charging. A DC architecture combining local generation, storage, a DC bus and an interlink converter can reduce unnecessary conversion stages.
For charging hubs and other DC microgrids, this can make demand more predictable and reduce the required grid connection capacity. A DC microgrid can also improve resilience during a grid outage: local generation and batteries can continue supplying part of the load, reducing dependence on the public grid.
Scaling DC distribution is requiring new standards for installation, interoperability and equipment level that have recently been published at IEC level or that are closed to be published.
Figure 3 : AC grid and DC microgrid
7. Standards turn separate assets into one coherent system
Three types of standards are needed: installation standards to connect assets safely, interoperability standards to make assets work together, and product standards. For prosumer installations, IEC 60364-8-82 provides the international AC low-voltage framework that directly supports the massive deployment of photovoltaic (PV) systems and batteries. In Australia, this must connect with national installation rules so that millions of small assets can operate safely and predictably.
For flexibility, standards are the enabler. IEEE 2030.5 is already used in Australia to support flexibility services and grid stability. In Europe, IEC 62746-4 provides an international reference for demand response interfaces, even if implementation depends on national and market frameworks. These standards make it possible to activate flexibility from loads in a way that grid operators can trust.
For HEMS, IEC 63402-3 is a key emerging international standard, defining the expected functions for energy efficiency, local asset orchestration and grid-support contribution. Australian HEMS-related requirements could build on this approach, so that home- and building-level optimization can move beyond individual savings and become part of coordinated system flexibility.
DC distribution also needs its own standards layer. The recently published DC amendment to IEC 60364-8-82 extends the prosumer installation approach to DC grids, while emerging standards for new DC equipment, such as IEC 63532 for interlink converters and IEC 60947-10 for solid-state circuit breakers, will be essential to make DC architectures safe, protected and scalable.
Finally, grid codes will need to evolve for inverter-based systems. This is particularly important in Australia, where coal retirement, fewer interconnection options than more integrated power systems, and high inverter-based generation make system strength a practical operational issue. As synchronous generation retires, inverters will progressively move from a grid-following role to a grid-forming role, helping support voltage, frequency and system stability.
Closing
Australia already offers a clear view of what a more decentralized, electrified and flexible power system can become. Installation standards, interoperability standards and product standards can help Australia build a safer, more scalable and more coordinated power system for the next stage of the energy transition. The Australian experience can also provide useful guidance for other countries following a similar path.
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