Virtual Power Plants can scale in Australia, but the system around them needs to catch up

Virtual Power Plants are generating very different views across Australia’s energy sector. For some, they are an obvious part of a more decentralised electricity system, providing a way to coordinate the growing volume of solar, batteries and, increasingly, electric vehicles. Others are more cautious, pointing to low participation, mixed customer experiences and the complexity of coordinating thousands of assets reliably. Recent data provides evidence for both perspectives.

Australia has built an extraordinary base of consumer energy resources. More than four million homes have rooftop solar, and AEMO’s final 2026 Integrated System Plan estimates that around 600,000 households in the NEM now have batteries. Battery adoption has accelerated sharply following the introduction of government incentives, with the Commonwealth’s Cheaper Home Batteries Program supporting more than 400,000 installations in less than a year.

VPP participation is growing too. The ACCC found the number of participating customers across NSW, Victoria, South Australia and Southeast Queensland increased by 67 per cent in the six months to January 2026, reaching 63,100. But battery adoption is moving even faster. Only around 24 per cent of customers with an installed battery in those markets were participating in a VPP at the start of 2026. That gap matters.

Household batteries create value individually by storing cheap solar generation and reducing a household’s reliance on the grid. But coordination can create additional value by charging and discharging those batteries when the wider system needs it. AEMO modelling cited by the ACCC suggests that if around half of household batteries ultimately participate in VPPs, around $7.2 billion of additional generation and network investment could potentially be avoided by 2050.

The point is not to install more batteries. It is to embrace the opportunity they represent by making better use of the batteries we are already installing.

Our view is that VPPs can play an important role in doing that, but technology alone will not get us there. Three conditions need to develop together: a compelling customer proposition, networks that can accommodate and enable two-way coordination, and clearer coordination between VPP providers, networks and system operators.

Whether that coordination ultimately sits inside something called a VPP, a dynamic retail offer or another aggregation model matters less than the outcome. We need consumer energy resources to become more visible, responsive and useful to both their owners and the wider system.

Australia is not one uniform market for VPPs. In the NEM, the pathway is more market-led, with flexibility increasingly able to respond to wholesale prices and system services. Implementation is also underway for reforms that will allow aggregated price-responsive resources to participate more directly in central dispatch from 2027.

WA has a different market design and is taking a more system-led approach. Its Reserve Capacity Mechanism, high rooftop solar penetration and minimum-demand challenges create different incentives for coordination. The 2026 WEM ESOO now forecasts VPPs reducing SWIS peak demand by around 200 MW in 2028-29, while WA's residential battery scheme explicitly links subsidised batteries with VPP capability and participation.

The fundamentals are the same, but the commercial signals, roles and scaling pathways will not necessarily be.

At its core, a VPP depends on customers choosing to participate. That makes the customer proposition much broader than trust alone. There are three parts to getting it right.

The first is the offer and the value. Most households have installed solar and batteries for practical reasons: lower bills, greater independence, and increased resilience during outages. A VPP asks them to make another trade, giving someone else a degree of influence over how their battery is used in return for additional value. That value needs to be meaningful, simple to understand, and easy to verify.

There is now stronger evidence that this can work. The ACCC found that VPP participants had median annual electricity bills 57 to 63 per cent lower than regular customers across the regions it studied. Customers with solar and a battery but not necessarily a VPP also benefited, although their savings were lower at 20 to 52 per cent.

But averages only tell part of the story. The ACCC also found significant variation between VPP products and customer outcomes. In some circumstances, a customer may be better off with another VPP provider or without a VPP at all. The proposition therefore cannot simply be “join a VPP and save”. Customers need confidence that the specific offer works for them.

The second element of getting it right is determining who provides the proposition and owns the relationship. Retailers, battery manufacturers, installers, specialist aggregators, dynamic retailers and third-party asset owners can all play a role. Each has different advantages in customer trust, access, technology and economics. Increasingly, the critical moment may be when a customer buys a battery, solar system or EV charger, rather than months later when an energy offer appears in their inbox.

The third is transparency and accountability. Customers need to know what will happen to their battery, how much control they retain, and how the value is shared. Backup reserves, transparent dispatch rules, simple override settings, clear information on battery use and straightforward exit arrangements all matter.

This has become more important as the market has grown. The ACCC reported a significant increase in consumer complaints relating to consumer energy resources and highlighted product complexity, operator discretion and limited battery interoperability as emerging concerns. It has called for stronger consumer protections as coordination grows.

There is also a more basic issue of awareness and language. If customers do not understand what a VPP is, why it exists, or what they are being asked to opt into, the rest of the proposition is unlikely to land. Education, labelling and plain-English explanations need to be part of the product, not an afterthought.

Even with a strong customer proposition, the local network has to be able to accommodate the behaviour of increasingly active consumer assets.

Distribution networks were largely designed around electricity moving in one direction, from large generators through the network to customers. Rooftop solar, batteries and EVs are changing that. Electricity now moves both ways, and what happens on a particular street or feeder can matter just as much as what is happening across the wholesale market.

VPPs add another dimension because coordination can create highly correlated behaviour. Thousands of batteries responding to the same wholesale price signal may be helpful to the broader system, but could create a problem if they all export into a constrained part of the local network at the same time.

This does not mean networks are uniformly “not ready”. Readiness varies significantly by location. It does mean networks increasingly need better visibility of what is connected and what those assets are doing, as well as more flexible ways to manage exports and imports as conditions change.

The final 2026 ISP reinforces this point. AEMO explicitly identifies distribution network upgrades and more dynamic operation as important to unlocking the value of consumer energy resources and reducing the need for grid-scale investment.

There is also an important question about who pays. Greater visibility, data, and flexible network capability require investment, and much of that investment will ultimately be recovered from customers through regulated network charges. The case therefore needs to be grounded in value. Investment should be targeted where better coordination can demonstrably increase hosting capacity, avoid or defer more expensive augmentation, improve reliability or unlock material customer and system benefits.

The goal is not to build a digital layer everywhere simply because we can. It is to make targeted investments that allow distributed resources to contribute more where the benefits exceed the costs.

The hardest part of VPP scale may ultimately be coordination. A VPP provider or aggregator wants to create value for customers and participate in energy markets. A distribution network wants to deliver customer value while maintaining local reliability, safety and power quality and making efficient use of its infrastructure. AEMO needs to maintain system security and ensure supply and demand remain balanced across the market.

Most of the time, those objectives can reinforce one another. Sometimes they will not. A wholesale price spike might encourage an aggregator to discharge a portfolio of batteries. A local constraint could mean the network needs exports reduced in one area. At the same time, an individual customer may want to preserve battery capacity for backup.

At small scale, these conflicts can be managed through individual arrangements. At large scale, that will not be enough.

The sector needs clearer coordination arrangements that establish how constraints are communicated, how competing signals are prioritised, what information is shared, and who is accountable for the outcome. In simple terms, we need clearer rules of the road.

There is movement in this direction. Reforms underway in the NEM will allow aggregated price-responsive resources such as VPPs to participate more directly in central dispatch from May 2027, while AEMO is also working on improved visibility of price-responsive resources.

As VPPs become a resource the system increasingly relies upon, performance will matter as much as participation. Aggregated portfolios will need to demonstrate availability, responsiveness and compliance with network and system constraints. Data and telemetry need to be good enough to verify what was actually delivered, not simply what was expected.

International experience gives some indication of what scale could look like. A coordinated California event in 2025 brought together more than 100,000 household batteries and delivered around 535 MW during the evening peak. In WA, AEMO is now forecasting 640 MW of distributed battery capacity capable of coordination through Synergy's VPPs by 2028-29, albeit with a conservative 50 per cent availability assumption while the model matures.

The question is therefore shifting from whether distributed assets can be coordinated to how they can be coordinated consistently, fairly, and reliably.

There is no single intervention that will take VPPs from a relatively small part of the market to a mainstream system resource. But five practical shifts would help.

1. Make the customer value exchange unmistakable. Customers should be able to see what they receive for participating, what control they provide and how value is shared. Offers need to become easier to compare and outcomes easier to verify.
2. Make customer guardrails the default, not the fine print. Backup reserves, override controls, transparency on battery use and clearer protections when things go wrong should become standard parts of the proposition. Interoperability also matters. Customers should not be unnecessarily locked into one provider simply because of the battery they purchased.
3. Target investment in network visibility and flexible operation where it creates value. Networks need the capability to accommodate more two-way flows and communicate local constraints, but investment should be linked to clear benefits such as greater hosting capacity, deferred augmentation or improved customer outcomes.
4. Establish practical coordination rules across VPP providers, networks and AEMO. The sector needs clearer arrangements for sharing information, signalling constraints, prioritising competing needs and verifying performance. This becomes increasingly important as coordinated portfolios grow from tens to hundreds of megawatts.
5. Unlock more of the value stack. The economics become more compelling when coordinated resources can create value across wholesale energy, system services and, where it is efficient, local network support. Better value stacking should increase the pool available to reward customers while also improving the economics for providers and the wider system.

Australia has already done much of the hard work of creating the underlying resource. Millions of households have invested in solar, and batteries are now being installed at a pace few expected even a year ago. The challenge is increasingly what we do with that resource.

If we can get the customer proposition, network readiness and coordination arrangements right, Australia has an opportunity to turn a very large collection of individual assets into a flexible resource that works harder for customers and for the system.

That may not always look like the VPPs we know today. But the underlying opportunity remains the same: making millions of small resources work better together.

Get in touch to discuss the opportunities, challenges, and practical pathways for scaling Virtual Power Plants across Australia.

Connect with Craig Hutchinson on LinkedIn.