The future grid won’t just run on renewables – it will run on batteries. From giant grid-scale projects to the car in your driveway, the question remains: how do we make them all work together?
At about 2am on 14 December 2017, one of Australia’s largest coal units – Loy Yang A3 in Victoria – tripped without warning, dumping 560 MW off the grid in seconds.
Normally, that kind of shock would leave the grid scrambling. But this time, nearly 1000 km away, the newly built Hornsdale Power Reserve in South Australia – the world’s first “Tesla big battery” – came online almost instantly, injecting power before the coal plant contracted to provide backup had even responded.
At that moment, batteries revealed their big advantage: speed. Coal generators can take hours to come online, and even gas turbines need minutes to ramp. Batteries, by contrast, can deliver in milliseconds. Since then, grid-scale storage has now become part of the fabric of Australia’s electricity network.
“Large-scale batteries are no longer just emergency backup,” electrical engineer Professor Behrooz Bahrani, Director of the Grid Innovation Hub at Monash University, told create.
“They now provide essential services such as frequency regulation, peak demand management and fast responses to disturbances. Their ability to deliver these within milliseconds makes them a cornerstone of grid stability and flexibility.”
In March 2025, the combined output of Australia’s big batteries reached a record 1.22 GW at the evening peak, underscoring just how far the technology has come since Hornsdale put batteries on the map. But as their numbers grow, the challenge is no longer whether batteries can work – it’s how to make them work together.
Distributed by design
The integration puzzle is bigger than grid-scale batteries. In suburbs and towns, hundreds of thousands of household units are already in use – a number set to climb further with the federal subsidy announced in July 2025. Add a growing fleet of EVs, and the coordination challenge multiplies. For engineers, the task is the same whether it’s a 300 MW utility battery or a 10 kW residential unit in a garage: integrate storage so it strengthens, rather than destabilises, the grid.
For Professor Lachlan Blackhall FIEAust, Deputy Vice-Chancellor for Research and Innovation at the Australian National University (ANU), the rise of batteries points to a deeper systems shift.
“We’re moving from a centralised, fossil-fuel powered grid to a highly decentralised system with utility-scale renewables alongside millions of small generation and storage assets,” he said. “This requires a fundamentally new operating paradigm.”
That shift means household batteries and rooftop solar can’t operate in isolation. They need orchestration – signals that help schedule when to charge, export to the grid or supply their household energy use. Without these capabilities, they risk either straining the grid or missing the chance to make it more efficient and affordable.
As co-founder of Reposit Power, Blackhall helped pioneer software to aggregate household batteries into some of Australia’s first virtual power plants (VPPs). Later, at ANU, he led the Battery Storage and Grid Integration Program, which trialled these ideas in practice. The 2016–19 CONSORT Bruny Island trial showed how a network of household batteries could ease pressure on the local electricity system during times of high demand.
The follow-on Evolve project (2019–21) introduced dynamic operating envelopes (DOEs) – smart software that signals how much energy homes can export or import based on real-time conditions. Unlike fixed limits, DOEs change depending on the current grid operating conditions, giving people more opportunity to use and share their energy without overloading the system.
That work seeded Elentar, a spin-out co-founded by electrical engineer Andrew Fraser, who previously worked alongside Blackhall at ANU and earlier worked on the Bruny trial at TasNetworks.
“Most batteries today are set up for the household – charge from solar during the day, discharge at night,” he said. “That’s good for the house, but it doesn’t necessarily help the grid. In fact, it can make things worse by filling up when the system already has too much solar, and sitting empty during the evening peak.”
While DOEs provide what Fraser called the “guardrails”, VPPs take that orchestration even further, and can link home batteries to the market – sending signals to charge or discharge when the system needs it.
The benefits are clear at system level, Fraser said, but less obvious for households: “The economics aren’t huge – often just a couple of hundred dollars a year – and if people don’t trust their retailer, they’re reluctant to hand over control.”
Even so, coordinated storage makes the overall system more efficient and cheaper for everyone. The task now is scaling these solutions – turning research pilots into everyday practice.
Balancing act
One of the next frontiers for distributed storage is transport.
A single car battery can be 10 times the size of a household unit, and as hundreds of thousands of EVs plug in over the coming decade, they could become one of the largest sources of flexible storage.
An April 2025 trial by CSIRO and Essential Energy showed how that potential could be unlocked, delivering Australia’s first vehicle-to-grid solution using the Combined Charging System standard, which enables DC bidirectional charging. The project tested how EVs can store rooftop solar during the day, power homes at night and export surplus energy back to the grid.
Large-scale demonstrations such as Project Symphony in Western Australia are also showing what this coordination looks like in practice. There, more than 900 homes and businesses with solar, storage and controllable appliances are linked into a single operating platform, proving how distributed assets can provide many of the same services as a traditional power station – from keeping frequency steady to shaving peaks in demand.
However, elegant integration relies on more than smart hardware; it depends on being able to see what’s coming. Operators need to know when the sun will dip, when demand will spike and how much charge is left across thousands of distributed batteries. That’s where advanced forecasting becomes critical.
“AI and machine learning can immediately enhance predictions of demand, renewable generation and battery state-of-charge,” Bahrani said. “Better predictions mean batteries can be dispatched more efficiently, reducing costs and strengthening reliability.”
The harder part is what happens next: turning those forecasts into action across millions of individual assets. For Blackhall, this is where standards are crucial.
“Great standards are the foundation for scaling,” Blackhall said. “If we want millions of energy assets integrated into the system, then integration standards have to be simple, repeatable and reliable. That’s where a lot of my effort is going – building the system for scale.”
Beyond lithium: chemistries to watch
Lithium-ion dominates storage today, but engineers are already preparing for a more diverse battery future.
Lithium-ion batteries have carried storage into the mainstream – from homes to grid-scale projects – but they are not the end of the story. Researchers are developing a new wave of chemistries that promise different trade-offs in safety, cost, cycle life and performance.
“Lithium-ion will continue to be the workhorse of the energy transition,” Dr Marzi Barghamadi, who leads battery projects at CSIRO, said. “But no single chemistry can do everything. The future grid will need a mix.”
Among the most advanced alternatives are sodium-ion batteries, which swap lithium for a far more abundant element. They can’t match lithium’s energy density. However, for different applications from scooters to stationary applications, they could deliver reliable and affordable storage without supply chain bottlenecks.
Other researchers are pushing solid-state designs, which replace flammable liquid electrolytes with solids. “The potential is huge,” Barghamadi said. “If the cost and technical hurdles can be overcome, lithium metal solid-state batteries could double driving range while improving safety.”
The road ahead
Meanwhile, storage capacity is surging. AEMO’s 2024 Integrated System Plan forecasts 22 gigawatts by 2030, much of it paired with new renewable zones. As batteries spread across the grid, questions of resilience become just as important as performance.
Lithium-ion fires, for example, are rare but behave differently to conventional blazes. It’s a reminder that integration is not just about markets and software, but about how assets are designed and managed in the real world.
Another frontier is digital: “Batteries are connected assets, so protecting them from cyber threats is essential,” Bahrani said.
In an April 2025 article, specialists from global battery storage company Fluence cited cases from ransomware in Queensland to coordinated strikes in Denmark as evidence that storage infrastructure is becoming a target. They argued that energy storage should now be “at the centre of the cybersecurity conversation”, and for engineers to design systems with security built in from the outset.
Taken together, these risks underline the central lesson of battery integration: performance alone is not enough. Safety, security and coordination all matter if storage is to deliver on its promise.
The story of batteries is no longer about backup; it is about integration – of large and small, fast and slow, public good and private benefit. For engineers, that is both the challenge and the opportunity: to design a system where every battery, from a grid-scale Tesla Megapack to the EV in your driveway, contributes to stability rather than undermines it.
When batteries burn: fire safety lessons
Lithium-ion batteries are generally safe, but when things go wrong, they behave differently – and fire services are adapting fast.
As batteries become central to Australia’s energy transition, fire authorities are confronting new and unfamiliar risks. Lithium-ion fires are rare, but when they occur, they don’t behave like conventional blazes.
“Batteries are generally safe – they don’t just spontaneously combust,” said Matt Allen, Senior Manager of Specialist Risk and Fire Safety at Victoria’s Country Fire Authority (CFA). “The bigger issue for first responders is being able to safely de-energise a battery if they turn up to a house fire not caused by the battery.”
To get ahead of these challenges, the CFA has published detailed guidelines for renewable energy facilities – documents now referenced nationally and even overseas. They set out design requirements for spacing, site access, firebreaks and water supplies. The emphasis, Allen said, is on thinking about safety right from the design stage.
“Firefighter safety is the number one requirement we look at. The guidelines are built around that, as well as the safety of the community.”
The 2021 fire at the Victorian Big Battery underlined what is at stake. A coolant leak in a Tesla Megapack triggered thermal runaway, destroying two [battery] units and forcing a major response. The incident, said Allen, was a turning point.
“We captured a lot of information out of that fire, and our guideline went through its biggest change because of how much we learned.”
For engineers, one lesson stands out: spacing matters. Thermal runaway can escalate quickly if cells or units are packed too tightly. The CFA recommends at least three metres between large units to give firefighters room to operate and prevent one failure from cascading into many.
EA OnDemand: Challenges and innovations in battery energy storage systems
This story was originally published in the November 2025 edition of create with the headline “Beyond backup”.
