This is an extract from a recent report “Rapid Growth in Distributed Solar and Batteries Enables Australia to Reach 40% Renewables” published by Renewable Energy Institute.

1. Utility-scale batteries dominate energy storage deployment

To support the economic and technical integration of solar PV, Australia added 17.5 GWh of energy storage capacity between 2021 and 2025, almost entirely through battery storage systems. Nearly 70% of these additions came from utility-scale projects [Figure 13].

Utility-scale batteries are particularly well suited to energy arbitrage, whereby they charge during periods of low or negative prices and discharge during periods of high prices. This is their primary source of revenue [Figure 14]. They are also the leading providers of frequency control ancillary services (FCAS), including regulation services and contingency reserves that help maintain system frequency close to 50 Hz. These services require rapid response times, giving lithium-ion batteries a significant competitive advantage.

Figure 15 highlights the complementarity between batteries and solar PV. Batteries typically charge during periods of strong daytime solar generation and low electricity prices, then discharge during the evening when solar output declines and demand remains elevated, enabling energy arbitrage while supporting grid stability and limiting curtailment.

In the NEM, batteries helped halve electricity prices during the evening peak demand period in the second half of 2025 compared with the same period in 2024, reducing prices from $144/MWh to $72/MWh. They achieved this by storing surplus daytime solar generation and displacing higher-cost gas-fired generation, while also compensating for reduced hydroelectric output in New South Wales and Victoria [Figure 16]. Moreover, by shifting solar generation beyond daylight hours, batteries contribute to the transition towards a 24/7 carbon-free power system.

As standalone utility-scale solar PV increasingly faces significant economic offloading and network curtailment, the co-location of solar PV and battery storage has become mainstream in Australia [Figure 17]. Battery systems can improve the utilization of grid connections, create new bankable revenue streams, and shift solar generation to higher-value periods.

After rising modestly between 2021 and 2023 due to higher financing costs and inflation, the LCOE of utility-scale solar PV paired with four-hour battery storage declined by more than 20% between 2023 and 2025, driven largely by falling battery costs. This made the technology’s LCOE comparable to the marginal cost (i.e., fuel costs and variable operation and maintenance costs) of existing combined-cycle gas turbines (CCGTs) [Figure 18].

Beyond reducing costs and improving market flexibility, batteries are also becoming increasingly important for maintaining power system reliability. Solar generators and batteries are connected to the grid through inverters. Advanced grid-forming inverter technology can emulate the response of synchronous generators to fluctuations in the power system, enabling the provision of synthetic inertia and helping maintain grid stability. This is particularly important as older, predominantly subcritical coal-fired power plants are progressively retired, reducing a major source of system inertia provided by the large rotating masses of their turbines and synchronous generators.

As of September 2025, Australia had the world’s largest pipeline of grid-forming battery projects, with 5.4 GW of capacity either operational or under construction. An example of a grid-forming battery already in operation is AGL Energy’s Torrens Island Battery (250 MW / 250 MWh) in South Australia, which began operating in August 2023. Coal-fired power plants face growing economic competition from solar PV, alongside increasing environmental pressures. They also face technical challenges, as ageing plants experience more frequent outages and lack the operational flexibility required to respond rapidly to variable solar PV generation. BloombergNEF projects that by the end of 2040, 96% of Australia’s coal-fired generating capacity will be permanently retired, leaving only a single coal-fired power plant in operation: the 852 MW Millmerran power plant in Queensland, owned by Sev.en Global Investments [Figure 19]. Commissioned in 2002, Millmerran is one of the youngest coal-fired power plants in the NEM.

Several utility-scale battery projects are being developed near or at the sites of former coal-fired power plants, including Eraring and Liddell in New South Wales, and Yallourn in Victoria. Repurposing these sites can support public acceptance of the energy transition in communities affected by plant closures.

2. Distributed battery deployment is accelerating rapidly

The economic rationale for investing in distributed battery storage differs markedly from that for utility-scale storage systems. For households, key motivations include reducing electricity bills, increasing self-consumption of rooftop PV generation, and enhancing energy independence, while profit maximization is generally a secondary consideration. While the upfront cost of a 10-kW residential rooftop PV system in Australia is around $5,000, a residential battery system with a capacity of 12 kWh costs more than $10,000. This remains the principal barrier to the widespread adoption of distributed batteries.

Against this backdrop, the federal government launched the “Cheaper Home Batteries Program” on 1 July 2025. The program provides a discount of around 30% on the upfront cost of installing battery systems with capacities ranging from 5 to 100 kWh. The subsidy is available for batteries connected to either new or existing solar PV systems. It will be reviewed at least annually and gradually reduced through to 2030, in line with declining battery costs. The program has been successful in accelerating the deployment of residential batteries, as demonstrated by the sharp increase in capacity additions in 2025 [Figure 20]. The vast majority of new installations occurred following the introduction of the program.

Prior to the introduction of the Cheaper Home Batteries Program, several states had already implemented financial incentives to support the uptake of distributed batteries. For example, the New South Wales government offered households and businesses subsidies of approximately $1,000-1,500 for the installation of new battery systems, while the Victorian government provided interest-free loans of up to $5,700 for distributed batteries.

These incentives contributed to New South Wales and Victoria emerging as leading states in the deployment of distributed solar plus-storage systems ahead of the implementation of the Cheaper Home Batteries Program [Figure 21].

Distributed solar PV paired with battery storage can significantly increase self-consumption, enabling households to consume more than 80% of their rooftop PV generation on site. Consequently, widespread adoption of distributed batteries can reduce exports to the grid and help alleviate some of the economic and technical challenges associated with high levels of distributed solar penetration.

In addition to increasing self-consumption, distributed energy resources can be aggregated to form virtual power plants (VPPs), which are networks of connected rooftop solar PV systems, battery storage systems, and controllable household loads that are managed collectively to operate as a single power plant. In 2018, the South Australia VPP was launched through a partnership between the South Australian government, Tesla, and electricity retailers. It is one of the country’s largest residential VPP projects, comprising thousands of homes equipped with rooftop solar PV systems and Tesla Powerwall batteries.

Participating households benefit from lower electricity costs through access to electricity tariffs that are 25% lower than standard residential rates in South Australia. They also gain greater resilience during power outages, as battery storage can provide backup power during blackouts, and access to carbon-free electricity, as a greater share of household electricity demand is met by rooftop solar generation, with excess solar electricity stored in home batteries for later use.

At the same time, VPP operators generate revenue by aggregating the capacity of thousands of distributed energy resources and participating in wholesale electricity and ancillary service markets, where they are compensated for supplying energy and supporting grid stability.

Since its launch, the VPP has supported the grid during several major events, including a power plant trip in Queensland in October 2019, the provision of emergency power to residents of Port Lincoln, South Australia, during catastrophic bushfire conditions in November 2019, and multiple interconnector outages between South Australia and Victoria in 2019, 2020, and 2022.

Despite these benefits, the widespread deployment of VPPs faces several challenges. One of the most significant is encouraging more households to allow third parties, such as electricity retailers or aggregators, to control the operation of their solar PV and battery systems. This can be challenging because many households value the autonomy and energy independence associated with owning distributed energy resources. Accelerating VPP participation will require the development of attractive business models that provide clear financial benefits while maintaining consumer trust.

3. Long-duration energy storage complements short-duration batteries

In recent years, energy storage deployment in Australia has been driven largely by the expansion of lithium-ion batteries, which have traditionally been deployed as short-duration systems providing 1-3 hours of storage. The country’s first four-hour utility-scale battery, Collie Stage 1 (219 MW / 877 MWh), entered operation in Western Australia in October 2024.

The economic incentive for long-duration energy storage (LDES) is currently limited because battery revenues are primarily derived from short-term energy arbitrage and FCAS, both of which can generally be provided by batteries with only a few hours of storage and rapid-response capability.

While short-duration batteries help address intraday imbalances, LDES will be needed to manage extended periods of low solar PV generation and maintain system reliability as coal generation is phased out.

LDES is widely recognized as essential for achieving a power system with high shares of solar PV in Australia, although no dedicated national LDES policy currently exists. Instead, policy leadership has come primarily from the states, particularly New South Wales.

New South Wales has legislated minimum LDES targets of 16 GWh by 2030, rising to 28 GWh by 2034. The state also defines LDES as storage capable of at least eight hours of continuous discharge. Eligible technologies include pumped hydro, lithium-ion batteries, and emerging LDES technologies such as flow batteries and compressed air energy storage.

New South Wales supports the deployment of LDES through competitive, technology-neutral tenders. Successful projects are awarded Long-Term Energy Service Agreements (LTESAs), which provide generators with the option to sell electricity at an agreed minimum price. These prices are generally not publicly disclosed, with most contract terms treated as commercially confidential.

Through two separate tenders held in February 2025 and February 2026, New South Wales awarded a total of nine LTESAs to LDES technologies, including eight lithium-ion battery projects [Figure 22]. Together, these battery projects represent around 1.4 GW / 13.8 GWh of storage capacity, with storage durations ranging from 8 to 11.5 hours.

The only LTESA not awarded to a lithium-ion battery project was granted to the ACEN Phoenix pumped hydro project (0.8 GW / 12 GWh), which has a storage duration of 15 hours. Several factors explain the predominance of lithium-ion batteries in these tenders, including lower capital costs, faster deployment timelines, and lower development risks. The challenges associated with pumped hydro development are illustrated by the Snowy 2.0 project (2.2 GW / 350 GWh), which has a storage duration of approximately 160 hours. A 2017 feasibility study, completed two years before construction commenced, estimated project costs at $2.8-3.3 billion and anticipated completion in 2024-2025.

The project has since experienced significant cost overruns and delays due to tunnelling difficulties and challenging geological conditions. Following a major project reset in 2023, project costs were revised to $8 billion and completion was deferred to 2028. While further cost increases are currently under review, the project’s scheduled completion date of 2028 remains unchanged.

Overall, recent developments indicate that lithium-ion batteries are likely to play a leading role in meeting Australia’s near- to medium-term LDES requirements, while pumped hydro may remain important for longer-duration storage applications.

Conclusion

Australia is transitioning from a centralized thermal power system to a more distributed power system, with rooftop PV and batteries playing central and complementary roles. While solar PV provides abundant low-cost decarbonized electricity, batteries are becoming the critical flexibility layer enabling the integration of high shares of solar PV from both economic and technical perspectives.

This profound transformation creates both opportunities and challenges, driving the need for innovative services and policies. In these areas, Australia demonstrates strong leadership.

Access the full report here