Battery storage across Australia’s National Electricity Market broke its own discharge record for at least the second time in two weeks on 11 August. The same fleet’s revenue per megawatt has been falling even faster than its capacity has grown.
On 11 August, battery discharge across Australia’s National Electricity Market reached 4,325MW at 18:25, according to analysis published by Geoff Eldridge of energy consultancy Global Power Energy, eclipsing the previous all-time high of 4,131MW set just eleven days earlier, on 31 July. At the same interval, batteries supplied 14.42% of NEM electricity consumption, also a record. Both figures matter less as one-off milestones than as the latest entry in a run that has seen the NEM’s battery discharge record broken repeatedly through the year, a pattern corroborated independently by Open Electricity’s live NEM records tracker, which lists 11 August as the most recent in a string of “highest ever battery discharge” updates recorded since January.
The day’s records extended beyond the national aggregate. New South Wales set its own discharge high of 1,776MW at 18:00, with batteries meeting 16.93% of the state’s consumption at that moment. Victoria had already set a charging record of 1,383.6MW at 12:05 that same day, beating the 1,360.2MW mark set in May. Eldridge’s analysis frames the more revealing number as the swing between those two extremes: NEM-wide charging approached 4,000MW around midday, equivalent to about 11.3% of consumption, while renewable generation and storage output reached roughly 70% of demand and curtailment peaked near 2,369MW. Moving from close to 4GW of charging around noon to more than 4.3GW of discharge by evening is an intraday operating range of about 8.3GW, a figure that says more about how hard the fleet now cycles than about how much energy it ultimately supplies.
The year-on-year comparisons are what give the daily figures their weight, and they are corroborated by AEMO’s own published data. NEM battery discharge on 11 August was up 111% on the record that stood a year earlier; NSW discharge was up 212%; Victorian charging was up 86%. Those growth rates track closely with what AEMO’s Quarterly Energy Dynamics reports have shown building through 2026: average battery discharge nearly tripled year-on-year in both Q1 (359MW versus 98MW) and Q2 (476MW versus 162MW), while peak discharge records climbed in successive steps, from 3,556MW in January to 3,759MW in June, 4,131MW in July, and now 4,325MW in August. The pattern is not a single extreme day. It is a fleet whose ceiling keeps moving because its installed base keeps moving with it.
That installed base has expanded faster than most other parts of the grid. Australia’s NEM connected 9.1GW of new generation and storage to full output in the 2026 financial year, more than double the FY25 result, according to AEMO’s quarterly connections scorecard, with battery projects accounting for the largest share of that build. Battery storage now represents 52% of the 75.4GW NEM connections pipeline, ahead of solar-plus-storage hybrids at 18% and onshore wind at 15%, and grid-scale battery capacity passed 9,000MW for the first time in the second quarter. The growth has been enough to make Australia the world’s third-largest utility-scale battery storage market, behind only the US and China, with 4.3GW of large-scale systems reaching financial close in 2025 alone.
What that expansion has done to wholesale prices is the more consequential story for anyone financing the next tranche of projects. NEM-wide battery price spreads, the gap between what batteries pay to charge and earn to discharge, fell 85% in a year to average AU$51/MWh (US$35/MWh) in the second quarter, down from AU$342/MWh a year earlier. Estimated net battery revenue fell over the same period from AU$130.5 million to AU$57.5 million, with net arbitrage revenue specifically down 56% to AU$52.8 million as gross energy revenues dropped AU$44.5 million even as charging costs rose AU$23.6 million. Volume-weighted discharge prices fell from AU$427/MWh to AU$101/MWh. Victoria absorbed the largest share of that decline, down AU$32.7 million, followed by South Australia and New South Wales; Queensland’s comparatively modest AU$4 million decline was flattered by a late-June price event that briefly pushed South Australian prices to the AU$20,300/MWh market cap. The mechanism compressing those margins is the fleet’s own success: as more batteries compete to charge cheap and discharge expensive, the price difference between those two moments narrows, which is precisely what a larger fleet is built to exploit.
Batteries set prices in 46% of dispatch intervals during the evening peak in the second quarter, up 24 percentage points from the year earlier, displacing gas as the dominant price-setting technology in those hours; gas-fired output averaged just 1,050MW across the quarter, its lowest second-quarter level since 2003. That is the transition working as intended. It is also the reason revenue per unit of capacity keeps falling for the assets doing the displacing. Owners have responded by pushing revenue toward services that sit outside the energy market altogether. Grid-forming inverters, which supply the synthetic inertia and system-strength support the grid needs as coal retires, now feature in around three-quarters of the battery pipeline, and FCAS revenue, though down 51% in absolute terms alongside the broader price collapse, has grown as a share of total battery income. Long-term contracts under the Capacity Investment Scheme and state-level agreements have moved from what one industry panellist at the Australian Clean Energy Summit called a “nice to have” to what she termed “almost a precondition” for financing new projects, a shift that effectively caps how much of any battery’s return can still come from trading the market on its own.
Squadron Energy chief executive Rob Wheals used the same Sydney summit to argue that the records being set this year describe only part of the technology mix the grid will ultimately need. His company’s modelling, he said, shows a NEM built purely on solar-based hybrids would require five times as much infrastructure to meet demand reliably: “You cannot build a whole electricity system purely on solar-based hybrids.” The argument is not disinterested. Squadron, Australia’s largest renewable energy investor by operating capacity, holds one of the NEM’s biggest wind portfolios through its CWP Renewables and Windlab acquisitions and has separately sought planning approval for a gas-fired firming plant to back its own wind and solar projects, giving its chief executive a direct commercial stake in investment signals broadening beyond the solar-and-battery combination that has dominated recent connections data. That does not make the underlying point wrong. AEMO’s own Integrated System Plan calls for 35GW of short- and medium-duration storage plus a further 5GW of long-duration capacity by 2050, and the fleet setting records this month is still overwhelmingly the short-duration, one-to-two-hour variety built for daily arbitrage rather than the multi-day storage the plan also assumes.
The 11 August numbers capture a fleet doing exactly what it was designed to do, absorbing midday solar that would otherwise have been curtailed and returning it during the evening peak, at a scale that would have been difficult to credit a year earlier. They also capture a fleet whose reward for doing so is shrinking with each quarter that its own scale grows, a dynamic already visible in AEMO’s revenue figures and showing no sign of reversing while capacity additions keep outpacing the price signals that justified the first wave of investment. The next stage of the buildout, on the current numbers, looks less like more of the same and more like a market that has to find new reasons, beyond the arbitrage spread, for batteries and other technologies alike to get built.
