Queensland's negative prices did not take winter off: August 2026

Energy Data Hub · Source: AEMO TRADE; calculations by Energy Data Hub · 2026-08

What the data shows

Queensland recorded 1,028 negative-price five-minute intervals in August 2026, out of 8,928. That is 85 hours and 40 minutes, or 11.5% of the month. This measures time, not the share of electricity sold below zero.

The regional comparison is the interesting part. In the same month New South Wales was at 2.3%, so Queensland spent about five times as long below zero. Victoria (10.7%) and South Australia (13.8%) were in a similar range to Queensland, but those two regions have far more wind in the mix. Queensland reached that level in the middle of winter with a much more solar-driven system.

The trend is already turning up. September came in at 16.6%. Last spring Queensland was at 30.6% in October 2025 and 28.6% in November. The low point of the past year was June 2026, at 2.3%.

The timing is very consistent. Across the twelve months to September 2026, all but one negative Queensland interval fell between 5am and 6pm AEST, measured by interval-start hour. The exception was in the 2am hour. Between 10am and 2pm, about 43% of all intervals were negative. After 6pm there were none.

Why Queensland (my view)

Price data tells you when negative prices happen, not why. What follows is my interpretation from generation and retail perspectives, not a reconstruction of individual bidding decisions.

The timing points straight at solar. Queensland has one of the highest rooftop solar penetrations in the country, and that solar does not show up as supply in the market. It shows up as missing demand. Operational demand falls through the middle of the day while utility-scale solar is at full output.

The supply side matters just as much. A coal unit cannot cheaply switch off for four hours and come back for the evening peak. Restarting costs money, adds wear and carries the risk of not being available when prices are high. So it is often rational for a thermal unit to bid below zero to stay above its minimum stable level. Grid-scale solar can also keep generating at moderately negative prices, as long as its certificate revenue covers the loss. Put those together and you get a market where nobody wants to be the one who leaves first.

Winter does not fix this in Queensland the way it does further south. The sun is still strong and heating demand is mild, so midday demand does not recover much. This is one possible contributor to Queensland’s double-digit negative time in August, but confirming its importance relative to New South Wales requires demand, weather and generation data.

What it means for retailers

Falling averages make the wholesale picture look better than it is for a retail book. Queensland's average spot price in August 2026 was A$60.42/MWh, against A$78.20 in August 2025 and A$130.10 in August 2024. That is a real decline in the time-weighted average, but it does not measure the relief for a retailer serving households.

The reason is load shape. Residential grid demand is at its lowest in the middle of the day, exactly when prices are negative, and at its highest in the 5pm to 9pm ramp. A retailer's wholesale cost is load-weighted, so negative midday hours can pull down the time-weighted average more than the cost of serving a household. The size of that difference needs interval customer-load data. For the volume matched by a fixed-price swap using the same spot reference, the swap settlement offsets the spot-price movement. Net exposure still depends on the hedge volume, customer load and contract terms.

The Solar Sharer Offer adds a new angle. From 1 July 2026 it became available to eligible smart-meter residential customers in south-east Queensland. Retailers with more than 1,000 customers across DMO regions must offer it; customers opt in. The first 24 kWh in the daily 11am–2pm window is free, with excess use charged at the applicable reasonable-use rate. Supply charges and controlled-load usage are separate. See the AER’s consumer guidance.

For the retailer, free customer usage does not eliminate wholesale, network or other supply costs. Negative spot prices can reduce the wholesale component, but the whole-month negative-time share does not measure the average wholesale cost of the 11am–2pm window. Network tariffs, customer usage and hedging would need to be modelled before concluding which component dominates in winter.

What it means for developers and storage

For a solar project selling into the spot market without storage, the trailing-year profile is stark. In its best production hours, roughly four in ten intervals between 10am and 2pm were negative. This is a time share, not an output-weighted measure for a solar project. Curtailment strategy and negative-price clauses in the PPA therefore deserve attention alongside the average price.

For storage, the chart is close to the investment case in one picture: a deep negative window in the middle of the day and no negative prices at all after 6pm. A time-share indicator is not a revenue estimate, but it shows clearly where the opportunity sits.

What to watch

October will be the first real test. My testable expectation is that October’s negative-time share will exceed September’s 16.6%; last October’s 30.6% is a useful comparison. A higher or lower result alone will not identify solar growth, storage or tariff effects: weather, demand, outages and interconnector conditions also matter. Solar Sharer uptake is worth tracking separately; this dataset does not measure it. Both questions can be checked on this site as the data arrives.

Data and version

This article is pinned to the August 2026 Queensland source checked on 1 October 2026. Regional and monthly comparisons use this site's negative-price indicator for October 2025 to September 2026. Average prices are AEMO's published monthly AVGRRP. Sections marked as my view are interpretation, not findings from the price data.