​On Wednesday evening, 8 July, Victoria electricity price reached $19,070/MWh, just below the market price cap of $20,300/MWh. South Australia followed closely, peaking at $16,971/MWh.

The spike came as record winter demand coincided with a drop in wind generation to 10% of normal. Gas, coal and hydro generators stepped in to fill the gap, while batteries could only cover a fraction of the shortfall.

South Australia's highly renewable grid is known for its sensitivity to high demand and low wind conditions. Victoria is increasingly showing the same characteristics. Together, the southern states are becoming more exposed to weather-driven price volatility, while New South Wales and Queensland remain relatively insulated thanks to their generation mix and milder winter conditions.

This article explains what drove the 8 July price event, how batteries responded, and why Victoria and South Australia are increasingly experiencing these extreme price outcomes.

Executive Summary

• Victoria's daily average price reached $359/MWh on Wednesday 8 July, with an evening peak of $19,070/MWh. South Australia averaged $336 and peaked at $16,971.
• Victorian evening demand was 26% above the quarterly average while wind generation fell 94% below normal. South Australia could not provide relief, with demand running 9% above average and wind generation 81% below its benchmark.
• Pre-dispatch signalled the price spike an hour early, causing some batteries to discharge before prices peaked.
• Victorian batteries earned 17 days' worth of average revenue in just one day. South Australia saw 10x average revenue on July 8.
• Weather-driven volatility is becoming increasingly important for battery revenues. As standard spreads are cannibalised, extreme system events are carrying a larger share of battery value, particularly in Victoria and South Australia.

Wind ran at 10% of normal, coinciding with elevated heating demand

A slow-moving high-pressure system brought cold temperatures, fog and exceptionally light winds across south-eastern Australia. That combination pushed heating demand higher while suppressing both wind and solar generation.

Victoria recorded winter demand of around 9 GW on 7 July. Although demand eased slightly on 8 July, it remained above 8 GW through the evening—around 26% above the quarterly average. At the same time, wind generation collapsed to just 6% of its normal evening output.

Imports tied the two states together. Victoria imported around 1 GW throughout the evening, with South Australia supplying part of that energy. However, South Australia's own wind generation had fallen to one-fifth of its normal level. Gas generation therefore climbed above 1.9 GW to meet both local demand and exports into Victoria.

As a result, both regions relied on the same limited pool of flexible gas generation, causing electricity prices to spike simultaneously.

This was not an isolated event. It marked the lowest point of a week-long wind drought, which eastern states forecasted to see the tail end of over Friday and Saturday.

Batteries dispatched against price signals that were an hour early

Batteries followed their usual daily pattern, charging during the solar-rich middle of the day before discharging into the evening peak. However, this event rewarded precise timing.

The price spike lasted only a single half-hour trading interval. Batteries that still had charge at 7:00 pm captured most of the available value, while those that discharged earlier largely missed the opportunity.

The batteries that dispatched early largely reflected pre-dispatch. Throughout most of 8 July, AEMO's pre-dispatch forecast expected evening prices to remain between $250/MWh and $700/MWh. When forecasts eventually increased, they predicted the peak about an hour earlier than it actually occurred.

Battery dispatch followed those signals. Several batteries discharged between 4:00 pm and 5:00 pm, leaving limited energy available when prices surged at 7:00 pm. Those that waited captured the majority of the event's value.

Why Victoria and South Australia are more exposed to electricity price events

Wind makes up a greater share of electricity supply in South Australia and Victoria than in New South Wales and Queensland, in that order. As wind's share of demand falls, southern prices climb steeply, while New South Wales barely tilts and Queensland hardly moves.

Interconnection further increases this sensitivity. As transmission capacity between Victoria and South Australia expands, both regions become increasingly exposed when they simultaneously experience low wind conditions and elevated demand.

The generation mix also matters. Once wind output falls, higher-cost gas and hydro generators are more likely to set market prices than coal-fired generators, leading to much steeper price spikes.

What to watch from here

Spreads continue to narrow as battery capacity grows across the NEM, making weather-driven volatility an increasingly important source of revenue.

Victoria and South Australia are likely to experience these events more frequently than the northern states. Their higher dependence on wind generation, colder winter temperatures, and smaller coal fleets make them particularly sensitive to prolonged wind lulls.

Wind generation is forecast to recover through Friday and the weekend in South Australia and Victoria. While New South Wales and Queensland look to receive the tail end of the wind drought, their broader generation mix should moderate the impact on electricity prices.