After June’s market dynamics were shaped by a concentrated South Australian price event driven by a prolonged wind lull, transmission limitations and tight morning supply conditions, July revealed a broader and faster-moving pattern of volatility across the southern NEM.
Last month, most significant disruption was relatively localised and sustained over several days, while July was defined by sharp swings between scarcity and oversupply within the space of a week, with extreme high prices on 8 July followed by deep negative pricing from 12 to 14 July.
Both months highlight the same underlying theme: wholesale outcomes are being driven less by average renewable volumes alone and more by the timing of wind output, interconnector capability, storage availability and how these factors align with winter demand.
Southern NEM price spike on 8 July
The main price event of July occurred on 8 July, when prices surged across Victoria, South Australia and Tasmania. VIC reached $19,069.69/MWh, SA $16,970.86/MWh and TAS $17,049.64/MWh. The event reflected several factors occurring at the same time rather than a single outage or constraint. Wind generation was very low across the southern NEM, winter demand was elevated, and interconnector support into Victoria was limited.
Conditions tightened further when all six Loy Yang A and B units repriced significant volumes of generation into very high price bands because of a temporary coal supply issue. Around 1,200 MW was priced above $10,000/MWh during the evening peak.
With less support available from neighbouring regions and limited renewable output, Victoria became increasingly dependent on higher-priced local generation. The tighter Victorian supply position then flowed through to South Australia and Tasmania.
Extreme price volatility in both directions
Only five days later, the market moved in the opposite direction. Victoria fell to -$757.07/MWh on 13 July, with more than 4,000 MW of wind and solar being dispatched while network constraints contributed to generator rebidding and sharp local price movements. South Australia also experienced around 50 hours of negative pricing between 12 and 14 July as wind output increased substantially.
The contrast between 8 and 13 July was one of the clearest features of the month. Low wind and constrained supply pushed prices towards $20,000/MWh on one day, while strong renewable output and limited network capacity drove prices hundreds of dollars below zero only a few days later. July showed how quickly the southern NEM can move between scarcity and oversupply when renewable availability and transmission conditions change.
Wind conditions remained a major price driver
Wind availability continued to have a strong influence on price outcomes through July. Victorian weekly wind generation fell from 391 GWh to 171 GWh ahead of the 8 July event, while South Australian generation declined from 203 GWh to 142 GWh. This reduction in wind output was a major contributor to the higher evening prices seen across the southern regions.
Conditions then reversed quickly, with strong wind between 12 and 14 July contributing to prolonged negative pricing in both SA and VIC. Later in the month, Victoria again recorded more than 3,800 MW of wind generation during a negative-price period on 24 July. July reinforced that average renewable generation alone does not tell the full story. The timing, duration and coincidence of wind output with demand and network availability are becoming increasingly important in determining wholesale prices.
ASX forward market
The ASX forward market was much calmer than the physical spot market. Despite the 8 July spike and continued volatility in SA, longer-dated electricity futures were broadly stable through the month. NSW Cal-27 finished around $84/MWh, QLD around $74/MWh and VIC around $64/MWh, with only modest monthly movements.
The limited response suggests the market largely treated July’s volatility as event-driven rather than evidence of a sustained tightening in future supply. The 8 July event required an unusual combination of very low renewable output, constrained interconnector flows, high winter demand and temporary coal supply issues at Loy Yang.
Once those conditions eased, spot prices returned relatively quickly to more typical levels. Longer-dated pricing continued to reflect expectations around renewable build-out, battery commissioning, thermal availability and regional supply-demand balance rather than individual winter price spikes.
July 2026 NEM insights by state
New South Wales
- Average spot price of $81.52/MWh, with approximately 10.8 hours of negative pricing and 15 five-minute intervals above $300/MWh.
- $72.30/MWh difference between the cheapest and most expensive average 30-minute times of day.
- The cheapest average period was 14:30, at $44.53/MWh, while the highest was 07:00, at $116.83/MWh.
- 31.7% renewable generation through the month.
- Minimum demand of 5,742 MW.
- Peak demand of 11,480 MW, reached at 18:55 on 30 July.
- Prices were comparatively stable for most of July, with NSW largely avoiding the extreme volatility seen across the southern regions.
Queensland
- Average spot price of $65.43/MWh, with approximately 55.8 hours of negative pricing and no five-minute intervals above $300/MWh.
- $81.94/MWh difference between the cheapest and most expensive average 30-minute times of day.
- The cheapest average period was 10:30, at $20.11/MWh, while 07:00 was the most expensive at $102.06/MWh.
- 28.7% renewable generation through the month.
- Minimum demand of 3,442 MW.
- Peak demand of 8,188 MW.
- Queensland was the lowest-priced region in July and remained largely insulated from the volatility experienced further south.
South Australia
- Average spot price of $95.88/MWh, with approximately 142 hours of negative pricing and 391 intervals above $300/MWh.
- $220.98/MWh difference between the cheapest and most expensive average 30-minute times of day.
- The cheapest average period was 13:00, at $59.64/MWh, while the most expensive was 19:30, averaging $280.63/MWh.
- 57.4% renewable generation through the month.
- Minimum demand of 441 MW.
- Peak demand of 2,420 MW.
- SA remained highly sensitive to wind availability and interconnector capability.
Tasmania
- Average spot price of $71.03/MWh, with approximately 58.7 hours of negative pricing and 72 intervals above $300/MWh.
- $219.38/MWh difference between the cheapest and most expensive average 30-minute times of day.
- The cheapest average period was 14:30, at $38.10/MWh, while the most expensive was 19:30, at $257.48/MWh.
- 91.3% renewable generation through the month.
- Minimum demand of 851 MW.
- Peak demand of 1,622 MW.
- Tasmania experienced a much wider range of price outcomes in July as Basslink’s regulated operation linked Tasmanian prices more closely with Victoria.
Victoria
- Average spot price of $70.35/MWh, with approximately 109 hours of negative pricing and 85 five-minute intervals above $300/MWh.
- Victoria recorded the largest average intraday price spread in the NEM at $246.94/MWh.
- The cheapest average period was 14:00, at $33.76/MWh, while the most expensive was 19:30, at $280.70/MWh.
- 40.0% renewable generation through the month.
- Minimum demand of 4,091 MW.
- Peak demand of 9,020 MW, reached at 17:55 on 7 July.
- Victoria recorded the widest range of price outcomes during July, from -$757.07/MWh on 13 July to $19,069.69/MWh on 8 July, reflecting the large swings in wind generation and network conditions during the month.
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