Spot prices remain low while future uncertainty increases
Lower levels of volatility and plenty of renewable generation resulted in average spot prices during February 2026 being lower than they were a year ago across the National Electricity Market (NEM). Prices in South Australia fell compared January this year, with the average price down 64%.
Queensland, New South Wales, and Victoria saw increases in average price month-on-month, however prices are still low compared to expectations prior to the start of the quarter. Compared to whole of quarter (Q1) average price expectations at the end of 2025, current prices for Queensland are down 20%, New South Wales down 24% and Victoria down 27%.
The conflict in the Middle East (which started at the end of February) has disrupted global oil and gas supplies and led to a sharp rise in the price of these commodities. While oil has a limited direct impact on electricity prices in Australia, its indirect impact on gas prices and the disruption of gas supplies are of more direct importance. Qatar is a leading exporter of liquified natural gas (LNG) with approximately 20% of the world’s LNG trade shipping through the Strait of Hormuz prior to the conflict. Many gas contracts are priced in relation to the price of oil, so the rise in the Brent oil price from $68 USD/barrel at the start of February to over $100 USD in March will likely have a direct impact on many gas contracts.
Electricity futures prices have mirrored the volatile oil price, although the magnitude of change is smaller. Futures prices fell for three consecutive months from late 2025 on the back of low spot prices and have now regained most of this fall on the back of recent global uncertainty, despite spot prices remaining relatively low. Should conflict expand or extend there may be ongoing global energy disruption and further upward impact on Australian energy prices.
Domestic coal and gas prices remain relatively stable
During the 2022 energy crisis, the market felt the effects of the combined impact on gas and coal prices. Unavailability of gas can lead to ‘fuel-switching’ where countries can rely more on coal, driving up the price of this commodity alongside increasing gas prices.
Australia is a significant global exporter of black coal and LNG, with the price in the domestic market being increasingly exposed to movements in the international price of these commodities.
Australian export coal is priced in reference to the Newcastle Coal price, with Newcastle being the largest export port. Black coal, used by generators in Queensland and New South Wales, is still the largest individual source of electricity generation across the NEM, and the rise in the price of this commodity, alongside gas, was a driver of high electricity price in 2022.
Since the start of the conflict at the end of February, the Newcastle Coal price for April has risen from $120 USD to $142 USD per tonne, well below the heights it reached in 2022, where it got to $420 USD/tonne. It remained around this level until the end of 2022. The current price is close to the prices for Newcastle coal during 2023 and 2024. The current muted response in the black coal price suggests a markedly different outlook than 2022 for underlying electricity prices.
The Australian Competition and Consumer Commission (ACCC) calculates an ‘LNG Netback’ price which is used to reference domestic gas prices and assess the prices charged to domestic consumers relative to international prices. The LNG netback price is roughly the international gas price minus the cost of pipeline transport, compression, shipping, and delivery of gas from Australia.
The latest update showed an increase in the LNG netback price from around $13/GJ to $20/GJ. This is around half the price at the same time in 2022 and less than a third of the peak price seen in 2022. The actual spot price of gas in the two east coast markets (the Victorian Declared Wholesale Gas Market, DWGM, and the South Australia, New South Wales, and Queensland Short Term Trading Market, STTM) has been around $10/GJ, within the usual trading range.
While the domestic price of these two commodities remains within normal expected trading conditions, any extension of conflict or further disruption to international energy markets may see pressure flow into the local market. Lessons from the 2022 energy crisis will likely help to shield Australia from similar impacts, particularly as they relate to the electricity market.
Gas storage healthy ahead of winter
The key gas storage facility on the east coast is the Iona underground storage facility in Southwest Victoria. This seasonal storage is generally filled from late spring through to mid autumn and used through the colder months to meet heating demand and increased electricity generation demand.
As of mid-March this storage is 91% full and on track for full storage ahead of winter. Traditionally this storage peaks around April/May and reaches a low point around August/September. A key risk is if the storage at Iona begins to draw-down too early or too sharply early in the winter period as this raises a significant risk of running too low by late winter.
Faster draw-down can occur due to local supply disruptions, outages of coal generators which require greater use of gas-fired electricity generation, or a colder than usual winter. None of these factors appears to be an issue at this time, but will be factors to keep an eye on as we move towards winter.
Planned generator availability high during Autumn
Autumn is a shoulder season for demand in the NEM, with lower risk of heat waves and before heating load increases moving into winter. Historically this period has been utilised by coal generators to do long maintenance outages. As of mid-March there is relatively little planned generator maintenance through the next 3 months, indicating a very high expected availability of generation.
While there is often unplanned maintenance required, especially as the coal-fired generation fleet in the NEM ages, a starting point of high expected availability suggests that gas-fired generation demand in the NEM is likely to be at or below usual levels given that greater gas generation acts as a substitute when coal plant is unavailable. Particularly as we move into the winter months with higher expected electricity demand, generator availability will be a key risk measure to watch in relation to high prices, with high prices in June 2025 driven by generator outages alongside very cold and still weather.
Summer heatwave risk appears over
Summer has concluded with relatively few high price periods despite several days of very hot weather and very high electricity demand. The likelihood of further very hot weather has now diminished significantly as we move into autumn.
Despite this, the Bureau of Meteorology (BOM) is predicting a much higher than usual likelihood of warmer and drier than average conditions over the next three months for the entire east coast. The exact impacts are difficult to predict, but generally this is likely to translate to higher solar generation output (less cloud cover), lower heating demand, and less inflows into hydro catchments.
Weather in Australia is driven by many climate indicators. Of note is that sea surface temperatures during February were the 10th warmest on record in the Australian region, and third warmest for the global average.
Changes in forward contract prices for CY26
Forward contract prices for Calendar Year 2026 were steady from the end of January through to the end of February for all states, remaining significantly below the level from 12 months earlier.
Futures prices have since risen on the back of energy uncertainty arising from the Middle East conflict, with 2026 price expectations rising between $5 and $13 by mid-March. While this takes futures prices for 2026 and 2027 back to similar levels at the end of 2025, there is significant uncertainty in these values going forward.
| State | February 2025 | January 2026 | February 2026 |
| NSW | $118.70 | $90.88 | $91.82 |
| QLD | $100.79 | $75.84 | $74.19 |
| SA | $96.12 | $87.31 | $87.00 |
| VIC | $75.25 | $65.85 | $65.83 |
February 2026 NEM insights by state
New South Wales
- Average spot price of $83.76/MWh, with 29.5 hours of negative prices and 4.4 hours above $300/MWh
- $256/MWh difference in average 30-minute spot prices at the cheapest and most expensive times of day
- No daily intervals with an average negative price over the whole month
- 42% total renewable generation through the month
- Minimum demand of 5,426 MW
- Peak demand of 13,056 MW
Queensland
- Average spot price of $69.87/MWh, with 52 hours of negative prices and 35 minutes above $300/MWh
- $100/MWh difference in average 30-minute spot prices at the cheapest and most expensive times of day
- No daily intervals with an average negative price over the whole month
- 39% total renewable generation through the month
- Minimum demand of 5,168 MW
- Peak demand of 10,965 MW
South Australia
- Average spot price of $56/MWh, with 195 hours of negative prices and 4.4 hours above $300/MWh
- $238/MWh difference in average 30-minute spot prices at the cheapest and most expensive times of day
- Average spot price was negative or very close to zero between 9:15 AM and 2:35 PM
- 88% total renewable generation through the month
- Minimum demand of 168 MW
- Peak demand of 2,814 MW
Tasmania
- Average spot price of $90.28/MWh, with 15 minutes of negative prices and 35 minutes above $300/MWh
- $25/MWh difference in average 30-minute spot prices at the cheapest and most expensive times of day
- No daily intervals with an average negative price over the whole month
- 100% total renewable generation through the month
- Minimum demand of 747 MW
- Peak demand of 1,212 MW
Victoria
- Average spot price of $45.06/MWh, with 143 hours of negative prices and no prices above $300/MWh
- $73/MWh difference in average 30-minute spot prices at the cheapest and most expensive times of day
- Average spot price was negative on average for only 2 five-minute intervals around 2pm
- 48% total renewable generation through the month
- Minimum demand of 2,402 MW
- Peak demand of 8,892 MW
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