To kick off this Wholesale Market Update, we’ll take a look at the spot price outcomes across the NEM for the summer quarters of Q4 2024 and Q1 2025.
Starting with Q4 ‘24, we can see from the chart on the left – which shows the spot price outcomes in each of the states – that New South Wales and Queensland, and to a lesser extent Tasmania, saw very strong price outcomes.
The middle chart shows the 90-day average of the ASX closing price for the Q4 and Q1 contracts, leading into quarters. All three states of New South Wales, Queensland and Tasmania clearly outperformed market expectations for Q4 ‘24 based on contract trading levels.
Q1 ‘25 was a different story, with more subdued prices across the mainland, which were all below contract prices coming into the quarter. Tasmania was the exception in Q1, the spot price out-turning around double the price where swap contracts were trading into the quarter.
The final chart here takes a look at cap payouts across the states – which is the component of the average spot price made up of prices above $300/MWh.
Clearly, the high Q4 prices in Queensland and New South Wales arose from volatile price outcomes over a few days across November-December. In Tasmania, on the other hand, volatility was low, and the high average price came from consistently strong spot prices, rather than volatile price events.
To look at some of the drivers of the spot price dynamics, we now turn to some aspects of the supply and demand balance across summer.
The charts here look at the spread of the highest daily demand outcomes across the states, showing the minimum, average, and maximum across the quarters.
In New South Wales, while there were more days at higher demands in Q1 compared to Q4, Q4 did have a higher maximum demand day compared to Q1, no doubt contributing to the high price events seen in this quarter. In general though, demands were stronger in Q1 compared with Q4 across all the states.
In NSW, while there were more days at higher demand in Q1 compared to Q4, Q4 did have a higher maximum demand day compared to Q1 – no doubt contributing to the high price events seen in this quarter. In general, demand was stronger in Q1 compared with Q4 across the other states.
Moving to the supply side, the top charts show monthly average generation, and availability, across the Coal fleets in New South Wales and Queensland and Hydro units in Tasmania. We can see that November in particular was the low point for coal plant availability, which resulted in higher output from gas plants.
Along with higher demands, this contributed to the higher prices seen in Q4. In Q1, better unit availability led to more subdued outcomes.
The exception of course was Tasmania – demands were slightly lower in Q1 compared to Q4. But despite higher average availability, Hydro output was down quarter on quarter. While gas replaced some of this generation over evening peaks, there was a strong uptick in energy imports from the mainland via Basslink, taking advantage of the lower prices in Victoria.
The mix of outcomes across summer has seen some subdued pricing dynamics in the forward contracts. Taking a look at the Financial Year ‘26 contracts, prices did increase through Q4 – particularly in New South Wales and Queensland – with higher-than-expected spot price outcomes and volatility throughout this quarter.
Despite weaker outcomes, Victoria contracts also increased with the market still pricing-in risk premiums from the future winter quarters.
Since mid-Q1 2025 contract prices have moved somewhat sideways, with the weaker outcomes in Q1 competing with market views on potential upside risk in winter based on the last few years’ outcomes. Market participants will be keenly watching the outcomes of this winter to see what will drive prices moving forward.
Last summer in the gas market was driven by low domestic gas demand, high power market volatility, and the impacts of Tropical Cyclone Alfred.
A warm end to last winter, combined with lower residential consumption overall, led to reduced southern market demand, prices reaching a low of $9.60/GJ.
In November and December, reduced coal generation availability led to high gas consumption in gas generation units. Consumption was particularly high in QLD and NSW, with the Brisbane price reaching over $21, whilst the Victorian price remained below $15 – an indication of pipeline constraints to transport gas from the southern markets.
Late February, Cyclone Alfred impacted shipping off the QLD coast, before making landfall in Brisbane. In early March, a week of high temperatures in Gladstone led to reduced LNG plant efficiency, contributing to increased domestic market supply, and lower prices.
An interesting observation was the increase in the premium of the northern market over the southern market, the price differential approaching the cost of firm pipeline transportation at over $1.80/GJ. The average price across the summer was just over $12/GJ in the south, and just under $14/GJ in the north.
Two dynamics continued to play out in gas generation as the renewables build-out in the NEM continues: the increasing flexibility of required capacity and the general reduction in annual gas consumption.
Looking at the left-hand chart, there were two examples of increasing flexibility: the first in mid-December when gas covered for unplanned coal outages and the second in February where gas ramped from 100TJ/d to over 500TJ/d multiple times in the same month.
The second dynamic is the general trend in the reduction of energy consumed on an annual basis, with just over 100PJ consumed in 2024, as seen in the right-hand chart.
Now let’s analyse demand across the three main segments – LNG, Domestic Demand excluding GPG, and then GPG – looking at the last few years as compared to the trailing 8 years.
LNG demand was high, with December 2024 setting a record for the highest LNG demand since plant commissioning.
Domestic demand excluding gas for power generation continued to trend lower, with a new record low set for August which continued through the end of 2024, driven by a mild end to winter and continued signs of residential demand destruction.
Finally, gas demand for power generation was generally lower, with Q1 gas volumes on average around 200TJ/d, particularly low for summer.
The Iona underground gas storage facility ended last winter with nearly 12PJ in storage, 7PJ less gas than at the end of winter 2023.
Interestingly, nearly one PJ of gas was injected in August, reflecting a warm end to winter in Victoria, and an early start to facility injections.
Despite strong withdrawals across winter, Iona tracked mostly sideways in Q4. In Q1, low domestic demand supported over 10 PJ of gas injections to storage, taking Iona to over 95% full.
Iona is now well prepared to again support the domestic market should large withdrawals be required this winter.
With respect to forward prices, the ACCC LNG Netback price, shown on the graph in red, is in backwardation out to May 2027. Prices have fallen recently off the back of bearish market fundamentals driven by reduced demand forecasts due to the impacts of US tariffs. Prices are around $16/GJ for the next couple of years.
Domestically, the futures market is pricing Wallumbilla at a multiple dollar discount to LNG netback, with very little seasonal differential between summer and winter, or between 2025 and 2026.
On the other hand, in 2026, Victorian futures are pricing in about $3/GJ of winter to summer premium, and over $2/GJ of south to north premium, reflecting the continued decline of southern gas production.
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