Australia’s East Coast winter gas market softens as volatility rises

Peak winter became the trough for Australia’s East Coast gas market in June.

The Victorian Declared Wholesale Gas Market (DWGM) cleared at A$3 (US$2.07) per gigajoule (GJ) on 18 June, its lowest price since 2016, even though it is normally the southern market’s peak-demand month. The market was not awash with gas: mild weather, lower underlying demand and battery storage reducing peaking demand created only a modest surplus, while near-full storage and a thin bid stack amplified the price fall.

Then the script flipped. The balance reversed within eight days as cold weather and a southern wind lull pulled gas back into the power mix, before a Longford outage lifted the intraday price by 57%.   June revealed a market:

• that is softer on average,
• but increasingly sensitive to weather, renewable output, outages and timing.

 

A$3 gas in peak winter

The DWGM averaged A$6.9 per GJ in June, the lowest June since the lockdown-affected 2020 and the cheapest month of 2026 to date. The winter premium had disappeared.

Figure 1: Average Victorian gas price in June across the years

 

The weakness was not confined to Victoria. Wallumbilla, in south-west Queensland, averaged A$7.4 per GJ, while the Australian Competition and Consumer Commission (ACCC) LNG netback averaged A$20.2 per GJ, nearly three times the Victorian price.

 

Figure 2: East Coast domestic gas prices against LNG netback

 

A winter that did not arrive

Slow-moving high-pressure systems brought unseasonably warm conditions to eastern Australia during the first half of June. New South Wales recorded its second-warmest June and Victoria its third-warmest since 1910. Nationally, the mean temperature was 1.5°C above the 1961–1990 average, making it the warmest June since 1996. Across our five reference stations, June averaged 13.3°C. Melbourne recorded 153 heating degree days (HDD), using an 18°C base, compared with 195 in June 2021.

As Figure 3 shows, the milder conditions coincided with the lowest southern gas demand among the years shown and a relatively low DWGM price, placing June 2026 in the warm, low-demand and low-price corner of the historical relationship.

 

Figure 3: June Melbourne cold, southern gas demand and DWGM price

 

Weather amplified a decline already underway

Southern demand fell from 50.6 petajoules (PJ) in June 2021 to 37.1 PJ in June 2026.

Our state-level HDD model attributes 3.4 PJ of decline to milder weather. The remaining 10.0 PJ was not explained by weather and comprised:

• a 6.1 PJ residual decline in gatestation demand, consistent with electrification, efficiency and other non-weather effects;
• 1.1 PJ less industrial demand;
• and 2.8 PJ less gas-powered generation (GPG).

Milder weather accelerated the decline, but did not create it. Before the temperature effect, southern June demand was already about one-fifth lower than in 2021.

 

Figure 4: June 2021 vs June 2026 gas demand in the southern states

 

Batteries take the peak

Battery discharge reached 360.7 gigawatt-hours (GWh) in June 2026, within 0.1 GWh of open-cycle gas turbine (OCGT) generation, the closest winter month in our series. In June 2021, OCGTs generated 505 GWh against 10 GWh from batteries.

 

Figure 5: Monthly power generation by OCGT and batteries discharging in NEM

 

The intraday profiles show where the displacement is occurring. Batteries now cover much of the morning and evening peaks that gas peakers traditionally served, while coal still supplied more than half of the energy on the representative days shown (Figure 6). Batteries are not yet replacing bulk energy, but they are taking the highest-value hours.

 

Figure 6: Intraday battery and gas power profiles and the power mix in July 2024 vs 2026

Using the same generation series, battery output exceeded OCGT output from November 2025 through May 2026. Average National Electricity Market (NEM) spot prices during those months ranged from A$53 per megawatt-hour (MWh) to A$77 per MWh (Figure 7). The pattern is consistent with batteries reducing the frequency and duration of high-price periods, weakening the economics of gas peakers and reducing routine gas demand from the power sector. However, batteries cannot eliminate the need for gas during sustained periods of cold weather and low renewable output.

The displacement of gas-fired generation by batteries is therefore unlikely to continue at the same rate. As coal-fired capacity retires, batteries will increasingly cover short-duration peaks, but the NEM will still require dispatchable capacity to manage longer periods of weak renewable output. Some of that requirement is likely to be met by new gas-fired generation alongside longer-duration storage.

 

Figure 7: Spot price against battery-to-OCGT ratio

 

The south came close to balancing itself

Southern production has declined since 2022, but demand fell faster in June 2026. Local production of 30.8 PJ met 83% of southern demand and covered the full requirement on three days in mid-June.

That left unusually little work for the two swing sources that normally support the southern winter. Queensland imports via the South West Queensland Pipeline (SWQP) totaled 3.9 PJ, and Iona supplied a net 2.6 PJ. Combined swing supply was 6.4 PJ, against 16.2 PJ in June 2025 and 16.9 PJ in June 2024, the lowest of the eight Junes in our analysis.

 

Figure 8: Southern June monthly balances across the years

Iona entered winter at its highest starting inventory on record. It was still injecting on 18 June and remained within 1% of its all-time peak when the DWGM fell to A$3 per GJ (Figure 9). With storage nearly full and demand weak, producers had limited outlets for marginal gas, increasing pressure to lower offers or reduce injections.

 

Figure 9: Iona cumulative net injections over the years

Queensland LNG feedgas reached 110.7 PJ, the highest June on record, while year-to-date intake remained broadly in line with recent years. The market absorbed the stronger June draw without a material price response.

 

A surplus amplified by a thin market

The physical surplus alone does not explain the nine-year low in prices. We measure depth as Victorian injection bids priced within A$1 per GJ of the last scheduling-horizon price. In June, the monthly median was 25.5 terajoules (TJ) per day, down from 41.3 TJ per day in May and 101.1 TJ per day in August 2025, the nearest complete winter comparator. It was the lowest complete month in the 12-month window.

 

Figure 10: Victorian injection bid volume within ±A$1 per GJ of the final schedule market price

The thin stack was partly a consequence of the loose balance, not a separate cause. Weak demand and limited outlets pushed the clearing point into a sparsely populated part of the bid stack. The surplus created the conditions, and limited depth amplified the price response.

 

Eight days from floor to winter

The late-June reversal showed where the battery effect ends.

From the low point of Thursday 18th June 2026, over the following 4 days (19th June, 20th June, 21st June and Monday 22nd June 2026) southern gas demand rose by 704 TJ per day to 1,733 TJ per day. GPG accounted for 445 TJ per day, or 63%, of that increase as colder weather coincided with a wind lull across southern NEM regions. The Australian Energy Market Operator (AEMO) recorded the quarter’s highest daily gas-fired generation on 22 June, while gatestation demand added another 241 TJ per day.

 

Figure 11: June-July 2026 daily southern gas balances

The supply system had to respond quickly. Iona moved from injection to withdrawals of 363 TJ per day, and southbound SWQP flows roughly doubled to 282 TJ per day. GPG demand remained elevated through 26 June, when the DWGM beginning-of-day price reached A$12 per GJ. One weather system created June’s surplus; the next removed it through two channels, higher heating demand and a renewed call on gas from the power market.

 

Longford exposed the other side

A power-generation issue at Longford at 8:30 AM on 28 June led to a full plant outage, with flows stopping around 10:40 AM. Longford supplied 180 TJ for the day, about 400 TJ below its June average.

The A$9.01 per GJ beginning-of-day price had been set before the event. The 10 AM schedule, set before flows ceased, was little changed at A$9.19 per GJ. The first standard schedule after the full loss of Longford cleared at A$14.15 per GJ at 2 PM, a 57% rise and the highest schedule price in the 1 June–27 July data window. Prices remained above A$13 per GJ through the final two schedules.

AEMO maintained gas stored within the eastern pipeline network, increased Iona injections and commenced southwest flows. It did not identify a supply threat, although the following day’s balance remained tight. The repricing showed how quickly a material shock could travel through a market with limited depth around the clearing point.

 

What June means for the next winter

Barring a major outage or sustained cold spell, we expect the southern market to remain relatively well supplied through the rest of 2026. Lower underlying demand and continued battery growth should keep average gas demand below historical levels and support the seasonal storage rebuild.

June 2026 nevertheless showed both sides of the market’s sensitivity.

• Mild weather, high storage and weak demand pushed prices to A$3 per gigajoule.
• Ten days later, the Longford outage lifted the intraday price to A$14.15 per GJ.

Southern production is forecast to decline further by next winter. Short-duration batteries will continue to displace gas peaking, but cannot cover prolonged periods of cold weather and low renewable output. A similar outage in a colder balance could therefore have a larger and more persistent effect.

June 2026 was not evidence of a structurally cheap market. Rather, it showed:

• a market with lower average demand, less physical slack than the headline surplus suggested and
• growing sensitivity to weather, outages and timing.

 

Editor’s note – this article was originally published on 29th July 2026 in the Rystad publication ‘Australia Oil & Gas Analytics’.  Following Krishan’s presentation at the Rystad Energy Brisbane Briefing on Tuesday, 11 August 2026, Krishan agreed to also publish this article here for WattClarity® readers.

 

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