Gas continues to play a central role in Australia’s energy transition - supporting domestic supply, enabling exports and economic growth, and providing critical firming capacity as renewable generation scales.
Domestic landscape
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East Coast
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West Coast
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Market Overview |
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Queensland anchors East Coast production, while declining southern production will deepen reliance on northern gas (including storage and transport) and possibly imports. |
AEMO’s 2025 WA Gas Statement of Opportunities (GSOO) shows a broadly balanced near term, contingent on new supply (including Scarborough) from the second half of 2026. Forecast supply gaps will grow from 2028 and beyond if projects slip further and reserves are downgraded. |
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Investment Trends |
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Shifting to upstream development in new acreage in Queensland and Northern Territory (eg Taroom Trough & Beetaloo Basin), pipelines to connect northern production to southern demand, gas storage and gas-fired peakers to support the energy transition. |
A tightening supply outlook and increased domestic gas needs are improving project economics for reliable, near-term local supply, further supported by the need for gas-fired generation to replace aging coal-fired generation. This provides power system reliability and firming as renewable generation and battery storage penetration increases in the South-West interconnected system and address peak day gas demand shortfalls that are forecast from 2029. Those forecast requirements for gas-powered generation may also give rise to potential pipeline constraints arising from 2029. |
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Trajectory |
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Forecast gas shortfalls recently pushed out to beyond 2030 due to delays in coal-fired generation retirements and rollout of batteries. |
Gaps widen from 2028 with annual supply gaps forecast potentially through to 2045 and beyond as gas powered generation becomes more seasonal and amidst possible declining production from existing and committed gas fields. |
Influence of international markets
Escalation of the Middle East conflict has significantly impacted trade through the Strait of Hormuz and curtailed LNG supply to international markets. Australia’s self-sufficiency has kept us relatively protected against geopolitical shocks (particularly for gas) and domestic gas prices are the lowest they have been in years as reported in the AFR. East coast spot gas prices have remained subdued at about A$9-$10.75 per gigajoule, though prices are likely to rise materially if disruption persists.
Bottom line, investment challenges and opportunities
Gas remains critical to Australia’s economy, with about 90% of domestic consumption supporting key industries, supplying one-fifth of the nation’s energy needs and generating about A$65b in annual export earnings. The Middle East conflict has heightened price and energy security risks.
For investors, the opportunities are where capital can solve east coast deliverability constraints or back tightening west coast sources of supply and potential gas pipeline infrastructure constraints, or to meet anticipated higher gas-powered generation peaks as coal retires, particularly in the context of reserve capacity mechanism support.
On the east coast, that means backing upstream development, as new plays such as Beetaloo and Taroom emerge, transport to move northern gas into southern deficit markets and storage. In Western Australia, tightening supply and higher prices are already improving project economics and reviving assets that once looked marginal.
Capital investors must price more than complex geology as policy risk, potential new levies on gas producers and the broader interventionist direction of recent reforms (such as the recently announced gas reservation scheme discussed below) also bring risks to investments. The strongest investment opportunities combine supply access, infrastructure and regulatory resilience, solving both security of supply and system reliability issues.
We discuss Australia's gas market in our Power Perspectives podcast.
Reserving the future
Australia’s proposed national gas reservation scheme is being developed against a backdrop of rising domestic and international energy costs, declining production in southern states and increasing geopolitical risk, including global LNG disruptions linked to the Iran conflict.
What Australian markets are affected by the new scheme?
The new scheme is national in scope and no exporter is exempt. While the west coast has experienced a domestic reservation of 15% for the past 20 years, the east coast and northern Australia have operated without any equivalent obligation. Therefore, the scheme is more relevant to the east coast market given emerging shortfalls, export projects not located near southern centres and no historical reservation policy.
In Victoria, gas reserves are steadily depleting. AEMO indicated that without new supply, a structural gas shortfall could occur from 2029. How Victoria will access gas reserved under the scheme remains uncertain.
Interestingly, emerging projects such as Beetaloo would be subject to the new 20% domestic supply requirement on any future LNG export production. With Tamboran Resources targeting first Beetaloo gas sales later this year and APA Group progressing pipeline infrastructure to connect the basin to the east coast grid and Darwin, how the scheme interacts with these developments as they progress toward LNG export also remains a live question.
What is the scheme seeking to achieve?
The scheme is intended to reduce gas costs for consumers and may create new opportunities across the gas sector, including in power generation and customer supply. It aims to ensure that a sufficient portion of domestically produced gas is available to support key industries, such as manufacturing, address cost-of-living pressures, and potentially reduce pressure to increase taxes on gas exports.
Following months of consultation with industry, the Government confirmed the key features of the scheme on 7 May 2026. A draft Design Framework has since been developed and was released on 26 May. The government is inviting interested stakeholders to provide feedback on the draft Design Framework, which outlines how the reservation scheme would operate.
Under the draft Design Framework, LNG exporters will be required to supply (rather than merely offer) a volume equal to 20% of their total exports to the domestic market, commencing on 1 July 2027. Export contracts entered into before 22 December 2025 will be honoured, allowing exporters to meet their existing commitments. However, the protection for pre-existing contracts is subject to the exporter demonstrating that there is no viable alternative to meet the domestic supply obligation other than breaching those contracts. As such, it does not appear that exporters will automatically receive an exemption for pre-existing contracts if there are alternative ways to achieve domestic supply (such as purchasing third-party gas).
The scheme will replace the ADGSM and the voluntary Heads of Agreement and reform the Gas Market Code. The Government has described this as a historic shift in domestic gas market settings, creating a single national domestic supply obligation and offering greater certainty to the local market.
LNG exporters seeking access to the international spot market will need to demonstrate to the Minister that they have actually supplied the domestic market to obtain an export approval.
The design of the scheme will be critical to ensuring that…
Further, given that the export contracts entered into before 22 December 2025 are preserved, the impact of the scheme on domestic gas supply in the short to medium term is unclear. The Government has confirmed the scheme applies to the spot market and prospective (uncontracted) gas, meaning its impact will increase as existing long term LNG contracts expire.
All participants in Australia’s gas market are highly interested in the final design of the scheme.
