Australia is one of the world’s largest natural gas producers and liquefied natural gas exporters, but national figures hide major regional differences. The country does not have one fully connected gas system. Western Australia and the Northern Territory are built around large offshore resources and export terminals, while the eastern market combines coal seam gas, conventional fields, domestic pipelines and three LNG export projects in Queensland.
This separation explains an apparent contradiction. Australia exports most of the gas it produces, yet manufacturers, power generators and households in the eastern states face repeated concerns about supply and price. Large offshore resources in the west cannot easily solve shortages in Victoria or New South Wales because there is no pipeline connecting the western and eastern systems.
Natural gas represented approximately 32% of Australian energy production in 2023–24. Production reached about 6,100 petajoules, more than twice the level recorded a decade earlier. Approximately 74% of domestic gas production was exported, primarily as LNG.
The LNG industry has therefore transformed Australia’s production profile. It has also tied parts of the domestic market more closely to international demand, shipping availability, oil-linked contracts and Asian gas prices.
Offshore Gas Supports the Western Export Industry
Most of Australia’s conventional natural gas resources are located offshore Western Australia. The Northern Carnarvon, Browse and Bonaparte basins contain major fields that support some of the largest LNG facilities in the Asia-Pacific region.
The North West Shelf project was the foundation of Australia’s LNG industry. It was followed by developments including Gorgon, Wheatstone and Pluto in Western Australia, Ichthys and Darwin LNG in the Northern Territory, and the floating Prelude facility offshore. These projects connect offshore wells with subsea infrastructure, processing plants, pipelines and specialised export terminals.
Western Australia’s domestic gas policy separates part of this production from the export market. Major LNG developments are generally expected to reserve gas for local consumers, with the state commonly applying a reservation target equal to 15% of LNG production. This approach has helped create a regional market with substantial gas use in mining, mineral processing, electricity generation and industry.
Natural gas accounts for more than half of energy consumption in Western Australia and a still larger share in the Northern Territory. Some of this reflects energy used by LNG plants themselves, but gas is also central to local power systems and resource industries operating far from the main eastern electricity network.
Western Australian projects are entering a period of change. Older fields supplying the North West Shelf are declining, encouraging operators to connect new resources and third-party developments to existing plants. Pluto LNG has expanded through a second processing train linked to the Scarborough gas project, while other proposals seek to maintain output from facilities that have operated for decades.
The ability to use existing terminals gives new fields access to valuable infrastructure, but these developments also face higher costs, environmental approval requirements and pressure to reduce operational emissions.
Queensland’s Coal Seam Gas Created an East Coast Export Industry
Eastern Australia developed along a different path. Conventional production from the Bass Strait, Cooper Basin and other southern regions supplied domestic consumers for many years. The growth of coal seam gas in Queensland later provided enough additional supply to support LNG exports from Gladstone.
Australia Pacific LNG, Queensland Curtis LNG and Gladstone LNG began exporting during the 2010s. Their development connected the east coast gas market to global LNG trade on a much larger scale. Gas from Queensland is now used both by Australian consumers and by liquefaction plants serving overseas buyers.
Coal seam gas is produced from coal formations by removing water and allowing methane to flow from the reservoir. Development usually requires many wells spread across a wide area, together with gathering pipelines, water treatment and compression infrastructure. Queensland’s Surat and Bowen basins contain the main producing areas.
The LNG projects supported investment in fields and pipelines that may not have been developed solely for the domestic market. However, they also created strong competition for supply. Domestic buyers now operate in a market where Queensland producers must balance export contracts, uncontracted LNG sales and Australian demand.
The east coast market is therefore affected by decisions made at the Gladstone terminals. When LNG producers have uncontracted gas, exporting it can tighten the domestic balance. Retaining it in Australia can create a larger short-term surplus.
Southern Field Decline Is Moving Supply Away From Demand
The central domestic problem is geographical. Major population and industrial centres are located in New South Wales and Victoria, but growing production is concentrated farther north in Queensland. Meanwhile, the mature fields that historically supplied southern consumers are declining.
Bass Strait production has been especially important to Victoria. As output falls, southern states require more gas transported from Queensland, additional production from smaller local fields, withdrawals from storage or another supply source.
Moving Queensland gas south is possible, but pipeline capacity, transportation charges and seasonal demand affect its availability. Winter heating demand in Victoria and other southern states can rise quickly, while gas-fired electricity generation may also increase when renewable output is low or coal plants are unavailable.
The Australian Competition and Consumer Commission has repeatedly examined whether the east coast will have enough supply in individual quarters. Its March 2026 assessment found that the market could range from a 12-petajoule shortfall to a three-petajoule surplus during the third quarter of 2026, depending partly on uncontracted LNG exports. Storage was expected to play an important role in covering winter demand.
A later government assessment concluded that a formal domestic shortfall was not expected for that quarter. This did not remove the structural concern. The balance can change according to weather, electricity demand, field performance, storage levels and export decisions.
Several LNG import terminals have been proposed for eastern and southern Australia. These facilities would receive overseas LNG, convert it back into gas and inject it into the domestic pipeline network. Importing LNG into a major exporting country appears unusual, but it may be more practical than transporting gas across the continent. Proposed locations have included Port Kembla in New South Wales and sites in Victoria and South Australia.
Gas Prices Have Become an Industrial Policy Issue
Supply uncertainty has made natural gas a significant issue for Australian manufacturers. Gas is used as both a fuel and a raw material in sectors including chemicals, fertiliser, food processing, glass, bricks, metals and paper. These users need predictable volumes and prices to make long-term investment decisions.
East coast prices rose as the market became more exposed to international LNG conditions. Government measures introduced since 2022 have attempted to improve domestic availability and limit extreme prices. These include a temporary wholesale price cap, a mandatory code of conduct and exemptions for producers that make enforceable domestic supply commitments.
The Australian Domestic Gas Security Mechanism provides another intervention option. If a domestic shortfall is forecast, the federal government can require LNG exporters to limit shipments or find additional supply. The mechanism is designed as a last resort and is assessed before individual quarters.
The ACCC reported that producer offers for 2026 supply averaged about A$13.12 per gigajoule during the first half of 2025, while retailer offers averaged A$14.33. Although prices had eased, they remained an important cost issue for energy-intensive industries.
Australia’s Gas Market Review, completed in December 2025, concluded that existing east coast regulatory tools were not sufficient to provide a durable and coordinated market structure. The government accepted 18 recommendations and began work on reforms intended to strengthen supply, transparency and affordability.
LNG Remains a Major Export Business
Australia exported 80.7 million tonnes of LNG in 2023, making it the world’s third-largest exporter that year. Japan, China and South Korea have traditionally been its most important markets, although cargoes also reach other Asian destinations.
LNG exports were worth approximately A$65 billion in 2024–25. Government forecasts published in December 2025 expected earnings to fall to about A$47 billion by 2026–27. The projected decline was driven mainly by lower prices rather than the disappearance of the industry. New supply from Qatar and the United States is expected to increase competition in the global market.
Australian LNG benefits from established projects, experienced operators and proximity to Asian buyers. Its disadvantages include high construction costs, aging fields and increasing competition from lower-cost suppliers.
Long-term demand is also uncertain. Asian economies continue to use LNG for power generation, industry and energy security, but many have committed to reduce emissions. Future Australian projects will need to demonstrate commercial competitiveness over several decades rather than relying only on current demand.
Gas Must Fit Within Australia’s Energy Transition
Gas supplied 16.2% of Australian electricity generation in 2025. Its national share is lower than coal’s, but gas-fired plants can start and change output more quickly than many coal units. This flexibility gives gas a role during peak demand, low renewable output and unexpected power-plant outages.
The federal Future Gas Strategy states that gas will remain part of Australia’s economy during the transition to net zero. At the same time, Australia has committed to net-zero emissions by 2050 and a 62–70% reduction below 2005 levels by 2035.
This creates pressure on LNG producers and domestic suppliers to reduce methane leakage, improve energy efficiency, use renewable electricity and develop carbon capture and storage. Many proposed Australian carbon-storage projects are associated with natural gas or LNG operations because raw gas can contain carbon dioxide that must be removed before sale.
The long-term direction of Australian gas will not be determined by resource availability alone. The country has large reserves and extensive infrastructure. The decisive issues will be whether new supply reaches the southern states, whether domestic buyers can secure affordable contracts, whether LNG facilities remain competitive and whether producers can operate within tighter emissions limits.
Australia will remain a major gas exporter, but its most difficult gas question is domestic: how to manage an export industry of global scale while maintaining secure and affordable supply across several disconnected regional markets.
