Australia occupies two very different positions in the global hydrocarbons market. It is one of the world’s major liquefied natural gas exporters, supported by large offshore gas fields and coal seam gas developments. At the same time, its domestic crude oil production is declining, and the country relies heavily on imported crude oil and refined fuels.
This contrast defines the Australian oil and gas sector. Large LNG projects in Western Australia, the Northern Territory, and Queensland supply customers across Asia, while refineries, motorists, airlines, farms, and industries depend on international petroleum supply chains.
Australia exported about 70% of the natural gas it produced as LNG in 2023. LNG exports expanded rapidly during the previous decade as a series of large projects entered service.
Oil presents the opposite picture. Australia accounted for only around 0.4% of global oil production in 2023 and imported approximately 90% of its oil requirements. More than 94% of the crude oil, condensate, and liquefied petroleum gas produced domestically in 2022–23 was exported, largely because the qualities and locations of these liquids do not always match the requirements of Australia’s remaining refineries.
The result is a highly internationalized energy system. Australia exports much of the gas and liquid hydrocarbons produced near its northern and western coasts while importing crude oil and refined products through ports closer to its major population centers.
LNG Projects Connect Australia to Asian Energy Markets
Australia’s LNG industry developed through several geographically distinct production centers.
The North West Shelf project near Karratha was the foundation of the country’s large-scale LNG trade. It was followed by projects including Pluto, Gorgon, Wheatstone, Ichthys, Prelude, Darwin LNG, and three coal seam gas-based export plants on Curtis Island in Queensland.
Western Australian and Northern Territory projects mainly process conventional offshore gas. The Queensland LNG plants are supplied largely by coal seam gas produced from inland basins and transported to Gladstone through long-distance pipelines.
Japan, China, South Korea, and other Asian economies have been the main customers. Long-term contracts helped finance the original developments and continue to provide a large share of export revenue. Australia earned approximately A$65 billion from LNG exports in 2024–25, although official forecasts expect earnings to fall as international prices weaken. The December 2025 Resources and Energy Quarterly projected LNG export earnings of around A$47 billion by 2026–27.
Export volumes may remain high even when revenue falls. Australian LNG plants were operating at an annualized rate of roughly 77.6 million tonnes in November 2025, equal to about 90% of national nameplate capacity.
The industry is therefore mature rather than rapidly expanding. Future performance will depend on replacing gas from declining fields, maintaining existing plants, and deciding whether large undeveloped resources can secure environmental approval and commercial support.
New Gas Is Increasingly Used to Sustain Existing Plants
Several major Australian LNG facilities were designed around offshore fields that are now maturing. New developments are often intended to maintain existing processing capacity rather than create entirely new export centers.
Woodside Energy’s Scarborough project is designed to supply gas to an expanded Pluto LNG facility in Western Australia. The project extends the operating life and output of an established export complex while developing a new offshore field.
The Browse gas resources, also operated by Woodside with partners, represent another possible source of supply for North West Shelf infrastructure. Browse is much larger and more complex, with technical, environmental, and commercial issues that have delayed development for many years.
In the Northern Territory, the Barossa project is intended to provide replacement gas for Darwin LNG as production from the original Bayu-Undan field declines. Gas from Barossa must travel through offshore infrastructure to the existing liquefaction plant near Darwin.
These projects show how Australia’s LNG industry is changing. The first major investment cycle created export terminals and processing plants. The current cycle is increasingly concerned with finding enough new gas to keep those assets operating.
This creates pressure to approve new offshore developments, but it also increases debate over emissions, cultural heritage, marine environments, and the risk of investing in assets that may operate for decades.
Southern Australia Faces a Different Gas Problem
Australia does not have a single unified gas market. Western Australia has its own production system, pipelines, policies, and domestic gas reservation arrangements. Eastern and southern Australia operate through a separate network connected to Queensland’s LNG export plants.
The eastern market has become increasingly tight because production from the Bass Strait fields between Victoria and Tasmania is declining. Those fields have supplied Victoria, New South Wales, South Australia, and Tasmania for decades.
Queensland still has substantial coal seam gas production, but much of it is linked to LNG export commitments. Transporting more gas south also requires sufficient pipeline capacity and can involve higher costs.
The Australian Energy Market Operator warned in its 2025 Gas Statement of Opportunities that southern Australia could face peak-day shortfall risks from 2028 and structural supply gaps from 2029. It stated that new supply investment and continued access to gas storage would be required to maintain adequate supply.
This forecast does not mean that every region will run out of gas at the same time. It means that supply may not be sufficient during periods of high demand unless new projects, pipeline expansions, storage, LNG import capacity, or demand reductions are delivered.
Gas-fired power generation adds another layer of uncertainty. As coal plants close and renewable generation expands, gas plants may operate less frequently but become more important during periods of low wind, limited solar output, or high electricity demand. This can reduce annual gas consumption while maintaining a need for large volumes on particular days.
Western Australia Balances Exports and Domestic Supply
Western Australia has a different policy structure because its gas resources and LNG projects are physically separated from the eastern market.
The state requires LNG developments to make gas available for domestic use under its domestic gas reservation policy. This has supported mining, mineral processing, electricity generation, manufacturing, and household consumption within Western Australia.
The policy has not removed all supply concerns. Demand from mining and industrial projects is expected to rise, and the timing of new gas fields remains important. AEMO’s 2025 outlook for Western Australia identified a possible supply gap around 2028, although it said the risk could be reduced by higher production from existing facilities or earlier delivery of new projects.
Projects such as Scarborough will provide additional domestic gas as well as LNG feedstock. Other undeveloped fields may also become important if demand increases faster than expected.
Western Australia’s system illustrates the tension within the Australian gas debate. Gas exports generate significant income and support large investments, but domestic industries also require affordable and reliable supply. Policies must therefore determine how much production is reserved locally, how prices are formed, and which new developments are approved.
Domestic Oil Production Continues to Decline
Australia’s crude oil industry is much smaller than its natural gas industry. Most remaining production comes from offshore basins in the northwest, with smaller volumes from areas such as the Cooper-Eromanga Basin in South Australia and Queensland.
Nearly 80% of Australian oil production in 2023 came from offshore fields around the North West Shelf. Much of this output was condensate associated with gas projects rather than crude oil from stand-alone oil fields.
Australia’s conventional oil resources are being depleted faster than new discoveries replace them. Geoscience Australia estimated that, based on 2023 production rates, remaining crude oil reserves had an expected life of about seven years. It also stated that conventional crude production could cease within a similar period without new commercial discoveries.
This does not mean that Australia will stop using oil. It means the country will become even more dependent on international supply.
Australia now has only two major operating refineries, at Geelong in Victoria and Lytton in Queensland. Much of the country’s petrol, diesel, and aviation fuel is imported as finished product from Asian refining centers. Domestic fuel security therefore depends on shipping routes, port infrastructure, commercial inventories, government stockholding arrangements, and access to overseas refineries.
Official forecasts also expect oil export earnings to decline as fields mature. The March 2025 Resources and Energy Quarterly projected that earnings from Australian oil exports would fall from A$12.9 billion in 2023–24 to A$5.5 billion by 2029–30 in real terms.
Australia’s Hydrocarbon Sector Is Entering a Maintenance Era
Australia’s oil and gas sector is no longer defined mainly by the construction of new LNG export plants. It is increasingly defined by the need to sustain existing facilities, replace declining fields, secure domestic gas supply, and manage falling oil production.
Natural gas will remain economically important because LNG exports generate substantial revenue and because domestic industries still depend on gas for heat, feedstock, electricity, and mineral processing. However, each new project faces closer examination of its cost, emissions, environmental impact, and expected operating life.
Oil presents a more direct security issue. Domestic production is falling, refining capacity is limited, and imported fuels remain essential to transport and industry.
Australia’s future hydrocarbons policy will therefore have to manage several separate problems at once. It must maintain reliable domestic gas, decide which export projects should receive replacement supply, protect liquid-fuel access, and adjust to changing international demand. The country will remain a major gas exporter, but its long-term position will depend more on sustaining and reorganizing existing systems than on repeating the rapid LNG expansion of the previous decade.
