Indonesia’s natural gas sector sits between two eras. The country built its international position as one of Asia’s leading liquefied natural gas exporters, supported by large fields in Kalimantan, Papua, and other eastern regions. Domestic demand for electricity, fertilizers, petrochemicals, and manufacturing has also continued to rise. Indonesia is therefore no longer defined only by how much LNG it can sell abroad. Its central challenge is moving gas from remote production areas to domestic demand centers while preserving the export revenue and investment that large projects require.
Indonesia held about 33.8 trillion cubic feet of proved natural gas reserves in 2024. Production reached roughly 2.1 trillion cubic feet that year, rising slightly from 2023 after additional drilling, especially by state-owned Pertamina. Consumption was lower than production, leaving room for exports, but the national balance hides a geographic problem. Many strong gas resources are far from Java, where much of the population, power demand, and industry are concentrated. Pipelines cannot connect every island economically, so LNG and coastal shipping serve the domestic market as well as international buyers.[1]
Eastern Gas Fields Support a National Market
Indonesia’s mature gas-producing areas include East Kalimantan, South Sumatra, the Natuna region, and offshore fields around Java. Some of its most important future resources are farther east, particularly in Papua and the Arafura Sea. Long-term production growth increasingly depends on offshore projects, deepwater developments, and new processing infrastructure.
The Tangguh LNG complex in Bintuni Bay, Papua Barat, is the clearest example. Its third production train started operations in 2023, adding 3.8 million tonnes per year of LNG capacity and lifting total nameplate capacity to about 11.4 million tonnes. Part of the additional output is committed to the domestic market, including supplies for state electricity company PLN. Tangguh therefore shows how Indonesia now uses LNG facilities to serve national demand as well as overseas customers.[2]
Further investment is intended to sustain Tangguh as existing reservoirs mature. BP and its partners approved the Tangguh Ubadari, CCUS and Compression project in 2024. The project will develop the Ubadari gas field, add compression to maintain production, and use carbon capture, utilization, and storage to manage reservoir carbon dioxide. It could unlock around 3 trillion cubic feet of additional gas resources. This matters because Indonesia needs new supply not only to raise output, but also to replace declines from older fields.[3]
LNG Exports Remain Important, but Domestic Supply Has Priority
Indonesia was one of the world’s leading LNG exporters before Australia and the United States became major suppliers. Bontang LNG in East Kalimantan and Arun LNG in Aceh were central to that history. Arun has since shifted from liquefaction toward regasification and domestic distribution, while Bontang remains active but depends on sufficient upstream supply from aging fields.
In 2024, Indonesia exported about 845.8 billion cubic feet of LNG, an increase from the previous year, and ranked sixth globally by export volume. Almost all cargoes went to Asian buyers, with China, Japan, and South Korea receiving most of the total. Indonesia also exported 145.3 billion cubic feet of pipeline gas to Singapore through the West Natuna Transportation System, although those flows declined from 2023.[1]
Exports provide revenue, support long-term sales contracts, and make large upstream projects commercially possible. However, the government increasingly expects producers to reserve gas for Indonesian customers. Domestic market obligations, regulated pricing, and allocations to power generation, fertilizers, petrochemicals, and industry can affect project economics. Producers may prefer export-linked prices, while domestic buyers need stable and affordable supply. Policy must therefore balance investment incentives with energy security.
That balance is especially important because coal remains dominant in Indonesian electricity generation. Natural gas can reduce reliance on coal or diesel in selected power systems, particularly where flexible generation is valuable. Yet gas cannot expand simply because reserves exist. Power plants need dependable contracts, regasification terminals, shipping capacity, and connections to local grids. In an archipelago, infrastructure determines whether gas is commercially usable.
Abadi Could Reshape Indonesia’s Gas Industry
The Abadi LNG project in the Masela Block is Indonesia’s largest proposed gas development and one of Asia’s most important planned LNG projects. The field lies in the Arafura Sea southwest of the Tanimbar Islands. INPEX operates the project with Pertamina and Petronas as partners.
The approved concept includes an onshore LNG plant designed to produce about 9.5 million tonnes of LNG per year, up to 35,000 barrels per day of condensate, and around 150 million cubic feet per day of pipeline gas for the Indonesian market. The revised plan also incorporates carbon capture and storage. Front-end engineering and design began in 2025, but a final investment decision is still required before full construction can begin.[4]
Abadi could create a new gas-producing center in eastern Indonesia, increase domestic supply, and extend Indonesia’s role in Asian LNG markets into the 2030s. It also illustrates the difficulty of developing remote resources. The project requires offshore facilities, a long subsea pipeline, an onshore processing complex, shipping infrastructure, financing, land access, and long-term buyers. Changes to the development design and commercial structure have already extended the timetable.
Its future will depend on whether the partners can control costs and secure buyers while meeting Indonesia’s domestic supply requirements. Competition will be strong. New LNG capacity from Qatar, the United States, Canada, and other producers is expanding, and buyers are becoming more selective about price, contract flexibility, and emissions.
Gas Infrastructure Must Connect a Fragmented Archipelago
Indonesia has both liquefaction and regasification capacity, giving it an unusual position as an LNG exporter that also moves LNG internally. Floating storage and regasification units near demand centers allow gas produced in one region to be delivered by ship to another. This can be more practical than building pipelines across deep seas and long distances.
Utilization is uneven. Some terminals operate below capacity because of supply constraints, price differences, or limited downstream connections. Pipeline networks are concentrated in particular areas rather than forming one national system. Further development will require coordinated investment in receiving terminals, coastal shipping, storage, local pipelines, and gas-fired generation.
The government also faces a policy choice over where gas creates the greatest national value. Export sales bring foreign exchange, but domestic gas can support fertilizers, petrochemicals, metals, power generation, and other industries. Directing too much supply to low-priced domestic markets may discourage upstream investment. Allowing too much gas to leave the country may create shortages or force domestic users to rely on more expensive fuels.
Indonesia’s natural gas future will be determined less by the size of its resource base than by project execution and market integration. Tangguh provides near-term supply, while Abadi and other deepwater developments could support the next phase of production. The central test is whether Indonesia can connect remote reserves with domestic customers while remaining competitive in Asian LNG trade.
