Three years ago, the conventional view of Southeast Asian LNG was that demand was real but infrastructure was theoretical. Terminals were permitted, FSRUs were chartered, off-take agreements were being negotiated — but the operational reality remained thin. Vietnam had no functioning LNG import capacity. The Philippines’ FSRU projects were mired in regulatory disputes. Indonesia was a net exporter with a fragmented domestic gas market that made import economics difficult to justify.
By mid-2025, that picture has changed substantially — though unevenly. Some countries have crossed the infrastructure threshold into operational reality. Others are still navigating the same institutional barriers that have delayed their projects for years.
Vietnam: Finally importing, but grid integration is the bottleneck
Vietnam’s first operational LNG import terminal at Thi Vai, in Ba Ria-Vung Tau Province, received its inaugural commercial cargo in late 2023 via an FSRU operated by PV Gas. By mid-2025, the terminal had processed dozens of cargoes, primarily sourced under short-term and spot procurement by PetroVietnam Gas Corporation.
The constraint is not supply or terminal capacity. It is the power plant gas infrastructure downstream. The Nhon Trach 3 and 4 combined-cycle plants — designed to receive gas from the Thi Vai terminal — experienced commissioning delays that pushed their commercial operation dates into 2025. Until those plants are running at design capacity, Thi Vai’s send-out rate remains well below its regasification capability.
Vietnam is planning additional LNG terminal capacity. The Long Son LNG terminal in Ba Ria-Vung Tau and proposed facilities in central and northern Vietnam are in various stages of development. Vietnam’s Power Development Plan 8 (PDP8), approved in 2023, calls for significant LNG-to-power capacity by 2030. The gap between PDP8’s targets and the current development pipeline is significant and will require sustained commercial and institutional momentum to close.
For LNG sellers and project developers, Vietnam represents a high-upside but high-execution-risk market. The demand is unambiguous — rapid industrial growth, coal-to-gas switching pressure from international investors and lenders, and a domestic gas production outlook that declines from legacy offshore fields. The path from demand potential to contracted volumes requires navigating a permitting and tariff environment that rewards patience.
The Philippines: Stable regulation finally attracting capital
The Philippines’ LNG import programme had one of the rockier development histories in the region. Multiple FSRU projects were announced, permitted, and then delayed or restructured through 2019–2023. The underlying cause was a combination of political risk around energy market liberalisation, uncertainty about the role of LNG relative to coal, and bilateral sensitivities around the South China Sea that complicated some supply source discussions.
By mid-2025, First Gen Corporation’s Santa Rita and San Gabriel power plants are receiving LNG via the interim floating receiving unit at Batangas Bay. Vopak Terminal Manila, in partnership with JERA and other investors, is developing a land-based import terminal on Pagbilao, with first cargo targeted for 2027.
The Philippines’ LNG programme is now primarily a gas-to-power story. The country’s energy mix has historically been dominated by coal, geothermal, and hydro, with natural gas playing a supporting role. Malampaya, the offshore gas field that has supplied most of Luzon’s gas-fired power capacity, is declining. The transition from Malampaya gas to LNG imports at regulated tariffs is the core policy objective driving terminal investment.
Department of Energy Philippines data through Q1 2025 showed that LNG imports had contributed approximately 8% of Luzon grid capacity, a figure expected to grow as additional gas-fired capacity commissioned to receive LNG comes online. For sovereign LNG procurement, the Philippines is a DES buyer rather than a FOB purchaser — PETRONAS, Shell, and QatarEnergy have all participated in tenders for Philippine utility supply.
Indonesia: The counterintuitive case
Indonesia’s LNG import story seems paradoxical. The country is the world’s seventh-largest LNG exporter, operating the Bontang LNG plant in Kalimantan and the Tangguh LNG facility in Papua. Yet PT Pertamina has been importing LNG into West Java and Bali via the Nusantara Regas FSRU for years, driven by a geographic mismatch between gas production (eastern Indonesia) and gas demand (Java).
The more significant development in 2025 is the progress of the Jawa Satu LNG terminal in West Java, which underpins supply to a combined-cycle power plant that represents one of the largest single LNG-to-power projects in Southeast Asia. Pertamina Gas has secured long-term supply from multiple sources for this anchor project.
For infrastructure project developers elsewhere in Southeast Asia, the Pertamina model is instructive: domestic LNG from government-controlled upstream integrated with imported LNG as a bridge and supplement, with the state energy company as aggregator. It avoids the credit and tariff complexities that plague buyer-side LNG in countries without a strong national energy company.
Malaysia: Building both sides of the market
Malaysia’s LNG infrastructure story runs in both directions simultaneously. PETRONAS exports roughly 25 MTPA of LNG from Bintulu while importing LNG into Peninsular Malaysia via two regasification terminals — Melaka and Pengerang.
The Pengerang Regasification Terminal, located within the Pengerang Integrated Complex in southern Johor, is particularly significant for regional infrastructure watchers. Its proximity to Singapore, its access to international shipping routes, and its integration with refinery and petrochemical downstream facilities make it a potential regional LNG hub candidate.
PETRONAS’s Sabah LNG regasification terminal in Kimanis, Sabah, adds a third import point that serves the East Malaysian power market. The interplay between MLNG exports from Bintulu, domestic gas production in Sabah, and LNG imports into Kimanis reflects the complexity of managing an integrated national gas system across a geographically fragmented country.
Thailand: The mature market
Thailand’s LNG import programme, operated by PTT through the Map Ta Phut LNG Terminal, is the most mature in Southeast Asia. PTT has operated LNG imports since 2011, building up procurement experience, supply diversity, and downstream distribution infrastructure over 14 years.
By 2025, Map Ta Phut is running at close to capacity, and PTT LNG is advancing plans for a second terminal. Thailand’s LNG import programme is notable for the diversity of its supply sources — contracts with Qatar, Malaysia, Australia, and spot purchases from multiple origins — which represents a model worth studying for newer importers in the region.
Social media pulse
Southeast Asia LNG import capacity is growing but the bottleneck has shifted from terminals to downstream: pipelines, power plants, and grid integration that can't absorb regasified LNG fast enough. Terminal utilisation rates tell the real story — and they're disappointingly low across the region.
June 2025 · @saulkavonic on X →
Vietnam's Thi Vai terminal cleared its 20th commercial cargo in May. That's progress. But the original PDP8 modelling assumed 3x this throughput by now. The power plant commissioning delays are the story no one wants to write because it makes the whole LNG-to-power narrative look shaky.
June 2025 · @ICISgas on X →
The common barriers
Across Vietnam, the Philippines, and Indonesia, the same set of barriers appear repeatedly:
Regulatory tariff design — LNG import costs are structurally higher than domestic gas production costs in every Southeast Asian market. Building a tariff that allows LNG-to-power to compete with subsidised coal, while covering import terminal operating costs and shipping, requires tariff reform that moves slowly in countries with politically sensitive electricity prices.
Power purchase agreement structure — Gas-fired power projects that anchor LNG terminal economics require long-term PPAs. PPAs require creditworthy off-takers, typically the state utility. State utilities in many Southeast Asian markets carry significant debt and cannot easily extend long-term payment obligations at commercial rates.
Supply credit — International LNG suppliers extending long-term SPA terms to Southeast Asian sovereign buyers require either government guarantees or credit enhancement from development finance institutions. The DFI pipeline — Asian Development Bank, World Bank IFC, Japan Bank for International Cooperation — has been critical in bridging the credit gap for several regional projects.
For infrastructure project developers reading this market, the opportunity is real but the execution environment demands patience and institutional navigation skills that are different from what’s required in more mature LNG markets. The developers succeeding in Southeast Asia are those who understand the regulatory constraint as a design variable, not an obstacle.
Global LNG works with project developers and sovereign buyers navigating Southeast Asia’s LNG infrastructure market. Speak with our team to understand the practical pathways for your project.