The list of LNG import infrastructure projects announced across Asia would, if all proceeded as planned, add approximately 150–200 MTPA of new regasification capacity across the region by 2030. That number is almost certainly wrong. It will be too high. Not because the demand isn’t real — it is — but because the institutional, financial, and regulatory barriers that have historically delayed Asian LNG infrastructure development have not disappeared simply because the project list has grown.
The useful analysis is not which projects are announced. It is which projects have the structural prerequisites to actually proceed.
Bangladesh: Survival mode and strategic opportunity
Bangladesh’s LNG import situation entering 2026 reflects a genuine crisis that has been partially managed through a combination of emergency procurement, demand rationing, and international financial support.
Petrobangla operates two FSRUs — the Summit LNG Terminal at Moheshkhali and the FSRU Exemplar, operated by Excelerate Energy. Combined capacity is approximately 1,000 MMSCFD, but actual throughput has run well below this due to spot procurement constraints.
The priority project for Bangladesh in 2026 is a third FSRU. The Bangladesh government’s engagement with potential FSRU operators has been active, and development finance interest from World Bank, Asian Development Bank, and JBIC exists. The structuring challenge is the same as it has always been: the domestic gas tariff does not support commercial import economics, requiring a sovereign guarantee structure that the government has historically been reluctant to issue in a form acceptable to international lenders.
The project that actually proceeds in Bangladesh in 2026 will be the one that resolves the tariff credit gap — whether through a government guarantee, a subsidised development finance structure, or a co-investment arrangement with a strategic partner. The FSRU technology is ready. The supply is available. The institutional solution is the bottleneck.
India: Capacity chasing demand
India’s regasification infrastructure is in a different situation from Bangladesh: capacity exists and is growing, but utilisation of existing terminals has room to improve before new capacity is genuinely needed in most locations.
Petronet LNG’s Dahej terminal — India’s largest, with approximately 22.5 MTPA capacity — runs at above-nameplate throughput for extended periods. Dhamra LNG, operated by Adani Ports on India’s eastern coast, commissioned its first phase in 2023 and is now handling commercial volumes under a supply arrangement with TotalEnergies.
The priority new-build terminal for 2026 is likely Chhara LNG in Gujarat, being developed by H-Energy. This terminal, if it reaches commercial operation as planned, would serve the Gujarat industrial corridor — one of India’s fastest-growing manufacturing zones and a significant potential gas consumer.
The structural challenge for Indian LNG terminal expansion is pipeline connectivity. Building regasification capacity is straightforward. Ensuring the regasified LNG can reach industrial consumers and city gas distribution networks requires synchronised pipeline investment that historically has lagged behind terminal construction.
GAIL India is the critical infrastructure connector. Its pipeline expansion programme, supported by government capex allocation, is the bottleneck between India’s LNG import ambitions and their commercial realisation.
Vietnam: From one terminal to a system
Vietnam’s transition from a single operational LNG terminal at Thi Vai to a multi-terminal import system is the regional infrastructure story with the most momentum in early 2026.
PV Gas, the gas distribution subsidiary of PetroVietnam, is developing the Long Son LNG terminal as the second major import point. The Long Son site, on Vietnam’s southern coast, is strategically positioned to serve the Ho Chi Minh City industrial zone and the Mekong Delta power sector.
Progress status: Long Son received environmental and investment approval in 2025 and is in procurement phase for the marine infrastructure and FSRU charter. Target first gas is 2027–2028, which for a Vietnamese infrastructure project is credible given the momentum.
The northern Vietnam LNG terminal question — serving Hanoi’s power sector and northern industrial zones — remains more speculative. EVN (Electricity Vietnam) has announced plans for a gas-to-power capacity addition in the north, but the supply and terminal infrastructure required to support it is in early development stage.
For LNG suppliers and project financiers, Vietnam’s infrastructure buildout represents one of the region’s clearer near-term opportunities. The government commitment to LNG-to-power under PDP8 is definitive, the credit structure for infrastructure investment is improving, and Vietnam’s economic growth trajectory supports the demand case.
Philippines: Land-based terminal entering the picture
The Philippines’ FSRU-based imports at Batangas Bay, through First Gen and partners, are transitioning toward longer-term infrastructure planning. The Vopak Terminal Manila project at Pagbilao is the most advanced land-based terminal development, with JERA as equity partner and a target commercial operation date in 2027.
The Pagbilao terminal is notable because it moves beyond the FSRU model that characterises most Southeast Asian LNG imports today. A land-based terminal provides higher throughput capacity, lower operational cost per unit, and better integration with domestic pipeline and power infrastructure. The Philippines’ transition to land-based regasification, if Pagbilao proceeds on schedule, represents a maturation of the market that will improve supply economics.
Department of Energy Philippines projections for LNG demand through 2030 indicate that the Malampaya field replacement alone — supplying Luzon’s existing gas-fired power capacity — requires approximately 4–5 MTPA of LNG imports by 2027. Additional gas-to-power projects proposed under the administration’s energy security programme add further demand that would require terminal capacity above what Batangas Bay FSRU and Pagbilao together can provide.
Malaysia: Pengerang’s hub potential
The case for Pengerang as a regional LNG hub rests on several structural advantages. Its location at the southern tip of the Malay Peninsula, adjacent to the main Singapore Strait shipping lane, puts it at the intersection of Pacific and Atlantic basin LNG trade routes. The integrated downstream complex at Pengerang — refinery, petrochemicals, regasification — creates cross-product synergies unusual for a pure LNG terminal.
What Pengerang lacks, and what PETRONAS is working to develop, is sufficient trading and third-party access infrastructure to function as a genuine hub. A hub is not just a big terminal — it is a price formation centre, a place where multiple buyers and sellers meet, establish prices, and exchange volumes. That function requires open-access terminal capacity, transparent pricing, and a regulatory framework that treats third-party access as a right rather than a negotiated favour.
Malaysia’s Gas Industry Development Act framework and the regulatory role of the Energy Commission Malaysia are relevant to this development. The commercial and regulatory evolution needed to position Pengerang as a regional hub is a multi-year project, but the physical infrastructure to support it is largely in place.
Indonesia: The domestic priority
Indonesia’s LNG infrastructure in 2026 is primarily a domestic gas system story. The Jawa Satu CCPP project has clarified that Indonesia’s LNG import needs are driven by a geographic mismatch between production and demand, not a fundamental supply deficit. PT Pertamina manages the import side through domestic procurement that uses the same infrastructure and commercial frameworks as its export operations.
New FSRU or terminal development in Indonesia in 2026 is primarily focused on eastern Indonesian island supply — small-scale LNG from Java or Kalimantan sources, transported by LNG carrier to communities with no pipeline connection. This small-scale distribution network is expanding but does not represent significant international procurement volumes.
Social media pulse
Asia LNG infrastructure pipeline: a lot of announced, a fraction will actually build. The differentiator between projects that proceed and those that don't isn't capital — it's supply contracts. The terminals that have long-term SPAs in place get financed. The others get rescheduled indefinitely.
March 2026 · @woodmac on X →
Vietnam is the Southeast Asia LNG market to watch in 2026. PDP8 creates binding demand. PV Gas has moved from aspirational to operational. Long Son terminal procurement is live. This is no longer a "potential" market — it's an active procurement market that is underrepresented in Asian supply allocation models.
March 2026 · @RystadEnergy on X →
The common denominator for projects that proceed
Looking across the regional pipeline, the projects with the highest probability of reaching commercial operation in the 2026–2029 period share several characteristics:
- A committed power sector anchor — gas-to-power demand that is contracted under a PPA, not speculative industrial demand
- Long-term supply contracted or in advanced negotiation — projects without supply are projects without lenders
- Government explicit support — not just policy approval but active facilitation of tariff structure and credit enhancement
- An experienced FSRU or terminal operator — first-time operators of LNG infrastructure face steep learning curves that delay commissioning and reduce utilisation
The projects that check all four boxes are relatively few among the announced pipeline. Identifying them early — and positioning to participate before the supply contracting windows close — is the strategic opportunity for LNG sellers and project developers in 2026.
Global LNG advises LNG infrastructure project developers and supply-side partners on project structuring, offtake strategy, and institutional navigation across Asia. Contact our team to discuss your project pipeline.