Supply disruptions in the Strait of Hormuz stress test Southeast Asia's gas buildout

The crisis in the Strait of Hormuz is stress-testing Southeast Asia’s plans for gas expansion, but its effects are not playing out uniformly across the region. While some countries appear to be moving away from gas, others seem to be pressing ahead.

Around 106 gigawatts (GW) of gas power capacity and 70 million tonnes per annum (mtpa) of liquefied natural gas (LNG) import capacity remain in development across Southeast Asia, according to data in Global Energy Monitor’s (GEM) Global Oil and Gas Plant Tracker (GOGPT)¹ and Global Gas Infrastructure Tracker (GGIT)². Together, these projects represent around US$160 billion in investment. 

In 2024, GEM documented the scale of this planned gas expansion and highlighted the economic and energy-security risks associated with greater reliance on imported LNG. The present conflict has brought those risks into sharper focus, disrupting LNG supply, driving up prices, and prompting governments and developers to reconsider their exposure to imported gas.

Southeast Asia’s planned gas expansion was already facing significant headwinds even before the present conflict. GEM data show that as of September 2025, around 65 mtpa of LNG import capacity had been shelved or cancelled, roughly equivalent to the approximately 63 mtpa already in operation. 

Gas power capacity showed a similar trajectory: between the end of 2024 and the end of 2025, over 35 GW of gas power capacity was shelved or cancelled across Southeast Asia. Demand signals were weakening in some markets as well. In Thailand, for example, GEM reported declining LNG imports and gas power generation alongside continued investment in additional LNG import infrastructure.

Against this backdrop, much of the remaining planned expansion rests on three assumptions: that LNG will remain reliably available, that it will remain affordable enough to compete with alternatives, and that domestic gas can provide a fallback when imports are constrained. The conflict puts these expectations to a real-world test, but its impacts are unfolding across countries with markedly different levels of LNG exposure, access to domestic gas, and gas power development.

State of play: Gas expansion remains intact despite mounting pressure

Southeast Asia’s gas buildout is still substantial, even as pressure on individual projects grows. The longer-term picture is striking: Gas power capacity in development has remained above 100 GW since at least 2024, while planned LNG import capacity has grown from roughly 47 mtpa to around 70 mtpa. In the first six months of this year, gas power capacity in development declined from 113.4 GW to around 106 GW, while LNG import capacity in development increased from around 59 mtpa to 70 mtpa since last year. 

Beneath those regional totals, country-level movements vary between H2 2025 and H1 2026. In Malaysia, 4.2 GW of gas power capacity moved into construction and no capacity was shelved or cancelled between H2 2025 and H1 2026. In the Philippines, however, no projects entered construction and 11.2 GW of gas power capacity was shelved or cancelled. LNG import capacity also moved differently at the country level. In Thailand, capacity in development remained unchanged at 10.8 mtpa in the past year, although 5 mtpa moved into construction. In Vietnam, capacity in development increased from 25.9 mtpa to 35.8 mtpa over the same period, including 6.7 mtpa now under construction.

The conflict exposes Southeast Asia’s LNG supply vulnerability

The Strait of Hormuz disruption has sharpened the supply risks that come with greater dependence on imported LNG. Disruption of shipping through the Strait of Hormuz constrained Qatari LNG exports accounting for approximately 20% of global LNG supply, with the impact falling particularly heavily on price-sensitive markets in emerging Asia and Africa, where higher prices prompted reductions in gas consumption and fuel switching (Global Gas Report).

Southeast Asia was significantly affected by the disruption. The IEA describes the Middle East conflict as a “stark wake-up call” for the region’s energy security, highlighting growing import dependence, limited diversification, and concentrated supply routes. Before the conflict, roughly one-third of Southeast Asia’s gas imports came from the Middle East, while markets such as Singapore and Thailand relied substantially on Qatari LNG.

While additional import terminals can expand access to LNG, they cannot insulate countries from disruption in the fuel supply itself or the price shocks that follow.

Higher LNG prices put gas expansion under pressure

The supply disruption was accompanied by a sharp increase in LNG prices, raising a separate challenge for Southeast Asia’s planned gas expansion: affordability. Asian spot LNG prices averaged US$17.50/MMBtu in the second quarter of 2026, 45% higher than a year earlier. Asian gas demand fell by an estimated 0.5%, or almost 5 bcm, in the first half of the year, as higher prices, fuel switching, and demand-side measures weighed on consumption.

For price-sensitive Southeast Asian markets, the implications extend beyond the immediate shock. LNG can remain physically available while becoming expensive enough to weaken the economics of relying on it for power generation. Recent developments in Thailand and Vietnam provide some of the clearest early indications of these pressures influencing policy and investment decisions, while gas power trends in the Philippines and Malaysia show how the shock is arriving in markets with very different existing project conditions.

Thailand and Vietnam show early signs of a rethink

Thailand has updated its power plan to reduce reliance on imported LNG and accelerate alternative energy sources, explicitly citing the conflict as highlighting the risks of dependence on imported fuels. In Vietnam, the company Vingroup proposed scrapping its planned 4.8 GW Hai Phong LNG power plant, the country’s largest proposed LNG plant, and replacing it with renewable generation, naming the conflict and the risk of high LNG prices. The proposal came only weeks after GE Vernova had been selected to supply turbines and generators for the project. 

Neither development signals a region-wide retreat from gas, but both show LNG price and supply risks beginning to shape real policy and investment choices.

Philippines and Malaysia entered the shock under different conditions

The same pressures are landing on gas power development trajectories already moving in different directions. In the Philippines, 11.2 GW of gas power capacity was shelved or cancelled between H2 2025 and H1 2026, while only 1.8 GW entered development and none started construction. By August 2026, approximately 13.8 GW remained in development, down from 19.7 GW in January—a decline of around 30%. None of this capacity is under construction, with around 83% still at the announced stage. 

Malaysia’s gas power portfolio is smaller but considerably more advanced. In the first six months of this year, 4.2 GW moved into construction, while no capacity was shelved or cancelled. By August, Malaysia had 10.8 GW in development, of which 5.3 GW, nearly half, was already under construction.

These movements largely predate the conflict and should not be read as evidence that the conflict caused project attrition in the Philippines or progression in Malaysia. Rather, they show that the price shock arrived in markets with very different existing project conditions: one dominated by early-stage projects, the other with nearly half its remaining gas power capacity in development already under construction. Those starting conditions may shape how quickly changing LNG economics affect individual projects.

Gas plans remain sticky even as their assumptions weaken

Gas plants and LNG terminals can remain announced or in pre-construction while developers reassess project economics, fuel supply, or future demand. A large infrastructure portfolio can therefore persist even as the assumptions underpinning individual projects begin to weaken. The developments in Thailand and Vietnam may be early indications of such a shift, but whether these pressures ultimately translate into widespread project delays, cancellations, or changes in fuel strategy will take longer to become visible in terms of numbers.

At the same time, emerging sources of demand could pull in the opposite direction: Wood Mackenzie projects that data-center expansion could drive structural LNG demand growth in Southeast Asia, further complicating the region’s gas outlook.

Domestic gas offers a buffer, but not a regional fallback

The countries with domestic gas have had more room to absorb the LNG shock. Malaysia was able to increase deliveries from domestic offshore gas fields as power demand rose, pulling on supplies already feeding Peninsular Malaysia. The Philippines is also seeking to bolster indigenous supply through its Phase 4 development of the Malampaya gas field. In March, President Ferdinand Marcos Jr. highlighted the difference between the cost of Malampaya gas and imported LNG—around PHP4.80/kWh compared with PHP10.30/kWh —while linking indigenous production to protection from volatile international fuel prices caused by the Middle East conflict. The Philippines, however, remains substantially exposed to imported LNG. In 2025, 55% of the Philippines’ gas supply came from imported LNG and 45% from Malampaya. New production from Malampaya Phase 4 is expected to help extend indigenous supply, but this is an expansion of an existing resource rather than a new supply option developed in response to the current crisis.

That distinction matters. Domestic gas can provide flexibility where additional supply is already available or close to production, but developing new resources is a much longer-term proposition due to the long lead times of new fields. New upstream development therefore cannot provide a rapid response to an immediate LNG supply shock.

GEM’s Global Oil and Gas Extraction Tracker identifies at least 20 gas fields in Southeast Asia that may come online between 2026 and 2035, representing around 62 bcm/y of new production capacity. Yet even with substantial upstream development, the IEA projects domestic gas production to fall under current policy settings, leaving the region dependent on imported gas even with continued upstream investment. 

New production has to do more than meet growing demand: It must also offset declining output from existing fields, observed at a rate of 6.1% in Asia Pacific post-peak fields. From the 2024 baseline of 210 bcm, the decline between 2026 and 2035 equates to an average of 9.5 bcm/y, greater than the replacement from the new fields (6.2 bcm/y) covered in GOGET.

Indonesia’s Abadi project, the largest source of potential new production in GEM’s Southeast Asia data, illustrates a further complication. The project is designed to produce 9.5 million tonnes of LNG per year alongside 150 million standard cubic feet per day of pipeline gas, and Indonesia has committed at least 60% of Abadi’s gas to domestic demand. Because LNG can also be moved domestically between producing and consuming regions in Indonesia, the project’s LNG output could contribute to domestic supply. However, how much new production strengthens domestic energy security will depend not only on where the gas is produced, but also on how it is processed, allocated, priced, and ultimately consumed.

Countries can adjust how they use gas they already produce, but a supply shock cannot quickly create new domestic resources. Domestic gas can provide an important buffer where sufficient production already exists, but new supply takes years to develop and its availability to domestic consumers depends on how projects are configured and their output allocated. It therefore cannot provide a rapid region-wide substitute for imported LNG.

Gas expansion persists, but its assumptions are under strain

The Middle East conflict has not produced a uniform retreat from gas across Southeast Asia. Instead, it is exposing how differently countries are equipped to absorb the same LNG supply and price shock.

Thailand and Vietnam provide some of the clearest evidence of these risks beginning to influence policy and investment decisions. The Philippines entered the crisis with substantial attrition already occurring among its gas power projects, while Malaysia entered with more projects under construction and greater access to domestic supply. These differences do not establish a simple relationship between domestic gas availability and project progression, but they help explain why the consequences of the same external shock may vary across the region.

For now, the regional buildout remains substantial: 106 GW of gas power capacity and roughly 70 mtpa of LNG import capacity remain in development. The consequences of the crisis have therefore not yet translated into a fundamental change in Southeast Asia’s infrastructure trajectory.

But the conflict has exposed the fragility of some of the assumptions supporting that expansion: Import capacity does not guarantee secure LNG supply, access to LNG does not guarantee affordability, and domestic gas provides a meaningful buffer only where sufficient supply is already available. How far those pressures ultimately reshape Southeast Asia’s gas buildout may take longer to become visible in the project development trends.