Southeast Asia has roughly 106 gigawatts of gas-fired power capacity and 70 million tonnes per year (mtpa) of LNG import capacity in development, according to Global Energy Monitor (GEM). Together, the projects represent an estimated $160 billion of investment.
Investor takeaway: the scale is large, but “in development” includes announced, pre-construction and construction-stage projects. These figures should not be read as capacity already being built. Project returns depend on affordable fuel, contracted offtake, financing and whether power tariffs can pass through volatile LNG costs.
A large pipeline, not a guaranteed buildout
GEM estimates regional gas-power capacity in development declined from 113.4 GW in the first half of 2026 to about 106 GW. LNG import capacity in development nevertheless rose from roughly 47 mtpa in 2024 to about 70 mtpa. The divergence shows that terminal plans can advance even as individual power projects are delayed, cancelled or reconfigured.
Country exposure is uneven. Malaysia had 10.8 GW of gas power in development by August, including 5.3 GW in construction. The Philippines had about 13.8 GW remaining after 11.2 GW was shelved or cancelled, with most of the surviving pipeline still at the announced stage. Investors therefore need project-level analysis rather than a regional headline.
LNG affordability is the central risk
The Strait of Hormuz conflict has disrupted LNG flows and lifted freight, insurance and spot-cargo costs. GEM cited an average Asian spot LNG price near $17.50 per million British thermal units in the second quarter of 2026, about 45% higher than a year earlier. High prices can reduce utilisation at new terminals, weaken power-distribution margins and force governments to choose between subsidies, tariff increases and lower gas burn.
Import infrastructure improves access to global supply, but it does not guarantee availability or affordability. Long-term contracts can reduce spot exposure, yet their oil-linked formulas, destination clauses and take-or-pay commitments create different risks.
Domestic gas provides only a partial hedge
GEM identified at least 20 fields that could add around 62 billion cubic metres of annual production capacity by 2035. Development takes time, and output may be exported or allocated to non-power users. Domestic reserves are therefore most valuable where pipelines, pricing rules and supply obligations connect production to local generators.
Implications across the value chain
| Exposure | Potential upside | Main downside |
|---|---|---|
| LNG terminals | Long-term capacity fees and growing import volumes | Low utilisation if cargoes remain unaffordable |
| Gas generators | Dispatchable power and capacity payments | Fuel-cost pass-through gaps and stranded assets |
| Utilities and governments | Grid flexibility as renewables expand | Subsidy pressure, tariff resistance and FX risk |
| LNG suppliers and shipping | New contracted demand | Project delays and buyer credit risk |
What investors should monitor
- Movement from announcement to final investment decision and construction.
- Long-term LNG contract coverage, pricing formulas and creditworthy offtakers.
- Terminal utilisation, power tariffs and government subsidy policy.
- Local-currency moves against the dollar, the pricing currency for most LNG.
- Renewable deployment, storage and grid investment that could reduce gas capacity factors.
The bullish case is that dispatchable gas supports industrialisation and renewable integration, creating durable infrastructure cash flows. The bearish case is that expensive imported fuel leaves terminals underused and plants uneconomic. The distinction between planned and committed capacity is therefore the most important filter for investors.