Southeast Asia is entering a “Deepwater 2.0” phase.
The region is targeting about 28 trillion cubic feet of gas across Indonesia, Malaysia and Brunei to offset declining shallow-water and onshore output.
Six major projects vital for domestic markets and LNG exports face fragile economics, thin margins, high execution and supply chain risks.
Southeast Asia is entering a second wave of deepwater gas development, targeting about 28 trillion cubic feet (tcf) of resources across Indonesia, Malaysia and Brunei. But the push comes with fragile economics and execution risks, with most projects expected to deliver internal rates of return (IRR) of under 15 per cent, according to Wood Mackenzie, a global energy and natural resources analytics and insights provider.
The planned developments, spanning six major projects, will require more than $20 billion in capital expenditure by 2030. Operators face narrow margins for error as they attempt to bring new supply online to offset declining output from ageing shallow-water and onshore fields.
“Southeast Asia's shallow-water and onshore gas fields are maturing rapidly, and this necessitates a focus on deepwater resources that were once considered too risky and expensive,” said Munish Kumar, senior research analyst (Upstream) at Wood Mackenzie. “Asia’s first wave of deepwater gas projects between 2008 and 2017 proved commercial viability… Now we are entering a new phase — Asia’s ‘Deepwater 2.0’ moment.”
Indonesia’s non-associated offshore gas production has declined by over 12 per cent from its 2018 peak, while Brunei will need an additional 500 million cubic feet per day (mmcfd) of gas post 2030 to sustain LNG output. Malaysia is expected to source 20 per cent of its gas from deepwater by 2027.
The new wave targets roughly 5 billion barrels of oil equivalent across key developments including North Ganal, Rapak and Ganal in Indonesia’s Kutei Basin; South Andaman projects (Tangkulo and Layaran) in North Sumatra; Kelidang in Brunei; and Rosmari-Majoram in Malaysia.
“These projects will deliver critical gas supply into domestic markets and LNG export plants to replace declining legacy production,” Kumar said.
The operator mix includes majors such as Eni and Shell, alongside national oil companies like PETRONAS and newer deepwater entrants such as Mubadala Energy. Eni is advancing three deepwater hubs in Indonesia's Kutei Basin, while farm-down opportunities from Eni and Harbour Energy in North Sumatra could attract additional investors.
Wood Mackenzie’s modelling shows most projects clustered around a 15 per cent IRR under base-case assumptions — significantly lower than comparable deepwater plays globally.
Sensitivity analysis highlights the risks: A 20 per cent increase in capital costs or a 20 per cent drop in gas prices or output could wipe out roughly 150 per cent of net present value. A three-year delay would halve project value.
“Without progressive fiscal mechanisms to share risk, there's virtually no cushion for execution failures,” Kumar said. “Any delay or cost overrun directly threatens project viability.”
Supply chain constraints are adding further pressure. Ongoing geopolitical tensions, including conflicts in the Middle East, are driving cost inflation and extending lead times for subsea equipment.
Operators are attempting to compress development timelines to protect project economics. Eni is targeting just five years from discovery to first gas at Geng North, while Mubadala is pursuing a phased approach in North Sumatra — prioritising early supply from Tangkulo before advancing the larger Layaran project.
The next five years will be critical. As regional energy security concerns intensify amid global geopolitical disruptions, deepwater gas is shifting from a high-risk frontier to a strategic necessity.
However, with economics finely balanced, the success of Southeast Asia’s “Deepwater 2.0” will depend on whether operators can deliver projects on time and within budget.