Southeast Asia Upstream M&A: Buyers Now Pay Record Premiums

For most of the past five years, Southeast Asia’s upstream oil and gas market looked like a place where international majors went to sell. That picture is now out of date. Development assets in the region have recently changed hands at about US$9.8 per barrel of oil equivalent (boe), against a six-year average of US$6-7/boe, and the buyers paying those prices are not bargain hunters.

Rystad Energy estimates that roughly US$9.6 billion of regional assets will reach the market across the rest of 2026 and through 2027. The buyer profile has moved from opportunistic to strategic. These companies want a permanent seat in specific basins, and they are paying for it.

That shift matters if you allocate capital to regional energy. If you read the current deal cycle as another round of distressed exits, you could underestimate how hard buyers will compete for scarce gas positions. If you treat every premium as justified, you could overpay for risk that has not yet been removed.

Here is a framework for reading Southeast Asia upstream M&A: who is selling, what is on offer, who is likely to buy, and whether the prices hold up.

Why has the Southeast Asian upstream deal market flipped from exits to strategic entry?

Between 2020 and 2024, the regional deal story followed a predictable script. Majors pruned late-life fields, and production sharing contracts (PSCs) expired. A PSC is an agreement under which a company funds and runs a field in return for a share of its output, while the host government keeps ownership of the resource.

Rystad now describes a different market, one driven by buyers seeking strategic entry. About US$6.7 billion of assets changed hands in 2025 on that basis. The valuations are the evidence of this change rather than its cause.

Pre-FID resources are discoveries where owners have not yet made a final investment decision (FID), the formal commitment to fund construction. Their values have roughly doubled. Producing assets have a record of premiums near US$8/boe.

Rystad Energy transaction data show development assets changing hands at about US$9.8/boe, with pre-FID resources above US$3/boe, a pricing step-up that reflects buyers paying for strategic positioning rather than near-term cash flow.

Capital is not the deciding factor Rystad’s Prateek Pandey, Head of APAC Oil & Gas Research, argues that money alone will not determine who wins these assets. In his view, the premium a buyer can justify depends on its plan for creating value from the asset.

When prices double on resources that are still years from first gas, buyers are paying for access and positioning. You should judge any deal by the strength of the buyer’s plan, not by the headline multiple. Wood Mackenzie’s May 2026 finding that new deepwater-gas projects cluster around a 15% base-case internal rate of return (IRR, the annual return a project is expected to generate) is a reminder that the underlying project economics remain thin.

What is actually on offer: the US$9.6 billion asset pool

The US$9.6 billion headline figure becomes more useful once you break it down. By seller category, the split is:

• Majors: US$3.6 billion
• Independents: US$3.7 billion
• National oil companies (NOCs): US$1.4 billion

According to Rystad, the pool covers about 45 PSCs across 12 provinces, holding roughly 2.8 billion boe of net resources and about 145,000 boe per day of production. However, 72% of those resources are pre-FID and only 18% are producing. Just 17 producing PSCs are competing for buyers, which explains why the few cash-generating blocks attract such strong interest.

Producing opportunity: Chevron’s North Malay stake

Chevron’s stake in the North Malay Basin, the second-largest producing gas block in Peninsular Malaysia, is the standout producing asset. It is being marketed, but no bidder or value has been disclosed. The sale fits a broader retreat: Chevron’s Southeast Asian resource base has shrunk from nearly 3 billion boe in 2020 to about 300 million boe.

Pre-FID gas: Kutei, Andaman, Ken Bau and Abadi

Eni has signed binding agreements to sell 10% interests in eight Indonesian Kutei Basin PSCs held through Searah, its 50:50 venture with Petronas. The deal is subject to approvals, and its terms have not been disclosed. Elsewhere, Harbour Energy’s Andaman interests are seen as a likely farm-down, Vietnam’s Ken Bau holds 3.7 trillion cubic feet (Tcf) of recoverable resources, and Inpex is targeting an FID on Abadi in 2027.

Only one transaction is signed, and the rest are marketed or potential deals. You should treat most of this pool as a pipeline of possibilities rather than completed price discovery.

Why majors leave, independents need partners and NOCs pick their spots

The supply of assets comes from three seller types, and each is selling for a different reason.

Majors

Rystad’s Kartik Selvaraju says majors are exiting markets where the growth potential is modest, freeing themselves to focus on a small number of core basins. When they do move into frontier areas, they tend to do so alongside partners so the exposure is shared. Chevron’s shrinking regional footprint fits this pattern.

The retreat of majors from low-growth basins is part of a wider pattern of oil and gas consolidation, in which companies concentrate capital on a few core positions and sell the rest.

Independents

Independents face a funding problem rather than a strategy problem. Harbour’s Andaman discoveries sit between appraisal and development, and reaching FID will require more capital than one balance sheet can comfortably carry. Harbour’s US$215 million sale of Natuna Sea Block A and Tuna to Prime Group in May 2026 was a separate transaction and did not involve the Andaman assets.

National oil companies

NOCs are the most selective participants on both sides of the market. Petronas presents its Searah venture and other farm-outs as a way to use capital efficiently and share risk while keeping exposure to strategic resources. Wood Mackenzie sees renewed NOC and international oil company interest, but it warns that project economics remain fragile.

The contrast is sharp:

• Majors want simplicity and lower capital intensity.
• Independents want funding and risk-sharing.
• NOCs want supply security, domestic control and local value.

Because sellers want different things, you should expect deals to be structured around those motives rather than awarded to the highest bidder alone.

How farm-downs work, and who is positioned to buy

A farm-down is the most common tool in this market. In a farm-down, an existing owner transfers part of its project interest to a new partner. The mechanics usually run in this order:

1. The incoming partner pays cash consideration for the interest.
2. It takes on an agreed share of future development and operating costs.
3. It may reimburse part of the seller’s past spending.
4. The seller keeps a minority stake and its share of future upside.
5. Governments, regulators, host NOCs and sometimes existing partners must consent. The deal can also change who operates the asset.

The Kutei sale shows the logic in practice, although Eni describes it as a stake sale rather than a farm-down. Pertamina is taking interests in East Sepinggan, North Ganal and Rapak. Medco Energi is taking West Ganal, East Ganal, Ganal and Muara Bakau.

Abadi’s partners are Pertamina Hulu Energi and PETRONAS Masela. Its May 2026 agreements in principle on offtake (advance commitments to buy future gas) with BP, PGN, PLN EPI, Shell and Pupuk Indonesia support future sales contracts, but they are not an FID.

Rystad anticipates that Petronas will front the coming round of home-market asset sales, with Pertamina next in line. The likely state-linked buyers are:

• Petros for Sarawak assets
• SMJ Energy for Sabah
• TI EP, a non-operating partner in PM6/12 off Terengganu

These NOCs are not replacing majors one for one. Knowing the natural buyer in each region shows you where bids are most likely to cluster, and where competition will keep pushing premiums higher.

Selective boom or overheated market? Weighing the risks behind record prices

The case for the premium

There is a real argument for today’s prices:

• Large, well-located gas resources are scarce.
• Buyers value assets that can supply domestic markets or support LNG projects.
• Development assets carry less geological and permitting uncertainty.
• The US$6.7 billion of 2025 volume shows that demand is real.

Where the premium looks exposed

The risks build quickly, however:

• 72% of the resource base is pre-FID.
• Two consecutive dry wells in Eni’s Vietnam portfolio have increased pressure on Ken Bau.
• The Kutei closing depends on government approvals.
• Abadi’s FID is still only targeted for 2027, despite front-end engineering design (FEED) and preliminary offtake agreements.
• Long-cycle gas faces energy-transition risk.

Thin margin for error Wood Mackenzie puts most new deepwater-gas projects near a 15% base-case IRR. That leaves little room for cost inflation, lower gas prices or delays.

Gas prices add further uncertainty. Industry estimates, which have not been independently confirmed, put the historical average near US$4 per thousand cubic feet (Mcf), an optimal threshold closer to US$6/Mcf, and a level around US$7.5/Mcf at which up to 95% of planned developments could become economic.

Taken together, the evidence supports a selective boom rather than a blanket case for US$9.8/boe. You should read the premium as justified only where a buyer has a credible route to FID, funding and offtake. Where it rests on price assumptions alone, it looks risky.

The thin 15% base-case return is only one of the deepwater gas risks facing regional developers, alongside cost inflation, schedule slippage and exposure to weaker gas prices.

Past performance does not guarantee future results. Financial projections are subject to market conditions and various risk factors.

What this means for capital allocation as the 2027 pipeline arrives

The framework comes down to four tests. Identify why the seller is exiting, name the natural buyer, understand the structure of the deal, and check whether the valuation rests on a credible path to development.

Three signals deserve your attention:

1. Approval and completion of Eni’s Kutei sales
2. Any named buyer for Chevron’s North Malay stake or Harbour’s Andaman farm-down
3. Abadi’s progress towards FID

No buyer or value has been disclosed for Chevron’s stake, Andaman, Ken Bau or an Abadi farm-down, so none of these deals should be treated as done. If the current pattern holds, capital is likely to concentrate in strategic gas positions backed by state-linked partners. Valuations may stay firm where buyers can deliver development and soften where they cannot.

For readers weighing Indonesian exposure, our deep-dive into Indonesia’s upstream boom assesses what the country’s untapped basins signal for investors.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions. Forward-looking statements are speculative and subject to change based on market developments and company performance.

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