Woodside Energy: How a Perth Gas Company Became a Global LNG Builder

Woodside is now a global LNG company that happens to be headquartered in Perth. That shift — from a North West Shelf partner with Australian assets to an operator with projects in the United States, Mexico, Senegal and Trinidad — happened in under four years, and it changes how the company should be analysed. The relevant comparison is no longer Santos; it is the international LNG developers Woodside now competes against for capital, buyers and construction slots.

How did Woodside become Australia’s largest energy company?

Through the North West Shelf and then through a single transformational transaction. Woodside was founded in 1954 and spent decades as a participant in the North West Shelf Venture off Western Australia, Australia’s first and largest LNG project, alongside international majors. It was a good business with a narrow footprint.

The change came in 2022, when BHP merged its petroleum division into Woodside in exchange for Woodside shares, which BHP then distributed to its own shareholders. The transaction roughly doubled Woodside’s production, added assets in the Gulf of Mexico, Trinidad and Algeria, and required no cash outlay. For BHP it was a clean exit from oil and gas; for Woodside it was instant global scale.

The result is a company producing at a scale that supports genuinely large projects. Record annual production of 194 million barrels of oil equivalent in 2024, world-class operated LNG reliability of 98%, unit production costs around US$8 per barrel of oil equivalent, and net profit after tax of US$3.6 billion that year with a fully franked dividend at the top of the target payout range.

What is the Scarborough project and why does it matter?

Scarborough is a large offshore gas field around 375 kilometres off the Western Australian coast, developed with a floating production unit connected by pipeline to an expanded Pluto LNG facility onshore at Karratha. It is Woodside’s largest Australian development in more than a decade and the main source of near-term production growth.

Execution has been the story. The project was 94% complete at the end of 2025, the floating production unit arrived on location in January 2026, and first LNG cargo remains on track for the fourth quarter of 2026. In an industry where multi-billion dollar LNG projects routinely run years late and billions over budget, delivering to schedule is itself a competitive advantage.

Woodside also sold down equity along the way: LNG Japan took 10% of the Scarborough joint venture for US$910 million and JERA took 15.1% for US$1.4 billion. Those buyers are also long-term customers, which aligns interests and reduces the marketing risk that has undermined other LNG developments.

Why did Woodside buy into US LNG?

Because that is where the growth in global LNG supply is, and because Australian project approvals have become slow and contested. Louisiana LNG — formerly the Driftwood project, acquired from Tellurian in 2024 — gives Woodside a Gulf Coast position with access to abundant, cheap US shale gas and short shipping distances to Europe.

The final investment decision came in April 2025 on a US$17.5 billion, three-train, 16.5 million tonne per annum foundation development, which was 22% complete at year end and is targeting first LNG in 2029. Woodside brought in partners quickly: Stonepeak took 40% of the infrastructure entity and contributed 75% of capital expenditure across 2025 and 2026, while Williams acquired 10% of Louisiana LNG LLC and 80% of the Driftwood Pipeline.

Those transactions cut Woodside’s own capital commitment to US$9.9 billion, under 60% of total project capital expenditure, and discussions have continued on selling a further stake of up to 20%. The company also raised US$3.5 billion in an oversubscribed US bond issue, which tells you something about how debt markets view the credit.

What does the rest of the portfolio look like?

Sangomar in Senegal has been the standout. The field produced at its nameplate capacity of 100,000 barrels per day for most of 2025 at almost 99% reliability, generating US$2.6 billion of EBITDA on Woodside’s share since start-up — US$849 million in 2024 and US$1,702 million in 2025 — and recording no injuries in its first eighteen months of operation.

Trion, a deepwater oil development in Mexico operated with Pemex, was 50% complete at the end of 2025 and remains on target for first oil in 2028. Beaumont New Ammonia in Texas achieved first production in December 2025, with lower-carbon ammonia targeted for the second half of 2026 — Woodside’s main venture into products beyond hydrocarbons.

The portfolio has also been actively pruned. Woodside divested Greater Angostura in Trinidad, progressed an asset swap with Chevron that simplified its Australian holdings around operated LNG, and has consistently framed portfolio management as an ongoing discipline rather than an occasional event.

How exposed is Woodside to climate and approval risk?

Substantially, and in ways that have already delayed projects. Australian environmental approvals for offshore gas developments have been repeatedly challenged in court, particularly around consultation with Traditional Owners and the assessment of downstream emissions, and the Browse development remains the clearest example of a resource that has been technically viable for decades without reaching sanction.

The Safeguard Mechanism reform requires large emitting facilities to reduce covered emissions on a declining baseline, which raises the cost of operating gas processing facilities in Australia over time and makes carbon capture or offsets a permanent line item rather than an optional extra. Woodside met a 2025 target of a 15% reduction in net equity Scope 1 and 2 emissions below its starting base and says it remains on track for the equivalent 2030 target.

Scope 3 is the harder problem. The overwhelming majority of emissions associated with Woodside’s product occur when customers burn the gas, and no producer has a credible mechanism to control that. This is the same structural tension facing every hydrocarbon producer, and it is why investor pressure has shifted from emissions targets toward capital allocation — whether shareholders would rather receive cash than see it committed to twenty-year assets.

What should investors watch in 2026?

Three deliverables, all of which Woodside has named explicitly: ramping up Beaumont New Ammonia, delivering the first LNG cargo from Scarborough, and keeping Louisiana LNG and Trion on schedule and budget. Each is a binary execution test, and Woodside’s valuation rests heavily on the market believing it can hit dates that most of the industry misses.

The financial question is the dividend. Woodside has historically paid out at the top of its target range while funding a heavy capital programme, which is only sustainable if project sell-downs continue to supply cash and if LNG prices hold. A period of weak prices during peak construction spending would force a choice between the payout ratio and the balance sheet.

The strategic question is whether the company is now too internationally weighted to be analysed as an Australian energy stock at all. With projects in Louisiana, Mexico, Senegal and Texas, Woodside’s earnings are increasingly driven by US Gulf Coast economics and global LNG spreads rather than by anything happening in Western Australia. Our companion piece on Santos covers the very different path taken by Australia’s second-largest producer.

How does Woodside compare with global LNG developers?

It sits in an unusual middle tier: too small to compete with QatarEnergy or the supermajors on balance sheet, too large to be a niche developer, and unusually strong on operating reliability. Operated LNG reliability of around 98% is genuinely best-in-class, and in a business where a plant outage means missed cargoes and contractual penalties, reliability converts directly into revenue.

The cost position is respectable rather than dominant. Unit production costs around US$8 per barrel of oil equivalent are competitive for a portfolio containing offshore Australian LNG, but Qatari expansion volumes and the newest US Gulf Coast trains will land at lower costs. Woodside’s answer is to be in both places rather than defend a single position.

Where it clearly differentiates is project delivery. The industry’s recent history is littered with LNG developments that ran years late and tens of billions over budget, and Scarborough tracking to schedule at 94% completion is a meaningful credential when marketing the next project to partners and lenders. Reliability of delivery is what allowed Woodside to attract Stonepeak and Williams into Louisiana LNG on favourable terms.

What does the shareholder base expect?

Cash. Woodside has historically paid a high proportion of underlying earnings as fully franked dividends, and a large part of its register — particularly the BHP shareholders who received stock in the 2022 merger — holds it for income rather than growth. The 2024 full-year dividend of US 122 cents per share, totalling US$2.3 billion at the top of the target payout range, is the benchmark those holders judge against.

That expectation constrains strategy. A company committed to a high payout while funding a multi-billion dollar construction programme has limited tolerance for cost overruns or price weakness, and the sell-down model exists partly to relieve that pressure. Each partial divestment converts future value into present cash that can support both capital expenditure and distributions.

The tension will be tested between now and 2029. Scarborough starts contributing in late 2026, but Louisiana LNG consumes capital until first LNG. That gap — heavy spending on one project while another ramps — is where dividend policy meets project delivery, and it is the single most useful thing to model when assessing the stock.

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