By 2030, roughly half of global LNG production capacity will sit in two countries. Under an extended disruption to Gulf LNG supply, Wood Mackenzie estimates global availability could run approximately 70 mmtpa below pre-conflict levels to 2035. Seven floating LNG projects sanctioned since 2023, adding 18 mmtpa of new capacity across six countries, represent the market's most direct response to both pressures.

New Wood Mackenzie research identifies four forces shaping whether that momentum continues: FLNG's role in supply diversification, its position as a strategic rather than opportunistic tool, the redeployment economics that distinguish it from fixed onshore infrastructure, and a structural gap in commercial ownership that constrains its next growth phase.

"Seven projects sanctioned in three years, backed by infrastructure investors, IOCs, and LNG traders, is not a technology bet," said Fraser Carson, Principal Research Analyst, Global LNG, Wood Mackenzie. "The cost gap with onshore has closed and floating LNG now competes on merit in the locations that matter. Cost and technology are no longer the constraints. The question is whether commercial structures catch up with the opportunity. One company currently provides FLNG as a service to the entire global market. That single provider sits opposite a pre-FID pipeline of over 80 mmtpa."

The diversification case is geographic, not volumetric. All proposed new LNG capacity in South America and West Africa is based floating design concepts. For producers in Argentina's Vaca Muerta and across West African gas provinces, floating LNG is frequently the only credible export route. The technology accounts for less than 10% of new global liquefaction supply but its value lies in reach, opening resources that conventional approaches cannot serve, not in the aggregate volumes it delivers.

FLNG remains a deliberate choice rather than a default. Where it competes directly with low-cost modular onshore projects, the economics can be tight. Where it commercializes stranded or offshore resources with no alternative path to market, the case is clear. The question for developers is not whether the technology works, but where.

The economics confirm a cost threshold has been crossed. The June 2026 final investment decision on Delfin LNG FLNG 1, the first floating LNG export facility in the United States and, at 4.4 mmtpa, the largest single FLNG unit sanctioned globally, came in at approximately US$932 per tonne, competitive with recent onshore US LNG FIDs. Conversions and standardised newbuilds can reach market at or below the sector benchmark of approximately US$950 to US$1,000 per tonne. Plant breakevens for recent projects cluster between US$2.3 and US$4.6 per MMBtu. FLNG fleet utilisation averaged 88% in 2024 and 2025, above the 85% onshore average. Operating costs remain structurally higher than onshore, running at approximately 3 to 5% of total capex per year.

Redeployment is the investment attribute that distinguishes FLNG most from fixed onshore infrastructure. Redeploying an existing vessel costs a fraction of building new: Hilli's redeployment costs to date stand at approximately US$350million, against US$1.5 to US$2 billion for a newbuild FLNG. That difference funds a market entry, not a maintenance budget. Golar LNG's Hilli vessel recovered its approximately US$1.3 billion conversion cost across an eight-year Cameroon charter by 2023, generating approximately US$2.1 billion in tolling EBITDA in the process. A redeployment budget of approximately US$350 million and roughly one year of downtime now unlocks a 20-year charter in Argentina with Southern Energy. That single contract is expected to produce approximately US$5.9 billion in contracted revenues. No fixed onshore plant can replicate that sequence. Moving within a 30 to 35-year hull life also cuts exposure to upstream resource depletion and single-country risk.

The sector's most visible structural gap is commercial. Of 15 operational and under-construction FLNGs, 12 are project-owned and three are lease-and-operate, all belonging to Golar LNG, which committed to a fourth vessel on a speculative basis in 2026. The lease-and-operate model transfers construction and financing risk to the vessel owner, lowering the capital barrier for frontier producers who lack the balance sheet for a fully integrated project. One provider serving the entire market is a constraint. With well over 80 mmtpa of known FLNG proposals in the pre-FID pipeline, and an additional 160 tcf of undeveloped upstream assets suited to FLNG globally, the opening for new entrants is substantial.

Key details:

• Seven FLNG units sanctioned since 2023, totaling 18 mmtpa across six supply locations
• Global FLNG capacity projected to reach 37 mmtpa by 2031
• Delfin LNG FLNG 1: 4.4 mmtpa; approximately US$932 per tonne; FID 3 June 2026
• Plant breakevens for recent projects: US$2.3 to US$4.6 per MMBtu
• FLNG fleet utilisation: 88% in 2024 to 2025, versus 85% for onshore
• Pre-FID pipeline: over 84 mmtpa globally across four regions
• Lease-and-operate model: three units, one provider globally

Background:

Analysis draws on Wood Mackenzie Lens LNG Asset Discovery and Lens LNG Valuations. Supply-demand context references the April 2026 Global Gas Strategic Planning Outlook. Project economics are modelled at a 10% discount rate in real 2026 terms, meaning all cost figures are adjusted to remove the effects of inflation and expressed in 2026 dollar values for comparability across projects. Coverage spans all 15 operational and under-construction FLNG projects globally. Gulf LNG disruption scenarios are modelled under Summer Settlement and Extended Disruption assumptions.