May

30

Ras Laffan repriced LNG’s geopolitical risk premium, and the market structure that existed through 2025 can no longer be assumed.

On March 18 and 19, 2026, Iranian missile and drone strikes on QatarEnergy’s Ras Laffan Industrial City damaged two of fourteen LNG trains and one of two gas-to-liquids facilities. The result is the largest single supply disruption in LNG’s history: roughly 12.8 MTPA — about 17% of Qatari export capacity — sidelined for three to five years. Replacement gas turbines for the refrigeration compressors have lead times of two to four years from three global manufacturers. QatarEnergy declared force majeure to buyers in China, South Korea, Italy, and Belgium; Shell declared force majeure downstream; and Omani trading house OQ did the same for Bangladesh. As of late May, force majeure has been extended through mid-August for some buyers, and the Strait of Hormuz remains largely closed to tanker traffic under a fragile U.S.–Iran ceasefire.

The 2025 trade matrix is the appropriate reference for determining where LNG lands.

The baseline. In 2025, global LNG trade totaled approximately 426 MTPA. Asia accounted for 63.6% (271 MTPA), Europe for 29.3%, the Middle East and Africa for 4.2%, and the Americas for 2.8%. On the supply side, the Atlantic basin produced 41.3% (176 MTPA), the Pacific 35.9% (153), and the Middle East 22.8% (97). The country-level figures behind these shares were concentrated: the United States, Australia, and Qatar each exported between 78 and 85 MT in 2024, while on the import side, China, Japan, and South Korea each imported between 47 and 79 MT. The headline reading was that Asia was the diversified buyer — 56.5% Pacific, 30.3% Middle East, 13.3% Atlantic — Europe was Atlantic-captive (92.8%), and the Pacific basin’s entire output flowed to Asia. That matrix described an integrated market at the macro level; in practice, it was three regional sub-markets stitched together by arbitrage.

Where the shock lands hardest. Asia’s 30.3% share of Middle East supply — long treated as a supply-security buffer — has been revealed to be a concentrated tail risk, yet resilience within Asia is asymmetric. China and South Korea both sit on QatarEnergy’s force majeure list, and their long-term oil-indexed sale-and-purchase agreements (SPAs) do not pay out at $18 JKM. South Korea has no real alternatives; China does and is using them. Europe’s exposure is structurally different: only 9 MTPA flowed from the Middle East in 2025, but Europe’s higher spot share means it absorbs the global price shock regardless of direct exposure. TTF traded around $14.80/MMBtu in late April, roughly 35% above pre-conflict levels; JKM traded in the high $16s to low $18s through May.

Where the buffer is — and isn’t. The Pacific basin has no spare capacity. Its 153 MTPA ran flat-out to Asia in 2025, and LNG Canada’s Kitimat ramp has not yet meaningfully changed that arithmetic. The Atlantic basin — the U.S. Gulf in particular — becomes the swing supplier, but the swing is tighter than headlines suggest. U.S. LNG exports averaged 17.6 bcf/d in February 2026, roughly 3 bcf/d (about 22 MTPA annualized) above year-ago levels as Plaquemines and Corpus Christi III ramped — the first meaningful offset to the Gulf disruption, though existing terminals are now running essentially at nameplate. Henry Hub has remained range-bound, and the stability is structural rather than coincidental. U.S. LNG export prices are indexed to Henry Hub plus liquefaction tolling fees, and the great majority of U.S. liquefaction is already committed under long-term offtake contracts. With no surplus capacity to respond to a higher-priced global market, international arbitrage cannot pull additional U.S. volumes through, and therefore cannot pull Henry Hub higher; the spread accrues instead to the off-takers holding Henry Hub-indexed cargoes that they sell into JKM and TTF markets trading at multiples of their input cost. The new wave of U.S. projects under construction — Plaquemines, Corpus Christi III, Rio Grande, Port Arthur, and Golden Pass — is now pricing into a different world than the one for which their final investment decisions (FIDs) were made.

Where the demand response is taking the strain. The shock has been absorbed less by supply replacement than by buyer behavior, and Asia and Europe are responding very differently. Chinese LNG imports for January through April totaled 18.0 MT, down roughly 10% year-over-year and the lowest since 2019. Chinese buyers are actively re-offering Qatari long-term cargoes into the European spot market (Kemp, LSEG Commodities Forum, May 2026). China can do this because Qatari LNG accounted for only about 15% of total Chinese gas imports in 2024 — pipeline gas from Turkmenistan, Russia, Kazakhstan, Myanmar, and Uzbekistan supplied roughly 53 MTPA, with Australian LNG adding another 26 — and because 47% of Chinese gas demand is industrial, allowing manufacturing-margin demand destruction that Europe’s household-and-power-dominated load cannot easily match. South Korea, with no comparable buffer, is bearing the brunt of the disruption directly. Europe, meanwhile, has paradoxically deferred LNG purchases despite storage at 36.7% on May 18, compared with a 10-year norm of 45–49%. EU LNG send-out in April was essentially flat year-over-year at 131 TWh, well below the technical capacity of 238 TWh. The European bet is on price retracement; if it does not arrive, the summer refill window will be tight.

The Hormuz dimension compounds the kinetic damage. Of the roughly 84 MTPA of Qatar and UAE LNG sent through the Strait of Hormuz in 2024, 12.8 MTPA represents the kinetic loss, expected to take three to five years to recover; the balance is suspended by the chokepoint closure and will return as the Strait reopens. The market is therefore pricing two recoveries on different timelines and writing the security premium against the worst of them. The premium on Middle Eastern LNG will remain higher than the 2025 cost stack assumed, regardless of how quickly the kinetic damage is repaired — buyers signing 20-year SPAs after March 2026 will not include the same indemnity language, and lenders underwriting new Middle Eastern liquefaction will not assume the same return profile.

Russia is the latent alternative — held by politics, not geology. Russia sits on some of the world’s largest unmonetized gas reserves and remains the most consequential variable not yet in the trade matrix. Russian LNG exports totaled 33.5 MT in 2024 — primarily from Yamal LNG on the Arctic peninsula and Sakhalin-2 in the Pacific, with Arctic LNG 2 largely sidelined by Western sanctions on shipping, equipment, and finance. About half of Yamal LNG continues to flow to Europe under pre-existing contracts. Pipeline gas to Europe collapsed from roughly 150 bcm in 2021 to about 25 bcm in 2024, following the 2022 invasion of Ukraine and the January 1, 2025, expiration of the Ukraine transit corridor. Power of Siberia 1 to China reached approximately 31 bcm in 2024, on track for its 38 bcm design capacity, with a contractually agreed expansion to 44 bcm.

The proposed Power of Siberia 2 — a 50 bcm/yr line from Yamal to China via Mongolia — is the single largest piece of latent supply in global gas. Moscow signed a legally binding memorandum with Beijing in September 2025 and had hoped the Iran war would push final commitment at the May 20–21, 2026 Putin–Xi summit. It did not. Talks remain stalled over pricing (China wants gas close to Russia’s domestic rates; Russia wants European-style market indexation), financing terms, and Beijing’s reluctance to deepen single-supplier dependence after Hormuz had demonstrated that risk in reverse. Chinese industry sources estimate construction at eight to ten years even after FID. Russia therefore has the resource base to displace a meaningful share of the post-Ras Laffan market, but its three near-term levers — Arctic LNG 2, Yamal LNG expansion, and Power of Siberia 2 — are all gated by political rather than physical constraints.

The expansion question. Qatar’s North Field East and North Field South projects — together adding roughly 48 MTPA between 2026 and 2030 — remain on the books, with the first NFE train still nominally targeted for Q3 2026, pending infrastructure integrity assessments. Whether that schedule holds is now the central question for global supply growth through 2028. Every quarter of slippage shifts pricing power to U.S. Gulf and Australian producers and improves the marginal economics of projects further out: Mozambique, the GTA project off Senegal–Mauritania, and Alaska LNG if it reaches FID.

Local pressures point in the same direction. Peru is reexamining export priorities as Camisea reserves face roughly two decades at current rates, and Australia is debating reserving east-coast gas for domestic use. The Qatar event accelerates the same logic globally — producing nations will price domestic supply and energy-security considerations more aggressively into export decisions, and importing nations will think more carefully about their exposure to chokepoints.

Repricing the security premium. The 2025 matrix described a market in which geography determined trade flows, contract structure allocated risk, and basin diversification served as a form of supply security. Ras Laffan demonstrated that the same geographic rigidity that defines LNG also concentrates geopolitical risk in specific producers and chokepoints. LNG remains the indispensable mechanism for monetizing stranded gas, and roughly 150 MTPA of liquefaction under construction suggests that demand will continue to absorb it. But it is now priced with a security premium that the 2025 cost stack did not anticipate. Even a sanctions realignment would not relax that premium quickly: LNG export terminals take years to design and build and require billions of dollars of capital, underpinned by long-term offtake contracts that sanctioned producers cannot readily attract. For Atlantic producers, that premium accrues as netback; for Asian importers, as the cost of holding redundancy; for Europe, as the cost of structural exposure to a global spot market whose marginal supplier just sat behind a chokepoint that closed.

Note: Figures are in million tonnes per annum (MTPA). The 2025 trade matrix is the author’s construction. Country-level 2024 reference figures and the demand-side analysis of Chinese imports, European storage, and U.S. export ramp draw heavily on John Kemp’s May 21, 2026, presentation to the LSEG Commodities Forum (Base Research), with underlying data from GIIGNL, Gas Infrastructure Europe, China General Administration of Customs, and the U.S. Energy Information Administration. The Russia section draws on Gazprom export disclosures and contemporaneous reporting on the May 20–21, 2026, Putin–Xi summit. Price data are current as of late May 2026.


Comments

Name

Email

Website

Speak your mind

Archives

Resources & Links

Search