Losers and winners from the Qatari LNG disruption

While European and Asian importers have been hit hard by the disruption in Qatari LNG to varying degrees, the crisis has both short- and long-term benefits for US exporters and other LNG competitors.

WHAT: Iran’s March 2 blockade and subsequent strikes on Ras Laffan halted Qatari LNG exports and damaged 17% of capacity, tightening global supply and forcing Europe and Asia into direct competition for alternative volumes.

WHY: Qatar’s outsized role in global LNG—combined with Europe’s depleted storage, Asia’s heavy reliance on Gulf supply and limited spare capacity elsewhere—has amplified the shock, while delays to expansion projects extend its impact.

WHAT NEXT: Prices and competition for cargoes are set to remain elevated, with US exporters capturing near-term gains and new projects gaining momentum, while policymakers face mounting pressure to adjust storage targets, supply strategies, and geopolitical alignments.

We are now entering the tailend of Qatari LNG supply, with only a handful of cargoes still on the water while the Strait of Hormuz remains blocked, with key Asian and Europe now locked in a fierce competition for replacement supplies. Gas importers the world over will be hit hard by the crisis, although some will fare better than others, and another key question is which rival suppliers to Qatar will benefit from the disruption.

Iran began its blockade of Hormuz on March 2, forcing QatarEnergy to announce a force majeure on LNG export contracts after it had to halt production at its Ras Laffan complex, disrupting a fifth of global LNG supply. Iran later struck the country’s liquefaction facilities with missiles, damaging two LNG trains equivalent to 17% of Qatari capacity that are expected to remain offline for three to five years. Qatar has also delayed work on its expansion plans at Ras Laffan. 

This means the impact on global LNG capacity will last for much longer after the current crisis is resolved. Prior to the disruption, there were worries of a growing supply glut emerging over the next few years, which have all but gone now. 

Qatar has also delayed the launch of the North Field East expansion project, which had been expected this year, eventually increasing the country’s LNG production from 77 to 110mn tonnes per year. The completion of future expansion phases, including the North Field South and North Field West projects, which had been anticipated to start up in 2028 and 2030 respectively, adding another 16mn tpy each, will also undoubtedly be affected.

European gas security in peril

Europe was already in a precarious situation pre-crisis, having gone through a colder than usual winter which depleted its gas storage volumes. Despite warmer weather gas withdrawals continue, with facilities at 28.4% of capacity as of March 23. 

TTF front-month prices are currently at just above €50 per MWh ($618 per 1,000 cubic metres), barely different from futures contracts next year. If this situation persists, there will be no incentive for traders to stockpile gas in the coming months with a view to selling them when colder weather once more arrives. The EU will therefore have difficulty reaching its target of gas storage utilisation of 90% by next November. 

According to the Financial Times, European Energy Commissioner urged member states last week to lower their targets to 80% to curb excessive buying during the current crisis. But this will leave the bloc more vulnerable to supply shocks next winter. 

Making matters worse, the EU is due to phase out remaining Russian pipeline and LNG imports over the next year and a half, which will further exacerbate the situation. While the complete cessation of supplies will not happen until next autumn, the material impact will be felt as soon as April 26, when short-term contracts for LNG will be banned. Two months later short-term contracts for pipeline gas will be banned as well.

For the time being, both the European Commission and the majority of member states remain committed to seeing the plan through, save for the usual objections from countries still heavily dependent on Russian gas such as Hungary and Slovakia. Whether that resolve as the LNG disruption continues remains to be seen. 

There is a further risk that Moscow could terminate supplies sooner, exploiting the current crisis to put pressure on Europe. Russian President Vladimir Putin threatened to do just that on March 5, linking the decision to the EU’s phase-out of Russian gas. Furthermore, Russia’s Gazprom accused Ukraine on March 19 of trying to disable key pipelines that carry Russian gas to Turkey, Hungary and Slovakia by targeting Black Sea coast facilities with drones.

So far, Europe’s policy response to the current crisis appears to be lacking. Beyond discussing a potential delay to the phase-out of Russian gas, the European Commission has faced criticism for once more considering a cap on gas prices. Energy industry associations have warned that such a move would handicap Europe’s ability to attract desperately-needed LNG away from Asia. 

Meanwhile, few governments have called for greater domestic gas supply to shore up the bloc’s energy security. Besides Norway, North Sea producers have maintained various policies that have limited domestic gas development, including a windfall tax and a licensing ban in the UK. 

In the Netherlands, meanwhile, there have been few calls to restart the giant Groningen field in the event of an emergency. The field was closed in October 2023 after years of causing minor earthquakes that damaged property in the area but no confirmed fatalities. NewsBase made the case in the 2021-23 energy crisis for reopening Groningen but distributing a share of profits from production to local residents. Some output could be brought back on stream within months, as its wells are idled but not permanently dismantled.

Uneven risks in Asia

Asia felt the disruption in Qatari shipments before anyone else, simply because it normally absorbs more than 80% of Qatar’s LNG exports. That does not mean the impact will be uniform. The region’s large, portfolio-based importers such as China, Japan, South Korea and Taiwan are far better placed to absorb the shock than the more price-sensitive South Asian buyers, which have less contractual flexibility, weaker balance sheets and far less room to pay up for spot cargoes. Still, most Asian buyers have much less storage capacity than those in Europe, meaning there is less of a cushion to supply shocks.

China should be more resilient than Europe or South Asia, though not immune. Chinese LNG imports fell 14% in 2025 to 67mn tonnes, as weak industrial activity, rapid renewable buildout, higher domestic gas production and increased pipeline gas imports from Russia reduced the country’s need for marginal LNG. LNG in China remains a supplemental fuel that often struggles to compete on cost with domestic output and piped gas, as well as coal, while pipelines from Russia are already near capacity. That gives China some insulation from extreme spot prices, but also limits its ability to fully replace lost Qatari volumes via pipelines.

Beijing is no longer taking direct US LNG cargoes, even though Chinese firms still trade and redirect US volumes globally. China could resume these imports if needed, which would deprive Europe from further supplies.

Japan is also relatively well placed. Only a small share of its LNG supply—roughly mid-single digits—normally transits Hormuz, and direct reliance on Qatar is limited compared with other Asian buyers. Utilities hold relatively comfortable inventories, and the country’s procurement is dominated by long-term contracts with diversified suppliers, particularly Australia and the US. Large buyers such as JERA, Tokyo Gas and Osaka Gas retain portfolio flexibility and access to spot markets if required. The bigger risk for Japan may be indirect: higher oil prices and petrochemical feedstock shortages could weigh on industrial output and gas demand, rather than physical shortages of LNG itself.

South Korea sits in a similar position to Japan, but with slightly greater exposure to spot market dynamics. As the world’s third-largest LNG importer, it relies heavily on long-term contracts, including volumes from Qatar, Australia and the US, which provides a strong baseline of supply security. State-owned KOGAS also maintains strategic inventories that can be drawn down in the event of disruption. However, Korea tends to be more active in the spot market than Japan, particularly during peak demand periods, meaning it is more exposed to price spikes. In a tight market, Seoul may need to pay a premium to secure incremental cargoes, although its strong credit profile ensures it can remain competitive against European buyers.

Taiwan is smaller but structurally more vulnerable. LNG accounts for a large and growing share of its power generation mix as the island phases out nuclear capacity, leaving it heavily dependent on imports with limited domestic alternatives. CPC Corp relies on a mix of long-term contracts and spot purchases, but with less portfolio depth than Japan or Korea. Storage capacity is also more constrained, reducing the system’s ability to absorb prolonged supply shocks. Taiwan can still compete for cargoes financially, but a sustained period of elevated prices would feed directly into power costs and potentially strain the island’s energy system.

India is in a much more difficult position. It is the world’s fourth-largest LNG importer and relies on Qatar for roughly 40% of its gas imports. New Delhi began rationing gas almost immediately after Qatari supply was disrupted, cutting volumes to industrial users in anticipation of tighter availability. The problem for India is not only dependence on Qatar, but the structure of its gas market: it has enough financial and commercial heft to compete for replacement cargoes, but paying up for them would quickly feed through into fertiliser costs, city gas distribution and industrial demand destruction. Disruptions have also spilled into LPG markets, underlining how quickly Gulf supply shocks can cascade across fuels.

Bangladesh and Pakistan remain the most vulnerable buyers in Asia. Both countries have already experienced the consequences of being priced out of the LNG market during previous crises. Bangladesh has been forced to procure spot cargoes at elevated prices, ration gas and shut fertiliser plants to preserve supply for power generation and essential services. Pakistan’s situation is more complex. It is heavily reliant on Qatari LNG under long-term contracts, but delayed deliveries may offer short-term relief as the country grapples with weak demand, curtailed domestic production and a rapid expansion of solar generation. That should not be mistaken for resilience. Pakistan’s ability to withstand a prolonged disruption rests less on supply security than on suppressed demand and an inability to compete for expensive spot cargoes.

US comes out on top

The US, controversially given that it started the war against Iran, has emerged as one of the clear beneficiaries of the crisis — both in the short term thanks to higher prices and the long term, as the Hormuz disruption could make buyers more reluctant to rely too greatly on Qatari supply in the future.

Although exporters have little immediate scope to lift output, with liquefaction plants already operating close to full capacity, they are nonetheless capturing significant upside from elevated global gas prices. That said, the gains are far from evenly spread.

Among US suppliers, Venture Global appears particularly well positioned. Its 20mn-tpy Plaquemines LNG facility, which began producing in December 2024, remains officially in the commissioning phase. As a result, the company retains the ability to sell volumes into the spot market rather than being bound by long-term contractual commitments, giving it unusual exposure to current price spikes. Venture argues that the extended commissioning period reflects the phased ramp-up of a modular, midscale design and the fact that the plant has yet to reach full operational capacity.

There was a similar situation at Venture’s Calcasieu Pass facility, which took more than three years to transition from first cargo to full commercial operations in April 2025. That prolonged ramp-up allowed the company to monetise periods of high prices, though it also led to a series of legal disputes with buyers, most of which have been resolved in Venture’s favour,

By contrast, more established exporters such as Cheniere, which sell the bulk of their volumes under long-term agreements, have more limited exposure to spot price upside. Their revenues are therefore less sensitive to the current surge in global LNG prices.

If the disruption persists, US producers may attempt to extract additional value by postponing maintenance and running plants at maximum utilisation. Even so, spare capacity remains limited in the near term. Incremental supply will come primarily from projects already under construction, including Cheniere’s Corpus Christi Stage 3 expansion, where Train 5 produced its first LNG in February and two further trains are due online this year. The Golden Pass project, led by ExxonMobil and QatarEnergy, is also expected to deliver its first cargo shortly.

The crisis could also make US LNG more appealing in the long term, as buyers seek to diversify away from heavy reliance on a single export hub in the Gulf. On the other hand, Qatar still beats the US on cost, and so importers will still want to strike a balance between affordability and reliability.

Another constraint is the relatively thin pipeline of projects ready to move forward, beyond those that have already reached a final investment decision (FID).  Those closest to advancing include the 9.5mn tpy Commonwealth LNG project, alongside Delfin LNG, Amigo LNG and further expansions at Cheniere facilities. Further out, the proposed 20mn tpy Alaska LNG project could benefit from shorter shipping distances to Asia, but its estimated $44bn cost makes it a far more challenging proposition.

While the disruption may encourage a shift away from reliance on a single LNG hub in Qatar, it is unlikely to reduce overall market concentration. Instead, supply would become more heavily centred on the US, already the world’s top exporter.

Winners elsewhere

Outside the US and Qatar, the list of projects capable of materially increasing LNG supply this decade is relatively short, and many of the most credible candidates remain some distance from FID.

Canada stands out as the most advanced alternative. The first phase of LNG Canada is already operational at 14mn tpy, while a second phase could lift capacity to 28mn tpy, with an FID expected in 2026.  Elsewhere in British Columbia, the proposed 12mn-tpy Ksi Lisims project has secured federal approvals and signed long-term sales agreements with Shell and TotalEnergies. The project is also targeting an FID this year.

Argentina is emerging as another contender, as the government seeks to unlock exports from the Vaca Muerta shale formation. Southern Energy has already taken FIDs on two floating LNG units with combined capacity of 5.95mn tpy, due to start up in 2027 and 2028. In parallel, the larger Argentina LNG project led by YPF, Eni and ADNOC’s XRG, with an FID on its first 12mn-tpy phase expected this year, and first cargoes on the water by the early 2030s.

In Mozambique, TotalEnergies and the government relaunched the 13mn-tpy Mozambique LNG project in January after a prolonged suspension linked to insurgency risks, with first output now targeted for 2029. ExxonMobil’s separate 18mn-tpy Rovuma LNG project lifted force majeure in late 2025 and is also expected to move towards FID this year. In the nearer term, Eni’s Coral North FLNG, with a capacity of 3.6mn tpy is scheduled to come online in 2028.

Offshore Mauritania and Senegal, BP and Kosmos Energy have brought the first phase of the Greater Tortue Ahmeyim project into production, delivering around 2.3mt/yr. A second phase, still awaiting FID, could raise capacity to around 5mn tpy in the early 2030s.

Tanzania represents a large but slow-moving opportunity. The government expects to finalise agreements for the long-delayed 10mn-tpy Tanzania LNG project, led by Shell and Equinor, by mid-2026. However, regulatory uncertainty has continued to stall progress, and first production is unlikely before the middle of next decade.

In Australia, Woodside continues to advance the Browse project, which could underpin around 11.4mn tpy of LNG supply, though it remains at an early stage and has yet to complete FEED. The Greater Sunrise project, spanning Australian and Timorese waters, is even less advanced. Despite renewed political momentum, the 5mn tpy development is unlikely to deliver first gas before 2032 at the earliest.

Nigeria LNG is aiming to bring a seventh 4.2mn-tpy train online in 2027, while local firm UTM Offshore has repeatedly delayed an FID on a proposed 2.1mn-tpy floating LNG facility, now targeted for start-up in 2029.

Enter Russia

As stated, the EU remains steadfast so far on quitting Russian gas. But there may be other benefits to Russia from the current crisis. The US-sanctioned Arctic LNG-2 project in the Russian Arctic began shipments last autumn but so far to only a single port in China. Depending on the length of the Hormuz disruption, other Asian buyers may be compelled to take shipments from the terminal, even if this means risking sanctions wrath from Washington.

Reduced global LNG supply could also strengthen the case for Russia’s long-delayed Power of Siberia 2 gas pipeline, which would carry 50bn cubic metres (bcm) per year of gas from the Arctic to China. Even so, Beijing may remain reluctant to back the project by signing a long-term supply contract because this would too heavily deepen its reliance on Moscow.