Not enough pipes to plug the leak

For the past decade the gas market has congratulated itself on diversification. LNG was the solution: a global, flexible, seaborne supply that would end the era of pipeline dependence and give buyers real optionality. Every major energy agency said some version of this. Every major utility board heard it.

Much of that story was true. What it underplayed was concentration on the supply side.

The world has indeed built a global LNG market. It has done so by constructing that market around a small number of very large fixed points – production complexes, export corridors, and import terminals – each handling volumes no other node can replace. The crisis that began on 2 March has not created this structural problem. It has made it visible.

What it has exposed is a system built around four critical nodes: one giant export complex, one narrow shipping corridor, an industry with almost no spare capacity and an import market more concentrated than its headline numbers suggest.

The first concentration: a single complex handles a fifth of global supply

Qatar’s Ras Laffan Industrial City is the world’s largest LNG export facility. Its 14 liquefaction trains process approximately 77 million tonnes per annum of LNG – around 20 percent of global supply from a single industrial complex covering a few square kilometres on the Gulf coast. In effect, one industrial site produces one cargo out of every five that moves through the global LNG market.

QatarEnergy halted production there on 2 March following Iranian drone strikes, declared force majeure, and sent buyers across three continents scrambling for replacement cargoes.

The scale of the shortfall is, by any historical comparison, extraordinary. Kpler’s vessel-tracking analysis published this week put the monthly supply hole at approximately 5.8 million tonnes with realistic replacement supply from all other global sources totalling under 2 million tonnes.

The arithmetic does not work. The volume that has disappeared is simply larger than the rest of the system can replace.

The US and Australia – the two other large exporters – are already running at high utilisation rates and cannot meaningfully increase output on short notice. Nigeria, Algeria and Trinidad face feed gas constraints rather than liquefaction capacity limits. The gap between the lost volume and the available cover is structural, not marginal.

The concentration at Ras Laffan is not an accident or an oversight. It is the logical outcome of decades of investment decisions that prioritised scale and efficiency. The North Field, which Qatar shares with Iran, is the world’s largest natural gas reservoir, and building a single giant complex to monetise it was the obvious strategy.

It produced a facility that is extraordinarily efficient and extraordinarily exposed. There is no distributed backup for a complex of this scale. Once the trains are down, the supply is gone until they restart – a process that, even after safe passage through Hormuz is confirmed, requires approximately two weeks of cool-down and recommissioning before the first cargo can load.

The LNG market diversified buyers. It did not diversify infrastructure.

The second concentration: a single strait is the only exit

Qatar’s gas reaches the world through one door. The Strait of Hormuz – 21 nautical miles at its narrowest point, with designated traffic separation lanes that compress the navigable channel further – is the sole maritime exit for every LNG cargo loaded at Ras Laffan. There is no alternative routing.

The Suez Canal option that occasionally appears in market commentary is not a true substitute. Sailing from Ras Laffan to Northwest Europe takes roughly 16–17 days via the Suez Canal but closer to 27–29 days around the Cape of Good Hope. The additional transit time increases freight costs and reduces the number of cargoes each vessel can deliver in a year – tightening shipping capacity precisely when the market needs more of it.

Under normal conditions Lloyd’s List data puts total cargo vessel traffic through the strait at around 100 ships per day. In the first days of March that throughput collapsed by more than 80 percent, with LNG carrier transits falling from eight on a typical Sunday to zero.

Insurance markets moved in parallel. War risk premiums escalated sharply in the first days of the crisis, and some coverage was withdrawn entirely, transforming manageable risk pricing into an operational impossibility for owners and operators.

This is the chokepoint that most discussions of LNG diversification have avoided examining carefully. The geographic argument was always: LNG gives buyers supply from multiple countries. That is true. What it omits is that a significant fraction of those multiple countries share a single exit corridor.

Qatar’s 20 percent of global supply does not merely come from one country – it comes through one waterway. The diversification benefit disappears at the point of export.

The third concentration: no spare capacity to absorb a shock

The instinctive market response to a supply disruption is to ask who can ramp up. In LNG, the answer in March 2026 is: not much, and not quickly.

Global LNG liquefaction operates at high utilisation rates. The IEA estimated, as of early 2026, that a large wave of new capacity was in the pipeline – around 325 billion cubic metres per year of projects under construction, set to come online between now and 2030. But projects under construction are not operational, and the gap between sanctioned capacity and available capacity is measured in years, not weeks.

The US, which exported a record 111 million tonnes in 2025 and now accounts for more than a quarter of global LNG supply, cannot meaningfully increase output. American terminals run at near-maximum utilisation, and the new trains coming online – Corpus Christi Stage III, Plaquemines Phase 2 – are ramping up on construction schedules, not emergency production timelines.

The LNG market was not built to carry spare capacity. The economics of project development require long-term offtake contracts that assume near-continuous operation. Building idle capacity into the system as a strategic buffer has never been part of the investment model – and it has never needed to be, because until this week no single supply point of this scale had gone offline without warning.

The global LNG system has no meaningful buffer.

The fourth concentration: Europe’s import infrastructure is thinner than it looks

The demand-side concentration is less discussed, but it matters for understanding how the shortfall propagates. Europe rebuilt its LNG import infrastructure rapidly after 2022, commissioning floating storage and regasification units across multiple countries to replace Russian pipeline gas. The REPowerEU story was one of successful diversification at the import end.

The reality is more concentrated than the headline capacity figure suggests.

Europe’s largest LNG receiving terminal is the Isle of Grain in the UK – a facility that, as of July 2025, is contractually committed to providing up to 7.2 million tonnes per annum of storage and regasification capacity to QatarEnergy under a 25-year agreement. The terminal that QatarEnergy chose as its primary European delivery point is now the terminal where Qatari gas cannot arrive.

South Hook in Milford Haven, the UK’s other large terminal, has historically received a significant share of its cargoes under Qatari supply arrangements. The two largest LNG receiving facilities in Europe have material exposure to the supply source that has just gone dark.

The wider picture reinforces this. Europe imported approximately 9.2 million tonnes of LNG from Qatar last year – roughly 8 percent of the continental total. But this aggregate masks individual country exposure: Italy holds a long-term supply agreement with QatarEnergy approaching 5 million tonnes annually, and several other countries face similar concentrated dependencies within their national supply portfolios.

European gas storage entered the current crisis at approximately 30 percent capacity – the lowest level since 2022 – meaning that the continent is competing for replacement Atlantic Basin supply precisely at the moment when it can least afford a prolonged bidding contest.

What the system is not designed to do

There is a version of the LNG market story that remains broadly intact. The US and Australia have not been disrupted. New capacity is coming. The demand-side response – particularly in price-sensitive South Asian markets – will provide some adjustment through load reduction. The crisis has not structurally broken the LNG market.

What it has revealed is the shape of the market’s limits.

A system designed to provide supply flexibility across multiple basins turns out to have most of that flexibility routed through a small number of nodes. Remove the largest single node without warning and the system’s ability to rebalance in the short term is severely constrained. Remove it through a geopolitical disruption that also closes the exit corridor, and the constraint becomes an arithmetic impossibility at the monthly scale.

The long-term supply wave – the 325 billion cubic metres of capacity under construction – does not help in the next three months. New liquefaction trains in Texas and Louisiana cannot accelerate their commissioning schedules. The FSRUs that Europe deployed post-2022 are useful but cannot replace Qatari long-term contract volumes that have no ready substitute at this scale. And the Ras Laffan restart, when it comes, requires safe passage through a strait where the geopolitical situation has no disclosed resolution timeline.

The investors who have spent the past four years pricing LNG infrastructure as a diversification play were not wrong in their premise. LNG does provide diversification relative to pipeline gas. The error – visible now in a way it was not before – was in assuming that the diversification properties of the seaborne market had no structural limits.

They do. Those limits are geographic, physical and concentrated – and a single geopolitical shock can expose all of them at once.

Three things to watch

The Hormuz transit situation is the primary indicator. Ras Laffan cannot restart in any commercially useful sense until vessels can move safely. Any change to the maritime security situation – in either direction – resets the timeline for when Qatari supply can return to the market. Watch for changes in insurance market coverage as the most sensitive real-time signal: war risk premium levels and the availability of cover move faster than official statements.

The European storage trajectory through April and May is the second. Storage entering the injection season at 30 percent – against approximately 52 percent a year ago – sets up a difficult restocking contest. If the Qatari disruption extends into late March, buyers attempting to rebuild storage ahead of next winter will be competing for Atlantic Basin spot cargoes that are simultaneously being redirected toward Asian markets facing their own shortfall.

The trajectory of storage fills through the injection season will determine whether Europe faces a genuine winter supply constraint or a costly but manageable shortfall.

Qatar’s long-term commercial positioning is the third, and the one with the longest shelf life. Before 2 March, Qatari LNG commanded a premium in contract terms – buyers accepted destination restrictions and pricing structures that reflected Qatar’s reliability and scale. As Saul Kavonic, a veteran energy analyst at MST Marquee, put it this week: the long-held perception of Qatar LNG as deserving a premium is now shattered.

Buyers who have spent the past three years assuming Qatar was the most reliable cornerstone of a diversified portfolio will be reviewing that assumption. The supply contracts that come up for renewal in the next cycle – and the new capacity that Qatar’s North Field expansion will bring online from mid-2026 – will be negotiated in a different commercial environment.

That is not a weeks-long story. It is a years-long restructuring of how the global LNG market prices geopolitical risk.