U.S./Israel-Iran War: the Middle East On Edge
NextFin News - The world's largest liquefied natural gas buyer is warning that spot LNG prices have further to rise before winter, as Europe enters the heating season with storage well below last year's level and a Middle East supply shock that has taken nearly a fifth of global LNG trade off the water. Yukio Kani, chairman and global chief executive officer of JERA, said on the sidelines of Gastech 2026 that low European gas reserves, an impending European ban on Russian LNG, and continued disruption in the Strait of Hormuz leave the market with "many bad news" heading into the cold months. The warning arrives as Asia's benchmark spot price trades near $27 per million British thermal units - roughly three times its level a year ago.
The Setup: A Winter Market Already Running Hot
The starting point is not a forecast of tightness but a market that has already repriced. Asia's Platts JKM marker climbed to $27.23 per MMBtu on September 16, 2026, up 8% in a single day and 26% over the prior month, according to market data. Europe's TTF hub stood at €79.52 per megawatt-hour, or about $27 per MMBtu, in mid-September. Both benchmarks are sitting at their highest second-quarter averages since 2022, with JKM up 45% year on year and TTF up 32% in the three months through June.
Kani put the arithmetic in terms a utility buyer feels immediately. At $10 per MMBtu, a single standard LNG cargo costs about $35 million; at $30, the same cargo exceeds $100 million. For a buyer purchasing 1 million tons, the bill jumps from $500 million to $1.5 billion - an extra $1 billion for the same molecules. "So I try to scare you, right?" he said, before adding that for buyers looking toward winter, "it seems like there are many bad news."
Three of those bad-news items are concrete and verifiable. First, European gas storage stood at 65.39% of working capacity on September 1, 2026, compared with 75.7% at the same point a year earlier - a gap of roughly 10 percentage points. By September 15 the level had recovered only to 68.7%, still 19.3 percentage points below the five-year seasonal norm, according to data from Europe's gas infrastructure registry. Second, the European Union's stepwise sanctions regime brings a full ban on Russian LNG imports into force at the beginning of 2027, closing a supply route the bloc has already leaned on less heavily each year since 2022. Third, the Strait of Hormuz, which carried almost 20% of global LNG supply, remains only partially open to commercial tanker traffic after fighting broke out in the region in late February 2026.
Taken together, these are not marginal adjustments. They are three separate tightening forces arriving in the same quarter. The question is whether the market has priced all three - or whether winter still holds a surprise to the upside.
Why the Price Spike Is Real, and Where the Mechanism Runs
The transmission channel from the Middle East conflict to a European and Asian gas bill runs through a single chokepoint: Qatar's Ras Laffan industrial complex, the world's largest LNG export hub. Iranian strikes in early March 2026 damaged two processing trains, removing 12.8 million tons per annum of capacity - about 17% of Qatar's LNG export capacity. QatarEnergy has extended force majeure declarations on deliveries, pushing timelines into the September-October window, and some buyers face declarations that could last years while replacement turbines - with two-to-four-year lead times - are sourced.
The immediate effect was a supply shock large enough to reverse a market that had been easing. Global LNG inflows fell by more than 10% in the second quarter of 2026, and European LNG imports dropped more than 10% year on year - roughly 5 billion cubic metres. The price response was violent: month-ahead TTF volatility surged to near 170% in March, while JKM volatility approached 300%. The spread between the two benchmarks flipped from a European premium of $0.90 per MMBtu in January-February to an Asian premium averaging $2.10 per MMBtu from March onward, pulling flexible cargoes eastward and leaving Europe to compete harder for what remains.
Europe's ability to absorb that competition is impaired by its own storage deficit. Gross injections in the first half of 2026 were about 15% - nearly 4 billion cubic metres - weaker than the same period in 2025, as high prices and weak price spreads gave shippers little incentive to fill. Regulators have relaxed the mandatory refill target to 80% for November 2026, down from the usual 90%, a tacit admission that the normal cushion will not be in place.
This is the mechanism in its simplest form: a geopolitical supply shock removed baseload volumes; the resulting price signal diverted flexible cargoes to Asia; Europe, already behind on storage, must now outbid Asian buyers for marginal tonnes while facing the loss of Russian LNG in January. Each step reinforces the next.
"If the buyers are looking into winter, it seems like there are many bad news. The price is already high. EU's gas reserve is inventory is low. LNG and gas from Russia will stop from January 1st next year. So it seems price may go up further." - Yukio Kani, chairman and global chief executive officer of JERA, speaking at Gastech 2026 in Bangkok.
The Cyclical Call: This Spike Will Revert
Despite the near-term squeeze, the weight of evidence says the current price level is cyclical, not structural - a spike that will mean-revert once the disruption clears. Three pieces of evidence support that call.
First, the supply wave that the market was pricing before the conflict has not disappeared. The International Energy Agency expects global LNG production to grow by more than 7% in 2026, its fastest pace since 2019, with North America accounting for more than 85% of the increase. Bernstein analysts project roughly 93 million tons per annum of new liquefaction capacity entering service across 2025 and 2026, including Golden Pass in Texas, Qatar's North Field Expansion, Australia's Scarborough, and Nigeria LNG Train 7. Kpler forecasts global LNG supply reaching 475 million tons in 2026, a 10.2% gain over 2025 - an increment roughly equal to South Korea's entire annual demand.
Second, the official baseline assumes the disruption is temporary. The IEA's third-quarter report assumes the Strait of Hormuz fully reopens in the third quarter of 2026 and that operations at undamaged regional facilities are restored early in the fourth quarter, with Qatari and Emirati deliveries ramping progressively between July and October. If that timeline holds, the 12.8 million tons per annum of lost Ras Laffan capacity returns before peak winter demand arrives.
Third, the price history of LNG is one of sharp, mean-reverting spikes. JKM's all-time high of $69.96 per MMBtu in August 2022 - during the full-blown post-invasion European crisis - was not sustained. Prices collapsed back toward the low teens as demand destruction and new supply arrived. The current $27 level is a crisis premium, not a new equilibrium.
Consensus bearish price forecasts underscore the point. Bernstein expects Asian spot prices to average roughly $9 per MMBtu over the 2026-2028 period, and Kpler puts the 2026 average at about $10 per MMBtu - less than half the current spot level. These are not fringe views; they are the mainstream supply-driven baseline.
The Structural Floor: Why This Cycle Does Not Return to the Old Low
Calling the spike cyclical is not the same as calling for a return to the pre-2022 world. Two structural changes put a floor under the next down-cycle, and JERA's own strategy reveals how the industry is positioning for exactly that world.
The first is demand. Artificial intelligence and data centres are bending Japan's electricity demand curve upward after a decade of expected decline. Kani noted that, excluding China, Japan is the largest potential AI data-centre market in Asia, and that 70% of that demand is concentrated around greater Tokyo - JERA's franchise area. Within 10 years, he sees about 15 gigawatts of data-centre load in greater Tokyo alone, and he argues that gas-fired generation is the quickest solution to provide round-the-clock power where renewables and grid connections cannot move fast enough.
The second is Europe's permanent loss of cheap pipeline gas. Russian piped deliveries to the European Union fell 90% between 2021 and 2025, and the bloc agreed in December 2025 to phase out Russian gas entirely by November 2027. That removes a low-cost baseload supplier and replaces it with seaborne LNG, which carries shipping, regasification, and risk premia that pipeline gas did not. Even in a well-supplied year, Europe's marginal barrel is now priced off global LNG rather than a long-term pipeline formula.
JERA's contracting behaviour confirms the structural read. The company has signed four 20-year supply deals with U.S. suppliers - NextDecade, Sempra Infrastructure, Cheniere Marketing, and Commonwealth LNG - while other Japanese buyers including Osaka Gas and Kyushu Electric have locked long-term pacts of their own. Japan's seventh Strategic Energy Plan, released in February 2026, identifies gas as "an important energy source even after carbon neutrality," reversing a decade of import declines. Morgan Stanley projects Japan's LNG imports rising to 78 million tons in 2030, even as the government's own forecast sees demand falling to 53 million to 61 million tons by 2040 under its emissions pathway.
The implication: the floor is rising even as the ceiling comes down. The next cyclical trough will sit above the last one, because the marginal buyer now includes data centres that cannot tolerate interruption, and the marginal supplier to Europe is seaborne LNG rather than Russian pipeline gas.
The Adversarial Case: What If the Supply Wave Drowns Out Winter?
The strongest argument against JERA's winter-tightness view is the simplest: the supply surge is real, large, and already bearing down on the market. Roughly 150 million tons of incremental LNG capacity is due online between 2026 and 2028 - equivalent to about 35% of current global demand. Bernstein's own analysts wrote that this volume "will get absorbed by the market, but at lower prices," describing a decisive shift from a seller's to a buyer's market. If the Strait of Hormuz reopens on the IEA's timeline and Ras Laffan returns before winter, the market could swing from shortage to surplus within a single quarter, and the $27 spot price would look like the top of the cycle rather than a waypoint.
There is force in that argument, and it is the reason annual-average forecasts cluster near $9 to $10 per MMBtu. But it conflates the average with the path. A market can be well supplied on an annual basis and still experience a severe seasonal squeeze if the supply arrives late, the storage cushion is thin, and demand is inelastic during the coldest weeks. Europe's storage deficit of roughly 10 percentage points against last year, the January cutoff of Russian LNG, and the possibility that Qatari volumes return only gradually rather than all at once create exactly that configuration. Averages are what analysts forecast; spikes are what buyers pay for in February.
Notably, the repair timeline itself may undercut the IEA's optimistic assumption. Energy consultancy Wood Mackenzie said in April that Ras Laffan was unlikely to be fully online before the end of August even under a best-case May restart, and Shell's third-quarter guidance assumed no production from Qatar, with some industry estimates pushing full recovery into the first quarter of 2027. If damaged turbines take years to replace, the 17% of Qatar's export capacity knocked offline could still be missing when European demand peaks - turning the cyclical rebound story into a two-winter problem.
The specific signal that would falsify the winter-tightness judgment is observable and dated: if the Strait of Hormuz is fully open to commercial LNG traffic and Ras Laffan capacity is restored before the end of the fourth quarter of 2026, and European storage closes November 2026 above the relaxed 80% target, then the squeeze thesis fails and prices should revert toward the $10 to $12 per MMBtu band before winter peaks. If any of those conditions does not hold - continued transit restrictions, delayed Qatari restarts, or storage stuck in the mid-60s - the path of least resistance remains upward into the heating season.
What Comes Next: Winners, Losers, and the Three Horizons
Split by time horizon, the picture diverges sharply.
In the short term - the 2026-27 winter itself - the beneficiaries are holders of flexible LNG cargoes and exporters with uncommitted volumes, who can capture the spot premium as European and Asian buyers compete for marginal tonnes. The exposed are European utilities and Asian spot buyers without long-term cover, plus the industrial consumers who face pass-through of higher power and feedstock costs. JERA's own first-quarter results show how volatile the pass-through can be: profit rose 30.6 billion yen year on year to 123.1 billion yen in the quarter ended June 2026, helped by improved LNG and coal trading, and the company set a full-year profit forecast of 280.0 billion yen while flagging Middle East uncertainty as a risk to fuel procurement.
Over the medium term - 2027 and beyond, assuming Hormuz reopens - the supply wave should dominate and pull annual averages down toward the $9 to $12 band. That is the window in which the cyclical call pays off: buyers who locked long-term contracts at 2026 spot-linked prices may find themselves above the market, while new LNG exporters racing to monetise capacity face a lower-price world than the one their investment decisions were made in.
Over the long term, the structural floor matters more than the cyclical trough. Data-centre power demand, industrial electrification, and Europe's permanent dependence on seaborne LNG keep the demand curve steeper than it was in the 2010s. The companies positioned to benefit are those that control the full value chain - liquefaction, shipping, regasification, and dispatchable generation - rather than pure spot traders. JERA's pitch that it can integrate the "AI data-centre value chain" from LNG procurement through gas-fired plants to round-the-clock power delivery is a bet on exactly that configuration.
For investors and policymakers, the practical read is asymmetric. The downside from here is bounded by the supply wave and the IEA's reopening assumptions; the upside is unbounded if the strait stays closed through a cold winter. That asymmetry is why buyers are paying up for 20-year contracts today: they are not buying cheap gas, they are buying certainty.
The winter price spike is a cyclical event riding on a structurally higher floor. The traders who make money are the ones who know which part of the move is which.
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