The Ultimate LNG Report
The Global LNG Investment Map: energy transition, supply waves, and the decade ahead
Hi, Investor! 👋🏼
I'm Jimmy - welcome back to another edition of Jimmy's Journal.
In today's report, we'll break down the global LNG market - from the basics of how the molecule actually works, to the biggest supply wave in history, to what a conflict in the Persian Gulf reveals about the decade ahead.
I hope you enjoy the read.
TL;DR (What Actually Matters)
Qatar exported 82.4 million metric tons of LNG in 2025 - roughly 20% of global supply. All 14 liquefaction trains are now offline. Asian LNG prices (JKM) jumped +45.8% in eleven days, from $10.80 to $15.77/MMBtu.
~400 Bcm/year of new liquefaction capacity is under construction globally through 2035, with the US accounting for over 50%. The supply wave is coming regardless of demand - and the biggest additions hit in 2028 and 2029.
The three historic demand pillars - China, Japan/South Korea, and Europe - are all stepping back simultaneously. The growth story has migrated to emerging Asia, where fundamentals are compelling but infrastructure is not ready.
The real constraint is the receiving end: regasification terminals near 100% utilization, virtually zero underground gas storage across India, Taiwan, Pakistan, and Bangladesh, and gas turbine lead times stretching into the late 2020s.
Introduction:
There’s an invisible highway running across the bottom of the ocean...
It carries no ships you’d recognize from a port, no crude oil in black barrels, no containers with corporate logos.
Instead, it carries gas - natural gas, cooled to -162°C until it becomes a colorless, odorless liquid and shrinks to 1/600th of its original volume - loaded onto the largest floating structures ever built - and delivered to dozens of countries that couldn’t otherwise heat their homes, run their factories, or keep their lights on.
This is liquefied natural gas (LNG).
And right now, in March 2026, with conflict in the Persian Gulf disrupting the flow of Qatari and UAE cargoes through the Strait of Hormuz, the world is receiving a crash course in just how much of modern civilization runs on this one molecule.
This piece is the complete LNG deep dive: where the fuel comes from, what it actually costs the planet, why it’s become the central battlefield in the global energy transition debate, and what the current market disruption reveals about structural vulnerabilities that will define the sector for the next decade.
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LNG 101:
From well to burner tip:
Natural gas - primarily methane, CH₄ - is one of the most abundant fossil fuels on Earth.
It’s cleaner-burning than coal or oil.
It’s relatively easy to extract.
And it’s been used for power generation, heating, and industrial processes for more than a century.
The problem is geography…
Natural gas, in its gaseous form, can only travel through pipelines.
And pipelines are extraordinarily expensive to build - typically $1-5 million per mile for onshore lines, and dramatically more for subsea routes.
More importantly, they’re politically fixed. When Russia built the Nord Stream pipelines into Europe, it wasn’t just an engineering project, but a geopolitical instrument. Germany became structurally dependent on Russian supply.
When that dependency broke in 2022, Europe was exposed.
LNG solves the pipeline problem, at the cost of enormous infrastructure on both ends of the trade.
The LNG Value Chain:
That infrastructure maps cleanly onto the same upstream > midstream > downstream framework used in oil - but with a few LNG-specific layers worth understanding.
Upstream:
Exploration:
Before any molecule can be liquefied or shipped, it has to be found and extracted. The upstream phase covers exploration, appraisal, development drilling, and production (E&P).
Exploration begins with seismic surveys - acoustic waves sent into the subsurface and analyzed for geological structures that might trap hydrocarbons.
When a promising structure is identified, an exploration well is drilled. If gas is found, appraisal wells follow to estimate the size of the accumulation. Only then does development begin.
Reserves - the gas that can be commercially extracted - are classified under a universally recognized system with three tiers:
1P (Proved reserves): are quantities that geological and engineering data show, with reasonable certainty, to be recoverable under existing economic and operating conditions. These are the numbers companies report to regulators and investors. “Reasonable certainty” conventionally means at least 90% probability.
The financial feasibility is the most important part in this case: the reserves may exist, but extracting them could require an almost infinite amount of capital, making the operation economically unviable.
Certification firms produce reports based on assumptions such as the price of a barrel of oil equivalent for LNG, as well as the extraction costs associated with that specific reserve.
2P (Proved + Probable): adds the “probable” category - reserves that have at least a 50% probability of being recoverable. This is the number most commonly used in industry valuations and acquisition pricing, because it reflects a more complete picture of what’s likely in the ground.
EV/2P multiples are widely used in the valuation of companies in the sector, especially those in the early stages of operation, as well as in transactions involving the acquisition of oil fields.
3P (Proved + Probable + Possible): extends further to include “possible” reserves - recoverable with at least 10% probability. These are the speculative upper end of the resource estimate, useful for long-range planning but treated with skepticism by financial analysts.
The distinction matters enormously in practice…
A company that books 1P reserves is making a conservative, legally defensible statement. A company promoting its 3P resource base is telling a much more optimistic story - one that may never translate into production.
Production:
The US, Qatar, Russia, Australia and Iran hold the world’s largest proven gas reserves.
Qatar’s North Field - the world’s largest single natural gas reservoir, shared geologically with Iran’s South Pars field across the maritime border - underpins essentially all of Qatar’s LNG ambitions.
The US leads in unconventional gas: shale formations like the Marcellus, Haynesville, and Permian Basin produce through horizontal drilling and hydraulic fracturing, techniques that unlocked resources previously considered unrecoverable.
Natural gas comes in two broad forms:
Conventional gas sits in discrete underground reservoirs - porous rock formations sealed by impermeable cap rock - and flows naturally once a well is drilled.
Unconventional gas (shale gas, tight gas, coalbed methane) is dispersed through low-permeability rock and requires stimulation - typically hydraulic fracturing - to produce at economic rates.
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Midstream:
Once gas leaves the wellhead, it enters the midstream phase: gathering, processing, liquefaction, and ocean transport.
This is where natural gas becomes LNG…
Processing:
Raw wellhead gas is rarely pure methane.
It contains water vapor, CO₂, hydrogen sulfide, heavier hydrocarbons (ethane, propane, butane), and other impurities.
All of these must be removed before liquefaction:
water and CO₂ would freeze and block equipment;
sulfur compounds are toxic and corrosive;
heavier hydrocarbons are typically extracted and sold separately as natural gas liquids (NGLs), which are valuable petrochemical feedstocks in their own right.
Liquefaction:
What remains after processing - predominantly methane - enters a liquefaction train: an enormous refrigeration complex that cools the gas to -162°C through a series of heat exchangers and refrigerant cycles.
The most common process today is the C3MR (propane pre-cooled mixed refrigerant) cycle, developed by Air Products.
A single liquefaction train at a modern facility like those in Qatar can process 7-11 billion cubic meters of gas per year.
The capital cost of a world-scale liquefaction terminal ranges from $3 billion to over $10 billion depending on location and configuration - making it one of the most capital-intensive industrial facilities on earth.
Storage and loading:
Liquid LNG is held in insulated above-ground tanks - typically double-walled structures with vacuum-jacketed walls - before being loaded onto LNG carriers via cryogenic loading arms at dedicated marine berths.
Shipping:
LNG carriers are among the most technically sophisticated commercial vessels ever built.
A modern Q-Max tanker - the largest class, designed specifically for Qatar’s ports - is over 345 meters long and carries up to 266,000 cubic meters of LNG (+40% more than traditional carriers), equivalent to roughly 160 billion BTUs of energy, enough to power a mid-sized American city for several days.
There are exactly 14 Q-Max LNG vessels in existence.
All of them were built and delivered between 2008 and 2010 by two South Korean shipyards: Samsung Heavy Industries and Daewoo Shipbuilding & Marine Engineering (DSME).
The vessels are named Mozah, Al Mayeda, Mekaines, Al Mafyar, Umm Slal, Bu Samra, Al Ghuwairiya, Lijmiliya, Al Samriya, Al Dafna, Shagra, Zarga, Aamira, and Rasheeda.
Operationally, ten of these ships are managed by NSQL (Nakilat Shipping Qatar Limited), while four are operated by STASCo (Shell International Trading and Shipping Company), part of Shell International in London.
All fourteen vessels are owned by Qatar Gas Transport Company (Nakilat) and are chartered to QatarEnergy LNG, Qatar’s state-owned LNG producer.
The cargo is kept cold through insulation and controlled boil-off; modern vessels use the boil-off gas as fuel for their own propulsion, eliminating waste and reducing operating costs.
A voyage from the US Gulf Coast to Japan takes approximately 20 days.
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Downstream:
The downstream phase begins when the LNG carrier arrives at a receiving terminal and ends when gas reaches the final consumer.
Regasification:
At the receiving terminal, LNG is warmed back to its gaseous state using seawater heat exchangers (or, in colder climates, air or steam vaporizers).
The process is essentially the reverse of liquefaction - controlled warming through heat exchangers until the liquid returns to gas phase.
Conditioning and injection:
The regasified gas is then odorized (natural gas is inherently odorless; the sulfur smell is added as a safety measure), pressure-regulated, and metered before injection into the domestic transmission pipeline network.
Domestic distribution:
High-pressure transmission pipelines carry gas from the regasification terminal to city gates - pressure reduction and metering stations at the edge of urban distribution networks.
From there, progressively lower-pressure distribution pipelines deliver gas to power plants, industrial facilities, commercial users, and ultimately residential customers.
In many emerging markets, this final-mile infrastructure is the binding constraint: a country can build a regasification terminal, but if the domestic pipeline grid doesn’t reach industrial clusters or population centers, the gas goes nowhere useful.
The total capital investment required to move one BTU of US shale gas into a Japanese home - upstream wells, gathering lines, processing plants, liquefaction terminal, LNG tanker, regasification terminal, transmission pipeline, distribution network - is staggering.
Which is why LNG trades at a significant premium to pipeline gas, and why the contracts underpinning most LNG trade are measured in decades, not months.
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The Pricing Architecture:
Unlike oil, there is no single global price for natural gas.
The LNG market operates across three major regional benchmarks, each with its own supply-demand dynamics:
Henry Hub (US) is the US benchmark, based on the physical delivery point at Erath, Louisiana. It represents the price of gas at the wellhead in one of the world’s most liquid gas markets.
As of early 2026, Henry Hub trades around $4-5/MMBtu - historically low relative to global benchmarks, reflecting the structural abundance of US shale gas.
TTF (Netherlands) is the European benchmark, based on the Title Transfer Facility virtual trading point. It’s the primary reference for European pipeline and LNG trades.
TTF spiked to an astonishing 340 EUR/MWh (roughly $35/MMBtu) in August 2022 following the Nord Stream shutdowns. It has since retreated significantly, though recent events in the Gulf have pushed it sharply higher again.
JKM (Japan-Korea Marker) is the primary Asian LNG spot benchmark, reflecting the price of LNG delivered to Japan or South Korea.
Historically, Japan and South Korea have paid the highest LNG prices in the world, partly because they were locked into long-term oil-indexed contracts (a legacy of the oil price shocks of the 1970s).
The JKM spot market is more liquid today, but Asian LNG prices remain structurally elevated relative to Henry Hub.
The spread between these benchmarks is what drives global LNG trade flows.
When JKM is $8/MMBtu and Henry Hub is $3/MMBtu, there’s $5 of gross margin available to whoever can liquefy, ship, and regasify that molecule.
In 2022, those spreads ballooned to extraordinary levels and triggered an unprecedented wave of US LNG export investment.
We are experiencing a similar situation today…
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The Carbon Question:
Is LNG part of the solution or the problem?
This is where the energy transition debate gets genuinely difficult, and where honest analysis requires holding two uncomfortable truths simultaneously.
LNG vs. Coal:
On a pure combustion basis, natural gas is roughly 50% less carbon-intensive than coal per unit of electricity generated.
The US Energy Information Administration (EIA) estimates that burning natural gas for electricity emits approximately 0.9 pounds of CO₂ per kilowatt-hour, versus 2.2 pounds for coal.
For countries like India, Vietnam, Bangladesh, and Indonesia - where the realistic near-term choice is between gas and coal, not between gas and renewables - LNG is a meaningful step toward lower emissions.
The IEA’s World Energy Outlook consistently notes that in emerging economies, displacing coal-fired generation with gas can deliver substantial near-term emissions reductions.
India’s electricity demand is growing at roughly 6-7% per year.
According to the EIA’s International Energy Outlook 2023, coal remains the dominant power source in Asia’s emerging economies, and the pace of its displacement will be one of the critical determinants of whether the world’s temperature trajectory bends meaningfully before mid-century.
This is the IEA’s “bridge fuel” framing, and it has genuine merit in the 2025-2040 timeframe for markets where the alternative is coal.
The methane problem:
The bridge fuel argument, however, depends critically on one number that the industry has historically been reluctant to discuss: the methane leakage rate.
Methane is the primary component of natural gas, and it’s also a potent greenhouse gas - approximately 80 times more powerful than CO₂ over a 20-year timeframe (and about 30 times over 100 years).
When natural gas leaks unburned from wells, pipelines, compressor stations, and LNG facilities, the climate benefit of choosing gas over coal rapidly erodes.
The EIA estimates that the US natural gas supply chain leaked approximately 1.4% of production as methane in recent years.
The Environmental Defense Fund, using satellite and aerial measurement data, suggests the real number may be closer to 2.3% in some shale basins. At a leakage rate above roughly 3%, gas becomes as bad as coal on a 20-year climate horizon.
For LNG specifically, there’s an additional layer: the energy required to liquefy, transport, and regasify gas consumes roughly 10-15% of the original energy content.
That energy itself comes from burning gas or consuming electricity (often from gas-fired plants).
The lifecycle emissions of LNG delivered from the US Gulf Coast to Japan are meaningfully higher than the point-of-combustion numbers suggest.
A 2022 study in the journal Energy Science & Engineering estimated that US LNG exported to Asia and combusted there carries a lifecycle carbon footprint approximately 33% higher than domestically consumed gas, once liquefaction energy, shipping, and boil-off losses are accounted for.
Still lower than coal - but the margin is narrower than the industry’s marketing materials typically acknowledge.
Qatar’s predominantly state-owned production, operating from a single supergiant reservoir (the North Field, which it shares with Iran), has some of the lowest methane leakage rates in the world - partly because of the reservoir characteristics, partly because Qatar has invested heavily in gas flaring reduction.
US shale production is more heterogeneous, with some operators having dramatically better emissions performance than others.
The Energy Transition context:
The IEA’s Net Zero Emissions by 2050 scenario is frequently cited to argue that no new fossil fuel development is needed. This is technically correct in the aggregate but misleading when disaggregated by geography and use case.
The IEA’s NZE scenario assumes that solar and wind capacity additions continue at record pace, that energy efficiency improves dramatically, and that emerging economies leapfrog fossil fuels.
Under those assumptions, global gas demand peaks before 2030 and declines thereafter…
But there are two things the NZE scenario can’t guarantee:
the pace of renewable buildout in countries with limited capital and institutional capacity;
and the reliability problem.
Gas - and specifically gas-fired generation - is not just a fuel source. It’s a balancing mechanism.
Every gigawatt of intermittent solar and wind capacity added to a power grid increases the need for dispatchable backup generation.
Batteries can handle short-duration storage (2-4 hours). But seasonal storage - managing the difference between summer solar abundance and winter heating demand - requires either enormous battery overcapacity, pumped hydro (geographically constrained), hydrogen (extremely expensive today), or natural gas peakers.
For most grids, the answer through 2040 will be gas.
Germany discovered this the hard way. Its Energiewende had by 2022 installed enormous wind and solar capacity - but during the Dunkelflaute (dark doldrums, the weeks in winter when wind is low and solar is minimal), gas and coal remained essential.
The solution isn’t to abandon gas; it’s to reduce the baseload reliance on gas while maintaining the flexibility.
The deeper point for investors: the energy transition doesn’t reduce gas demand to zero in the 2025-2040 window.
It changes the type of gas demand, from baseload thermal generation to flexible peaking and load-following.
That actually makes the gas market more price-volatile, not less, as utilization swings more dramatically between seasons and weather patterns.
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The Supply Side:
The shale revolution:
The US shale revolution is one of the most consequential industrial developments of the 21st century.
Between 2005 and 2015, US natural gas production roughly doubled, driven by the combination of horizontal drilling and hydraulic fracturing. Four formations led the transformation:
Marcellus shale in Pennsylvania and West Virginia;
Haynesville in Louisiana and East Texas;
Permian Basin in West Texas (primarily associated gas from oil production); and
Utica in Ohio.
Together, they transformed the US from a gas importer into the world’s largest gas producer.
According to the EIA’s Annual Energy Outlook 2024, US dry natural gas production reached 103 billion cubic feet per day in 2023, a record.
The EIA projects this growing to approximately 110-115 Bcf/d by the late 2020s, driven primarily by associated gas from the Permian Basin and continued Haynesville expansion.
The implication for LNG is straightforward: the US has a structural, multi-decade supply surplus of natural gas at costs that make export economics attractive whenever global prices are meaningfully above Henry Hub (guess what? Today we are in exactly that scenario).
The Haynesville in particular - located just 200-300 miles from the Gulf Coast liquefaction terminals - is the natural feedstock source for the LNG export buildout.
What’s actually being built?
Between 2025 and 2035, approximately 201 billion cubic meters per year of new US LNG export capacity is under construction or in advanced development.
To put this in context: total US LNG export capacity today is roughly 150 Bcm/year. The industry is essentially building another 130% of current capacity from scratch.
The major projects include Golden Pass LNG (a joint venture involving QatarEnergy and ExxonMobil, with Train 1 delivering first cargo in early 2026), Corpus Christi Midscale, Port Arthur Phase 2, CP2 Phase 1 (Venture Global), Rio Grande LNG, and Woodside Louisiana LNG.
In 2025 alone, six projects reached Final Investment Decision, representing 83 Bcm/year of capacity - a record for a single calendar year.
The ramp is not linear…
The biggest volume additions come in 2028 and 2029, when multiple trains across these facilities are scheduled for simultaneous commissioning.
Roughly 40 Bcm/year of new US capacity is expected to come online in each of those two years - a sudden, significant increase in global LNG supply at a time when demand growth may not be keeping pace.
Qatar, meanwhile, is executing on the largest single LNG expansion in history.
The North Field East and North Field South projects will add 66 Bcm/year of liquefaction capacity through six new trains, each capable of processing 11 Bcm/year.
The first Qatar NF cargoes are expected in 2026, with full ramp completion by approximately 2028-2029.
Qatar’s stated strategy is to maintain its position as the world’s lowest-cost LNG producer and to secure market share before the supply surplus fully materializes - which creates an incentive to accelerate project timelines.
At least, that was the plan before the conflict…
As of March 2026, that strategy is on hold.
All 14 liquefaction trains at Ras Laffan are offline, and the question is no longer how fast Qatar can ramp up - it's how long before it can safely resume exporting at all.
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The Demand Side:
For three decades, the global LNG market was anchored by three demand centers: Northeast Asia (Japan, South Korea), China, and Europe.
Together, they account for roughly 70% of current global LNG imports. All three are now structurally weakening as LNG buyers…
The three pillars are crumbling:
Japan and South Korea are executing the most significant energy policy pivots in a generation.
Japan’s 7th Strategic Energy Plan, published in late 2024, targets nuclear power at 20% of the electricity mix by 2040 and renewables at 40-50%. As of late 2025, Japan had restarted 14 nuclear reactors, with the Nuclear Regulation Authority reviewing additional restart applications.
South Korea’s 11th Basic Electricity Plan calls for similar nuclear and renewables expansion.
After the problems with imports from the Middle East, I imagine they will accelerate this plan.
The combined effect: LNG demand in these two countries, which together imported roughly 158 Bcm in 2025, is expected to grow by only about 15 Bcm over the entire decade to 2035. That’s essentially flat - a dramatic deceleration relative to historical growth rates.
China is the most consequential shift. China’s LNG imports grew at roughly 10-15% annually through much of the 2015-2022 period, and the widespread forecast was that China would absorb a substantial portion of the coming global supply surplus. That forecast is now being revised downward, for several reasons.
First, Russia. The Power of Siberia pipeline, which began deliveries in 2019, is already sending 22 Bcm/year of Russian gas to northeastern China. Power of Siberia 2 - a much larger pipeline project through Mongolia, with a design capacity of 50 Bcm/year, eventually expandable to 106 Bcm/year - is now projected to begin operations in 2031.
When fully operational, Russian pipeline gas could supply a substantial share of China’s incremental gas demand, directly displacing potential LNG imports.
Second, domestic production. Beijing has prioritized energy security through domestic supply development, targeting an increase in domestic gas production-to-consumption ratios. Unconventional gas resources in the Sichuan Basin (tight gas and shale) are being developed at accelerating pace.
Third, renewable policy. China’s solar and wind deployment has been extraordinary - the country added more renewable capacity in 2024/2025 alone than the rest of the world combined.
As solar penetration rises, the need for gas-fired backup increases in theory, but Beijing appears willing to manage grid reliability through coal backup rather than gas, preserving gas for industrial and chemical uses.
All that said, the revised expectation is that Chinese LNG imports peak at around 120 Bcm in 2032 and then plateau or decline, significantly below the 140 Bcm-by-2030 forecast that underpinned much of the recent US LNG investment case.
Europe bought enormous volumes of LNG after the 2022 Russian pipeline gas cutoff, filling the ~150 Bcm/year gap left by Nord Stream and other pipeline reductions.
But European LNG import growth going forward is structurally limited. Industrial gas demand remains approximately 20% below 2019 levels and is recovering slowly, constrained by energy costs and the broader deindustrialization pressure.
Residential demand is declining at roughly 0.8-1% per year as heat pump adoption accelerates and building insulation programs take hold.
The projected growth in European LNG imports over 2025-2035 is only about 26 Bcm - meaningful, but nowhere near large enough to absorb a 400 Bcm/year supply wave.
The Southeast Asia thesis:
The entire bull case for global LNG market balance over 2025-2035 rests on one region: emerging Asia Pacific - India, Taiwan, Thailand, Pakistan, Bangladesh, Vietnam, Indonesia, the Philippines, and a handful of smaller markets.
The demand fundamentals are genuinely compelling…
These are economies with GDP growth rates of 4-7% per year, rising electrification rates, young and growing middle classes, and structural energy deficits.
Their governments have explicitly designated natural gas as a critical transition fuel:
India’s national gas infrastructure masterplan targets increasing gas’s share of the primary energy mix from roughly 6% today to 15% by 2030 (most of it coming from Qatar) - which would require a tripling of import capacity.
Taiwan, having completed its nuclear phase-out in 2025, is targeting 50% of power generation from gas.
Thailand, Vietnam, the Philippines, and Bangladesh all have substantial gas-fired generation capacity either under construction or planned.
Projections suggest these markets collectively could more than double LNG imports from roughly 127 Bcm in 2025 to approximately 280 Bcm by 2035, with India alone contributing the largest country-level volume increase - from 33 Bcm to nearly 90 Bcm.
But the demand potential and the physical capacity to receive LNG are two very different things. And here the structural story gets genuinely alarming…
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The Infrastructure Bottleneck:
The regasification gap
Recall the value chain: even if supply is produced, shipped, and offered at competitive prices, it can only be consumed if the destination country has terminals capable of receiving and processing LNG.
In emerging APAC, those terminals are the binding constraint…
Total regasification capacity in high-growth emerging APAC markets (excluding China, Japan, South Korea) is approximately 210 Bcm/year.
But critically, utilization is already very high in many key markets:
Taiwan’s terminals ran at close to 100% utilization for much of 2025.
Pakistan and Bangladesh have repeatedly exhausted available capacity, forcing cargo cancellations.
Thailand peaked near 80% utilization.
India’s Dahej terminal - one of the largest in Asia - regularly operates near nameplate capacity.
The under-construction pipeline is thin: only three major regasification projects are currently being built in the region.
The pre-FID project pipeline is theoretically substantial - approximately 100 Bcm/year - but the majority of those projects are not expected to reach final investment decision until after 2030, meaning the infrastructure gap persists for the entire critical period of the current supply wave.
If demand grows as projected, regasification utilization in these markets approaches 100% by 2035, creating a hard physical ceiling on import volumes.
You can’t import more gas than your terminals can receive, regardless of how cheap or available supply is.
The storage void:
Gas storage infrastructure is what allows LNG markets to function as genuine commodity markets rather than just-in-time delivery systems.
Underground gas storage facilities - depleted reservoirs, aquifers, or salt caverns converted to hold pressurized gas - absorb supply in summer and release it in winter, smoothing price volatility and providing buffer against supply disruptions.
The emerging APAC markets have almost no ne.
According to International Gas Union data, Taiwan, India, Thailand, Bangladesh, and Pakistan have essentially zero underground gas storage capacity.
Total above-ground LNG storage tank capacity in these markets covers only about 5% of their current annual LNG imports - compared to roughly 14% for China, and vastly more for Europe (which has 104 Bcm of underground gas storage, equivalent to about 30% of annual consumption).
Without storage, these markets have no shock absorbers.
A cold winter, a supply disruption, a vessel delay, a terminal maintenance outage - any of these creates an immediate demand-destruction event, because there’s no inventory buffer to draw down.
This is why Bangladesh and Pakistan have repeatedly experienced LNG shortages despite willing buyers and available global supply: their physical infrastructure can’t reliably deliver molecules when demand spikes.
The gas turbine queue:
Building new LNG-fired power generation capacity also requires gas turbines.
Heavy-duty industrial gas turbines - the kind used in large combined-cycle power plants - are dominated by three manufacturers: GE Vernova ($GEV), Siemens Energy ($SIE), and Mitsubishi Power.
The combined market for these machines is relatively small (a few hundred units per year globally), and order books are now stretched to multi-year lead times.
The US AI data center buildout and Middle Eastern power generation projects consumed approximately 68% of H1 2025 gas turbine orders globally - up sharply from prior years.
This means emerging Asian buyers are competing for equipment against customers with deeper pockets, more established financing, and in some cases, geopolitical priority from the major manufacturers’ home governments.
The combination of constrained regasification capacity, absent gas storage, and long gas turbine lead times creates a structural demand ceiling in the region most critical to global LNG market balance.
The bull case can be stated; the infrastructure to realize it is behind schedule.
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The Strait of Hormuz:
The event:
In late February and early March 2026, a conflict in the Persian Gulf resulted in significant disruptions to LNG transit through the Strait of Hormuz.
Qatar - which exported 82.4 million metric tons of LNG in 2025, roughly 20% of total global supply - experienced operational shutdowns across its 14 liquefaction trains at Ras Laffan, the world’s largest LNG export complex.
The UAE’s Das Island facility also curtailed operations. QatarEnergy provided no timeline for restart.
The Strait itself became nearly impassable for commercial traffic. War-risk insurance was either unavailable or priced above $500,000 per voyage.
Commercial vessel traffic fell roughly 90%, with tanker operators unwilling to risk vessels worth $100-200 million in an active conflict zone with no insurance backstop.
Global energy markets repriced immediately:
JKM - the Asian LNG benchmark - moved from $10.80/MMBtu on February 20 to $15.77/MMBtu by March 3, a gain of 45.8% in eleven days.
TTF spiked sharply before partially recovering on tentative de-escalation signals.
Tokyo power futures hit record highs. Physical traders locked in 3-6 month supply contracts at elevated prices - a signal that market participants did not expect replacement supply to materialize quickly.
The buyers most directly exposed were Qatar’s primary Asian customers:
China (20.6 million mt of contracted Qatari supply per year),
India (15.1 million mt),
Taiwan (8.3 million mt),
South Korea (7.4 million mt),
Japan (4.2 million mt),
and a range of smaller buyers across the region totaling another 20 million mt annually.
Together, roughly 76 million mt of annual contracted demand suddenly needed to find alternative suppliers - in a market where no single alternative supplier operates at remotely comparable scale.
Industrial gas rationing started within 24 hours. India’s state-owned gas companies began cutting supplies to fertilizer plants and heavy industry, prioritizing power generation.
Taiwan activated its emergency response mechanism and began coordinating emergency cargo purchases with South Korea and Japan.
Pakistan and Bangladesh - already operating near their infrastructure ceiling - faced the prospect of extended power outages if spot cargoes proved unaffordable.
Why restart is complicated:
The instinct is to assume that once the shooting stops, the molecules start flowing again. But LNG infrastructure doesn’t work that way…
Qatar’s ability to restart facilities is not the binding constraint.
The binding constraint is Qatar’s willingness to route cargoes through the Strait.
Even if a ceasefire is declared, the question of whether Qatari tankers and insurers will accept the risk of transiting the Strait in a conflict’s aftermath - given the demonstrated vulnerability of physical infrastructure - requires a complex assessment of security guarantees, insurance availability, and political judgment.
Qatar holds roughly $450 billion in foreign assets via its sovereign wealth fund, and another $60 billion in central bank reserves - a fiscal buffer equivalent to roughly 10x its annual LNG export revenues.
It can absorb a prolonged export disruption without severe economic stress, which paradoxically reduces its incentive to rush back through the Strait before it’s confident the risk is genuinely manageable.
This distinction - between the ability to restart and the choice to restart - is critical and was underappreciated by markets in the initial reaction to de-escalation headlines.
What demand destruction actually looks like:
In a scenario of prolonged Qatari and UAE export disruption, the global LNG market faces a deficit of approximately 75 Bcm across the March-October injection season - roughly 10% of total global imports.
The market response won’t be uniform. Different buyers have very different price sensitivities, and understanding the “merit order” of demand destruction is essential.
The most price-sensitive buyers are the emerging Asian markets we’ve discussed, who already operate near their infrastructure capacity ceiling and whose governments have less fiscal space to absorb high energy costs.
These markets will see the largest percentage volume declines in a sustained high-price environment, estimated at roughly 25% below y/y levels in a worst-case disruption scenario.
China and the JKM markets (Japan, South Korea) are less price-sensitive at the margin - they have storage, deep-pocketed buyers, and more contractual protection - but still face meaningful cuts in the 12-13% range under an extended disruption scenario.
Europe has optionality the others lack: it can switch power generation from gas to coal.
Germany and Poland together have approximately 56 GW of installed coal and lignite capacity that ran at only about 25% utilization in summer 2025, but ran at nearly 50% during the energy crisis of 2022.
Raising coal utilization by 10 percentage points across Germany and Poland could reduce European gas demand by roughly 6 Bcm over the injection season - a meaningful offset.
Japan and South Korea similarly have about 90 GW of installed coal-fired power capacity that ran at roughly 70% utilization in peak periods. At 2022 utilization rates (about 10p.p. higher), they could reduce gas burns by roughly 9 Bcm over March-October.
The “fair value” price level for demand destruction - where enough demand falls away to rebalance the market without requiring Europe to exhaust its storage refill capacity - likely sits in the range of TTF at 60-70 EUR/MWh during the summer injection season.
The key difference from 2022 is coal inventory: global coal stockpiles are far healthier than they were in the initial post-Ukraine energy crisis, with Chinese coal inventories at roughly 8x their mid-2021 trough and US coal stocks approximately 20% above 2022 levels.
That limits how high natural gas prices need to go to trigger coal substitution - the coal is available, so the gas-to-coal switch can happen faster and at lower gas prices than in 2022.
The US decoupling:
Here’s something many investors are missing:
The Henry Hub gas price, and by extension US LNG export economics, is significantly less exposed to Gulf disruptions than the European and Asian markets.
The transmission channel works through utilization: if Qatari and UAE LNG is absent from global markets, and US LNG steps up to partially fill the gap, US export terminals run at higher utilization - drawing down US domestic gas inventories and supporting Henry Hub prices.
But the US also has healthy coal stockpiles that can replace gas-fired generation domestically, dampening the pass-through into domestic prices.
US natural gas consumption patterns are less dependent on spot LNG pricing than Asian markets.
There is also a timing dimension that is easy to miss. The US exported 111 million metric tons of LNG in 2025 - the first country ever to exceed 100 million mt in a single year - and entered 2026 with terminals running close to peak utilization.
Golden Pass LNG Train 1, a joint venture between ExxonMobil and QatarEnergy, was commissioning its first cargoes in Q1 2026, adding roughly 0.7 Bcf/day of incremental capacity.
Plaquemines Phase 2 and Corpus Christi Stage 3 were simultaneously ramping up.
Qatar went offline exactly as the US was adding 18-22 million mt of annualized export capacity - the largest single-year increment in US LNG history, arriving at the moment the market most needed it.
That is not strategic planning. It is timing that will nonetheless have strategic consequences.
The implication: the 2026 Gulf disruption is primarily a TTF and JKM event.
Henry Hub may see some support but won’t reprice by the magnitude European and Asian buyers experience.
This actually matters for how you think about US LNG exporters (whose economics are largely Henry Hub-based, with the margin captured from the destination price) versus the upstream US gas producers (more directly exposed to Henry Hub).
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What the decade looks like:
The medium-term: structured oversupply
The combination of the supply wave (400 Bcm/year of new capacity by 2035) and the demand-side recalibration (China revising down, Japan and South Korea flat, Europe limited) creates a period of structural oversupply in global LNG markets, most pronounced in the 2028-2033 window when the largest volume of new US and Qatari capacity enters service simultaneously.
During this period, US LNG export capacity utilization is projected to fall well below recent highs - some models suggest averages in the 63-75% range during the loosest years, compared to 90%+ today.
The analogue from 2020 is instructive: when US LNG exports collapsed during the COVID demand shock, Henry Hub prices fell to near $1.50/MMBtu and several cargoes were cancelled.
The supply is price-elastic in both directions - it will find homes, but at lower prices.
The 60-70 EUR/MWh TTF spike thesis from the current Gulf disruption is, paradoxically, compatible with a medium-term oversupply world: a temporary disruption creates a temporary price spike; the structural trend is toward moderation once the supply wave clears.
The long-term: the bottleneck thesis wins
By 2033-2035 and beyond, the picture changes - assuming the infrastructure buildout in emerging APAC eventually catches up to demand.
Regasification capacity is gradually being added; India in particular has multiple regasification projects in various stages of development.
Gas storage will eventually be built - necessity is the mother of infrastructure investment.
Gas turbine lead times will likely shorten as manufacturers expand capacity.
When that infrastructure catches up, the combination of 280 Bcm/year of emerging APAC demand growth, a flattening supply curve (most currently announced projects will be fully operational by 2031), and Henry Hub as the global price anchor creates a constructive multi-year backdrop.
The convergence thesis also plays out on the price side: as US facilities run at lower utilization during the oversupply window, Henry Hub prices face downward pressure, narrowing the historic Henry Hub-to-JKM spread.
The US domestic gas market increasingly becomes the global balancing mechanism - a structural shift with significant implications for US gas producers and utilities.