The average margin on a US Gulf coast (USGC) cargo destined to Europe, including regasification costs, was $4.56 per million British thermal units (MMBtu) between 2023 and 2025, or $17.5 million per one LNG vessel, compared to negative margins prior and during the pandemic in 2019 and 2020. These attractive profits have spurred national oil companies and majors, sovereign wealth funds, private equity, Asian utilities and other energy buyers to flock to the USGC with their checkbooks to get in on the action. As a result, a flurry of LNG final investment decisions (FID) has been undertaken during this period, both from greenfield and brownfield projects. The notion of the incoming LNG oversupply has deterred very few investors, despite rising risks of low prices. Yet, this bullish perception began to get questioned on 5 December when the TTF-Henry Hub differential collapsed to $4 per MMBtu, the lowest spread seen since April 2021. The industry reported squeezed margins, with TTF approaching the full costs of US LNG delivered to Europe (Figure 1), and fears of production shut-ins if the differential continued to drop.

Historical context
The only episode in the short history of the USGC LNG industry which saw broad LNG cargo cancellations was back in 2020 during the Covid-19 pandemic. Using this as a case study, Figure 2 shows that during 2019 and 2020, even with TTF always being below the full cost of US LNG delivered to Europe, facility utilization didn’t incur any declines. This is a result of fixed costs (pink bars) being considered sunk, while LNG offtakers are only concerned with covering their variable costs of transporting LNG (blue bars), also known as the short-run marginal costs (SRMC). This played out from April to August 2020, when TTF (white tick markers) dropped below the SRMC (blue stacked bars) of US LNG delivered to Europe for an extended period of time, during which we saw 150+ cargos cancelled and US LNG utilization plumet for a 5-month period. An important feature of this market mechanism is that LNG contracts mandate a 45 to 60-day notice period if the offtaker wishes to not lift a cargo, meaning that US LNG utilization lags prices by 1-2 months. That means that short stints of price compression between TTF and Henry Hub – for example, from simultaneous opposite extreme weather patterns in both continents – won’t be enough to shut-in LNG production in the USGC, beyond operational reasons and dominium’s optimization. 

SRMC is broken down into the following segments: 1) the cost of feedgas (Henry Hub); 2) 115% of the cost of feedgas to cover liquefaction losses and profit to the LNG developer; and 3) variable costs of shipping and regasification. While fixed costs include: 1) the tolling fee of LNG offtake contracts, which hovers around $2.5 per MMBtu; and 2) fixed shipping and regasification costs. Note that there is some nuance with shipping and regasification costs depending on business models – if offtakers own a fleet or vessels or regasification capacity. The economics are as follows: the TTF-Henry Hub spread must be sustained below the variable costs of US LNG delivered to Europe (feedgas losses, variable shipping and regasification) for a 1–2-month period for US LNG cargo cancellations to materialize. Variable costs, in a balanced market, are around $1 per MMBtu to Europe and $1.5 per MMBtu to East Asia.

Utilization scenarios
Looking ahead, the forward curves point to a differential of above $4 per MMBtu, even during 2028 and 2029, when oversupply becomes more severe. Even so, as forward curves have lower liquidity farther along the curve, there is less certainty during that time frame. Rystad Energy’s price forecasts point to the narrowest differential in 2031, being $2.84 per MMBtu with TTF and $3.35 per MMBtu with East Asia spot LNG price, clearing the variable costs of US LNG to both continents. Therefore, US LNG remains fully utilized in our base case scenario (figure 4).

The second scenario outline is seen when US LNG utilization shifts downwards and fluctuates between 100% and the share of contracted volumes, which hovers around 80% of full capacity. In this scenario, TTF-Henry Hub spreads fall to $1-$1.5 per MMBtu ($1.5-$2 per MMBtu for Asia) but remain above the variable costs of US LNG to Europe. Yet, they would be low enough to cause LNG developers to deploy optimizations for non-contracted LNG production and/or use the time to carry out maintenance, although optimization would be the only commercial reason to lower production.

The third scenario shows US LNG utilization dips below 80% (share of contracted volumes) as cargos lose profitably and cancellations arise. This scenario begs the question: what are the market conditions in which differentials compress below variable costs for an extended period of time, beyond temporary extreme weather patterns?

Global power generation weakness
As opposed to the 2020 shut-ins induced by Covid-19, which was demand driven, the incoming downside pressure on prices will be supply driven as LNG production outpaces demand growth. Industry analysts are betting that as prices fall, price sensitive LNG demand will emerge. Historically, this has been the case, and most of the displacement comes at the expense of seaborne coal consumption. Traditionally, LNG has also displaced seaborne coal when prices are within $1-$2 per MMBtu of the seaborne coal prices, particularly in Japan, South Korea and Europe. This is due to efficiency gains of gas turbines, with combined-cycle turbines typically sitting in the range of 50-60% thermal efficiency while conventional coal-fired power plants are near 33-38%. The Newcastle coal price index fluctuated around $4-$5 per MMBtu in 2025, meaning that price sensitive LNG demand is likely to appear when prices hit the $6-$7 per MMBtu range. Europe could see incremental demand at slightly higher LNG prices, closer to $7-$8 per MMBtu as their carbon price decreases the competitiveness of coal. For reference, between Japan, South Korea and Europe, seaborne coal consumption was north of 300 Mt per annum (Mtpa) in 2025.

The other big bet of LNG demand is from China and emerging markets in Asia, which are solely economics driven and therefore have no appetite for emissions reductions. The displacement in these countries comes from other fuels, notably liquids. At a landed price of $7 per MMBtu in these countries, LNG becomes competitive with bunkering, residential and commercial LNG, petrochemicals, refining naphtha, ammonia production, firm renewables, and truck fuel oil. Given this backdrop, the scenario of US LNG shut-ins is only possible in a global economic recession, where weakened energy demand, power generation and low oil prices cause oil switching capabilities to be fully exhausted, leaving no price sensitive energy demand to absorb US LNG. 

Henry Hub upside risks
The other side of the equation is North American gas prices – the cost of feedgas of these LNG facilities in the USGC. In the next five years, US baseload gas demand will see extreme growth, with LNG capacity nearly doubling from the current 109 Mt to 190 Mt before the end of the decade, and datacenters add 1.3-1.5 Bcfd of power generation demand every year out to 2030, although not all of this will be served by natural gas. In addition, coal-fired power plants will continue to be retired, making gas-for-power demand less elastic to prices. As demand becomes less elastic, supply side economics become increasingly challenging as shale plays mature further and tier 1 inventory continues to dwindle. This is most prevalent in the Haynesville, where well productivity is seeing more notable degradation. The Permian and Appalachia, where economics are stronger, suffer from constrained pipeline infrastructure to get molecules to market. Broadly speaking, this implies a Henry hub consistently in the $4-$5 per MMBtu range in the medium term.

As seen so far this winter, a cold spell throughout the country and wellhead freeze-offs can lead to Henry Hub skyrocketing to mid- to high-$5 per MMBtu. The same is true for a warm stretch that can send the marker tumbling back down. In a scenario where TTF is trading near $1-$2 above seaborne coal, at around $6.5 per MMBtu, a spike in Henry Hub to the upper $5 per MMBtu could leave US LNG cargos unprofitable. Yet, as highlighted above, broad-based US LNG cargo cancellations require the TTF-Henry Hub spread to converge to below $1 over the course of one to two months. As the US becomes the marginal global LNG producer – potentially accounting for 35% of global LNG production by 2030 – the increase in Henry Hub index contracts mean that the price of TTF and JKM become more closely tied to, not only regional supply-demand fundamentals, but to the price of US LNG contracts. Therefore, the cost of marginal LNG supply is bound to fluctuate with the price of Henry Hub, implying that a rise in Henry Hub will also lead to a rise in global LNG prices, as we’ve seen so far in 2026. 

Disclaimer: The opinions expressed in this article are solely those of the author, and do not necessarily represent the views or beliefs of Rystad Energy. 

***

For further reading, explore our recent insights:

• Weekly oil trading signals - Delivered straight to your inbox, our signals draw on high-frequency, short-term data. They cover oil supply, demand, real-time consumption, downstream refining and OPEC+ decisions.

• 'Trump and Energy' special report series: Venezuela, the country's oil infrastructure and what it would take to lift its crude output to 3 million barrels per day (bpd).