The profitability of U.S. liquefied natural gas (LNG) continues to thrive despite concerns regarding oversupply. From 2023 to 2025, the average margin on a U.S. Gulf Coast (USGC) cargo destined for Europe stood at an impressive $4.56 per million British thermal units (MMBtu), translating to approximately $17.5 million per LNG vessel. This marks a significant recovery from the negative margins experienced during the pandemic in 2019 and 2020. These favorable conditions have attracted a variety of investors, including national oil companies, sovereign wealth funds, and private equity firms, all eager to capitalize on the booming U.S. LNG market.
As a result, numerous final investment decisions (FID) have been made for both greenfield and brownfield projects. Despite rising concerns about low prices and the prospect of an incoming oversupply, many investors remain undeterred. Nevertheless, the optimism surrounding U.S. LNG faced a critical moment on December 5, when the TTF-Henry Hub differential plummeted to $4 per MMBtu, the lowest spread recorded since April 2021. This shift raised alarms about squeezed margins, as the TTF approached the full costs of U.S. LNG deliveries to Europe.
In examining historical context, the only significant episode of LNG cargo cancellations in the short history of the USGC LNG sector occurred during the Covid-19 pandemic in 2020. Despite TTF prices consistently falling below the full costs of U.S. LNG, facility utilization did not decline. This resilience can be attributed to fixed costs being viewed as sunk investments. LNG offtakers are primarily focused on covering their variable costs, which include the costs associated with transporting LNG.
The short-run marginal costs (SRMC) for U.S. LNG encompass several elements: the cost of feedgas (Henry Hub), liquefaction losses, and variable shipping and regasification expenses. Fixed costs include the tolling fees of LNG offtake contracts, averaging around $2.5 per MMBtu, along with fixed shipping and regasification costs. For cargo cancellations to occur, the TTF-Henry Hub spread must remain below the variable costs of U.S. LNG for a sustained period of one to two months.
Looking ahead, future market conditions indicate a TTF-Henry Hub differential above $4 per MMBtu, even as oversupply intensifies by 2028 and 2029. Nonetheless, projections based on Rystad Energy’s forecasts suggest that by 2031, the differential could narrow to $2.84 per MMBtu for TTF and $3.35 per MMBtu for East Asia spot LNG prices, still clearing the variable costs for U.S. LNG deliveries.
Three potential utilization scenarios emerge for U.S. LNG. First, in a base case scenario, full utilization continues. The second scenario sees utilization fluctuating between 100% and contracted volumes, approximately 80% of full capacity. In this case, TTF-Henry Hub spreads may decline to between $1 and $1.5 per MMBtu, which would still be above variable costs, allowing LNG developers to optimize production.
In the third scenario, if U.S. LNG utilization dips below 80%, cargo cancellations could occur, primarily if market conditions cause differentials to remain compressed below variable costs for an extended period. Analysts predict that, unlike the demand-driven shut-ins during the pandemic, any future reductions in production will likely stem from oversupply, as LNG production outpaces demand growth.
The global LNG market dynamics also point to a potential increase in price-sensitive demand, particularly from regions such as Japan, South Korea, and Europe. Historically, LNG has displaced seaborne coal when prices are within $1-$2 per MMBtu of coal prices, primarily due to the efficiency gains of gas turbines. As LNG prices approach the $6-$7 per MMBtu range, demand is expected to rise.
In North America, the Henry Hub price, a critical factor for U.S. LNG operations, faces upward pressures due to increasing baseload gas demand. Analysts forecast that U.S. LNG capacity will nearly double from 109 Mt to 190 Mt before the end of the decade. As coal-fired power plants continue to be retired, the demand for natural gas is expected to become less elastic to price fluctuations.
Consequently, the implications for U.S. LNG remain significant. A cold winter or supply disruptions could elevate Henry Hub prices, impacting the profitability of U.S. LNG cargoes. For broad-based cargo cancellations to occur, the TTF-Henry Hub spread would need to converge below $1 for one to two months. As the U.S. solidifies its position as a leading global LNG producer, the link between Henry Hub and global LNG prices will become increasingly pronounced, with changes in Henry Hub likely affecting international LNG markets.
The insights presented here reflect the author’s views and are not necessarily representative of Rystad Energy.
