Global liquefied natural gas (LNG) prices have experienced a significant increase in key Asian and European markets following the closure of the Strait of Hormuz, a critical chokepoint for global energy trade. The disruption has rerouted substantial volumes of LNG, impacting supply dynamics and driving up benchmark prices in these regions.
Futures prices for LNG delivered to the Title Transfer Facility (TTF), the European benchmark, saw a notable rise. For the week ending April 24, the TTF price reached $14.80 per million British thermal units (MMBtu). This represents a 35% increase compared to the price levels observed prior to the Strait of Hormuz closure, according to data compiled by Bloomberg L.P.
Similarly, East Asian markets have also felt the impact, with the front-month futures price for the Japan-Korea Marker (JKM), the regional benchmark, climbing by 51% over the same period. The JKM price stood at $16.02/MMBtu for the week ending April 24, reflecting heightened demand and reduced supply availability.
In stark contrast, natural gas prices in the United States, benchmarked at the Henry Hub, have moved in the opposite direction. Since February 28, Henry Hub prices have declined by 9%. This divergence is attributed to limited near-term opportunities for expanding U.S. LNG exports and robust domestic natural gas storage and supply levels as the winter season concludes.
The closure of the Strait of Hormuz has directly affected an estimated 10 billion cubic feet per day (Bcf/d) of global LNG supplies. This volume represents approximately 20% of the total global LNG trade, with a significant portion originating from Qatar's Ras Laffan export facility. Data from Kpler indicates that no laden LNG vessels have transited the strait between March 1 and April 24.
While U.S. LNG exports are expected to increase, the growth is anticipated to be modest and will only account for a fraction of the volumes displaced by the Strait of Hormuz closure. The U.S. Department of Energy has approved two increases to terminal export authorizations for countries without free trade agreements (FTAs) with the United States since February. These include Plaquemines LNG, with an additional 0.5 Bcf/d approved in March, and Elba Island, with a 0.1 Bcf/d increase in April. Countries lacking FTAs are the primary destinations for nearly all U.S. LNG export volumes.
Further capacity additions are expected to come online in the coming months. Approximately 2.4 Bcf/d of DOE-authorized export capacity is slated to become operational between April and December 2026. This includes the Golden Pass project (Trains 1–2) and Corpus Christi Stage 3 (Trains 5–7), which will add significant export capabilities.
U.S. LNG terminals are currently operating at high utilization rates, which inherently limits the potential for substantial increases in domestic natural gas exports in the short term. This operational constraint also caps the extent to which U.S. domestic market prices could be significantly influenced by international market volatility.
In March, the United States exported an estimated 17.9 Bcf/d of LNG, marking the second-highest monthly export volume on record, surpassed only by the 18.4 Bcf/d recorded in December 2025. The utilization rate at export terminals in March reached 94% of the maximum DOE-approved export levels, according to the U.S. Energy Information Administration's (EIA) Short-Term Energy Outlook and Liquefaction Capacity File. This represents an increase from February's estimated 17.3 Bcf/d, which had a terminal utilization rate of 91%.
QatarEnergy declared force majeure on March 4, a move that has compelled Asian buyers, who typically import over 80% of Qatar's gas, to seek alternative spot cargoes on the global market to compensate for the disrupted contract volumes. This has intensified competition for available LNG supplies.
Although average weekly TTF prices have receded from a three-year high reached in mid-March, they continue to trade at elevated levels compared to February. European natural gas storage inventories concluded the winter season at 28% capacity, falling short of the five-year average of 41%, according to Gas Infrastructure Europe. This deficit will likely necessitate increased purchases of spot cargoes to replenish storage facilities before the next winter season.
Asian natural gas storage capacity is generally less extensive than that of Europe. Consequently, JKM prices are expected to remain sensitive to weather-related demand fluctuations in the region. The weekly average front-month futures prices for the U.S. benchmark Henry Hub have largely remained insulated from the price volatility observed in international markets.
Henry Hub futures prices have experienced a 9% decrease since the week ending February 27, coinciding with the end of the winter heating season and a subsequent decline in domestic consumption. At the commencement of the natural gas injection season, daily Henry Hub prices for the prompt month reached their lowest levels since October 2024.
