The first year of Trump 2.0 has clearly highlighted the administration’s desire to leverage US hydrocarbon resources as a diplomatic tool. Countries facing large increases in tariff rates following ‘liberation day’ have promised to buy large volumes of US LNG to reduce trade deficits and secure less onerous tariff rates with Washington. Most notably, the EU has committed to $750b in energy purchases over three years ($250b/yr), up from $95b in 2024, with most of the projected increase from additional LNG buying. In H1 2025, 55% of European LNG imports were sourced from the US, and the European Commission’s purchase commitments imply relative comfort in this number moving significantly higher.
Marketing US LNG internationally clearly enjoys robust institutional support in Washington, with significant resources devoted to the effort. A high-level US delegation, including the US energy secretary, held a meeting as part of the Partnership for Transatlantic Energy Cooperation in Athens in early November 2025 to promote the vertical gas corridor—a plan to import US LNG into Greece, transit molecules into southeastern Europe and ultimately reach Ukraine’s large gas storage facilities.
As part of the wider ‘energy dominance’ agenda, Trump is clearly seeking to formalise and lock in Europe’s increase in demand for LNG arising from the loss of Russian pipeline gas following the invasion of Ukraine, with long-term supply contracts. Indeed, beyond simply encouraging allies to commit to US supply agreements, Trump has actively lobbied for residual buyers of Russian gas (both pipeline and LNG) to halt purchases on an expedited timeline, with the European Commission bringing forward a ban on Russian LNG imports by one year as part of the bloc’s 19th sanctions package. Of course, US LNG is ready to provide the replacement molecules.
Trump’s LNG diplomacy will likely run into commercial and regulatory reality, however. Firstly, this is not the era of ‘pipeline diplomacy’. Generally, consumer countries do not sign LNG deals with US liquefaction projects—these are usually bilateral agreements between private companies, at least in the European context.
There is no way for the European Commission to induce companies to sign LNG supply agreements. As such, decisions will be largely commercially driven, and at present, that commercial outlook appears poor in the short-to-mid-term. Indeed, the unprecedented wave of new LNG supply (the IEA estimate liquefaction capacity to increase by 300bcm/yr by 2030 compared with 2024 levels) will transition the market towards a demand creation regime, pressuring the rich TTF–Henry Hub (HH) and JKM–HH spreads that have incentivised US project development.
While the current TTF–HH spread has come down from the peaks observed through the energy crisis, it remains relatively attractive at $6/m Btu, while the current curve averages of approximately $5/m Btu for calendar year 2028. We expect these spreads to actualise significantly narrower than currently reflected on the curve in the coming years.
Supply and demand
The spike in global gas prices following the Russian invasion of Ukraine provided the commercial rationale for US FIDs, but the volume of LNG capacity hitting the market will far outstrip Europe’s residual import requirements, particularly given the declining consumption trend and lack of flexibility (remaining coal-gas switching) available. Instead, these molecules will need to be absorbed in lower-income markets, pricing below oil-liquids parity and potentially displacing higher-cost coal imports.
While the demand creation price is largely unknown, a consensus around $6/m Btu has recently gained traction, with consumption market benchmarks likely tending towards this level. On the supply side, lower oil prices imply lower associated gas production and a greater reliance on incremental Haynesville supply, whilst the market is also likely to tighten with additional gas-power consumption emerging to support the buildout of datacentres as part of the wider AI thematic. A structurally supported HH price above $4/m Btu is realistic.
As with 2020, US cargo shut-ins may ultimately be the lever to balance an oversupplied global market as TTF and JKM prices tend towards HH parity as a global gas price floor. However, rather than a black swan event triggered by the pandemic, this would instead be embedded as a regular market balancing factor, with our models implying particular vulnerability through injection seasons following mild European and Asian winters.
In this scenario, US exporters are ultimately protected by the relatively rigid take-or-pay SPAs that underpin supply agreements, with offtakers instead exposed. Indeed, in a scenario where cancelling a cargo, paying fixed fees and securing alternative spot supply is more cost effective than lifting contracted gas, a long-term US LNG offtake agreement would prevent European buyers from taking advantage of low spot prices.
From the regulatory standpoint, the disparate nature of the domestic US upstream sector means it is hard for US exporters to comply with the EU’s upcoming methane rules due in 2027, whilst European companies cannot hold long-term contracts for unabated gas beyond 2049.
This commercial and regulatory logic largely explains the reluctance for European end-users to sign long-term agreements, and instead why the majority of recent offtake agreements with US terminals have been signed with aggregators, who can leverage global portfolios. Of course, US LNG molecules will continue to flow to Europe, and the continent will need additional volumes following the next leg down in Russian supply following LNG sanctions in 2027 and the loss of TurkStream flows in 2028. However, the flow of these molecules will continue to be dictated by commercial logic, rather than Trump’s energy diplomacy.
Joel Hancock is director, commodities research at Natixis CIB. This article is taken from our Outlook 2026 report. To read Outlook in full, click here.
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