Ten days ago, China announced retaliatory tariffs on American energy imports and also announced an antitrust investigation into Google, just minutes after a sweeping levy on Chinese products imposed by U.S. President Donald Trump took effect. Beijing said it would implement a 15% tariff on coal and liquefied natural gas (LNG) products as well as a 10% tariff on crude oil, agricultural machinery and large-engine cars. Well, the tariffs came into force on 10 February, marking the beginning of another trade war between the world’s biggest economies under Trump. Commodity analysts at Standard Chartered have delved into the potential effects of the tariffs on the U.S. energy sector.
StanChart has pointed out that China first levied a tariff of 10% on US. LNG imports in September 2018 and then increased to 25% in June 2019. StanChart notes that whereas some imports continued at the 10% rate, there were none at the higher rate. Beijing then granted tariff waivers for LNG in February 2020 as part of a trade war de-escalation and after 11 months of zero flows, with the first US cargo arriving in April 2020. According to the analysts, in the following 59 months, there have been cargoes in all but three months. Further, the relationship between U.S. producers and Chinese LNG buyers has deepened with some long-term contracts signed. In contrast, no long-term LNG contracts between the two countries were signed prior to 2021.
However, the potential negative effects of the latest tariffs on LNG are likely to be limited. The U.S. currently provides less than 6% of China LNG imports, while China accounts for just 6% of U.S. exports. With Europe’s demand for U.S. LNG likely to remain robust, StanChart has predicted that displaced flows are unlikely to become distressed. StanChart sees the tariffs cutting the flow of spot cargoes to China dramatically, with some flows under longer-term contracts likely to continue, depending on the nature of re-export clauses. The experts have warned that the biggest threat of these tariffs is the economics of future long-term contracts, including contracts amounting to at least 15 million tonnes per annum (mtpa) that have already been signed.
U.S. Gas Prices Surge On Strong LNG Demand
U.S. natural gas futures climbed to $3.7/MMBtu, the highest in three weeks, driven by lower output, rising LNG exports and colder weather forecasts. Gas flows to the eight major U.S. LNG export plants averaged 15.3 bcfd so far in February, up from 14.6 bcfd in January, close to record levels. Daily LNG feedgas hit 15.9 bcfd on Thursday, surpassing the previous high of 15.8 bcfd on January 18. Meanwhile, extreme cold froze some wells, causing daily gas output to drop by 3.7 bcfd over the past week to a two-week low of 103.0 bcfd. Weather forecasts indicate colder-than-normal temperatures through February 22, boosting heating demand. Additionally, the EIA reported that U.S. utilities withdrew 100 bcf of natural gas from storage in the week ending February 7, bringing total inventories down to 2,297 bcf, more than the expected 92 bcf draw.
Meanwhile, European natural gas futures pulled back below €51 per megawatt-hour on Thursday from a two-year high of 58.039 per megawatt-hour (MWh) they hit on 10 February driven by milder weather forecasts that are expected to reduce heating demand.EU inventories stood at 56.95 billion cubic metres (bcm) on 9 February according to Gas Infrastructure Europe (GIE) data, 21.45 bcm lower y/y and 8.09 bcm below the five-year average. The w/w draw to 9 February was 4.9 bcm, 37% higher than the five-year average (3.58 bcm) and almost twice the draw for the same period last year (2.5 bcm). Cessation of Russian gas transit through Ukraine accounted for the bulk of the m/m reduction (1.47 bcm), although a 0.824 bcm m/m fall in flows from Norway also played a significant role.
Excluding transit flows, EU imports of Russian pipeline gas totaled just 1.362 bcm in January 2025, 90% lower than in January 2021. Commodity analysts at Standard Chartered have projected that If temperatures for the rest of the northern hemisphere winter were to normalize, inventories would finish March at close to 44 bcm, while a continuation of the recent larger-than-usual draws would result in an end-season inventory level of 39.1 bcm. The latter forecast for the end-season minimum would be 29 bcm less than last year’s number, but ~10 bcm higher than in 2022 in the immediate wake of Russia’s invasion of eastern Ukraine.
By Alex Kimani for Oilprice.com