Lower Asian demand in September and October partially responsible for excess LNG flows into Europe but threat of delay to Nord Stream 2 pipeline probably also factored
The rise of US LNG means LNG markets are flush with new supply whilst the prevailing ‘tolling’ model for US LNG means traders can profit from cheaper North American gas but face significant downside risk if demand growth slows.
A spike in journey times highlights lower demand
This was particularly felt during September and October when demand in the Far East decreased, leaving several US cargoes lifted in August and September circling the oceans. Journey durations spiked as vessels remained in limbo for several weeks, including the British Sponsor and the Gaslog HongKong.
Traders initially sent some cargoes the long route to buy time…
Other LNGCs such as the Diamond Gas Sakura and the GasLog Shanghai were deliberately sent via the Cape of Good Hope to time deliveries considerably into the future. As such, the Diamond Gas Sakura took 85 days to deliver a Cameron cargo lifted on 18 August to CPC’s Yung-An terminal in Taiwan, a journey which usually takes less than half the time, after the vessel turned back from the Panama Canal to take the route around South Africa.
…then switched to Europe
Fortunate traders were able to adjust in October and journey times plummeted as cargoes found shelter in Europe and went into gas storage. Whereas only 8 US LNG cargoes found their way into European tanks in October 2018, there were 19 in October this year, so that the 137.5% growth in the number of cargoes delivered to Europe far outpaced the 72.4% of overall growth in US LNG cargoes y/y. Nevertheless, we think some of these cargoes to have traded at considerable discounts as regional storage capacity filled. Meanwhile, a few US cargoes remain idling off European shores, including roughly 147,000m3 aboard the BW GDF Suez Paris and 139,700m3 aboard the Solaris.
US-European LNG trade describes both a convenient outlet and a hedge
Whilst from a trader’s perspective Europe thus posed a convenient recipient for what would otherwise have been surplus LNG, we believe the additional US volumes also served as a convenient hedge for European utilities against the looming delay of Gazprom’s Nord Stream 2 pipeline into Germany. The pipeline was originally scheduled to become operational by the end of this year when a Russo-Ukrainian gas transit agreement – a major export route of Russian gas into Europe – expires. Delays at the time seemed inevitable, however, as a 2019 amendment to the European Gas Directive forbids gas suppliers to control supply infrastructure, but which directly contravenes Gazprom’s pipeline gas export monopoly enshrined in Russian law. A threat by Chancellor Merkel to suspend the project until protracted litigation between Gazprom and Ukraine energy company Naftogaz was resolved added to uncertainty.
US LNG focus back on Far East
Meanwhile, traders seem to have swung back towards destinations in the Pacific and the Far East and we expect around 60% of US cargoes currently at sea to arrive in the Far East by 19 December. In line with the run up to winter, Far Eastern LNG demand has begun to rise again, with our initial outlook already pegging this month’s regional demand 2.5% higher y/y.
US LNG risk firmly lies with portfolio players, not capacity owners
US liquefaction plants typically sell their LNG at 115% of US gas futures plus a fixed gas liquefaction fee of $3-4 /mmBtu in what is known as the ‘take-or-pay’ or ‘tolling’ model.
Early adopters such as BG Group (now part of Shell’s portfolio) even managed to negotiate fees as low as $2.25/mmBtu for the 3.5mtpa it signed with Cheniere from Sabine Pass T1. Other companies such as Total with stakes in more than one train are also likely to have managed to secure lower fees.
Under the tolling model, the plant operator effectively leases out liquefaction capacity to portfolio players and major utilities for the duration of the supply contract (on an annualised basis), with the caveat that a fixed fee is payable regardless of whether the portfolio player uses the contracted plant capacity or not.
For the plant operators such as Cheniere this model means revenue are secure. For LNG portfolio players this imparts a downside risk of tens of millions of US$/month, incentivised by relatively low US gas prices following the US shale gas boom in the Marcellus and Utica plays and associated gas from the Eagle Ford play and other Texan sources. The EIA’s latest figures at the time of writing peg Henry Hub prices at $2.72-2.87/mmBtu.Previous:
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