The extremely high levels of LNG supply into the market continue, though the expected new terminals have yet to make an impact in 2019. While we have often discussed the supply side this year, the much-anticipated new trains have finally started to make an appearance, with Australia’s 3.6 Mtpa Prelude and the 4.0 Mtpa US Cameron T1 project both seeing first exports at last. Those two projects are set to start ramping up production, and their exports will be joined in Q3 19 by the 4.5 Mtpa Corpus Christi T2 and the 4.2 Mtpa Freeport T1. We could start to see the first m/m increases in production this year.
While the strength in supply alone would be bearish for the market, the strength of Chinese demand has come off significantly. Even though China’s LNG imports were up by 0.3 Mt (7%) y/y, this was the weakest monthly growth since 2016. That growth was partially supported by a reduction in pipeline imports (-0.14 Mt), which highlights how the Chinese economic slowdown, exacerbated by the trade war, has delayed China’s dash to gas. Still, Chinese LNG imports are expected to grow by 5 Mt y/y in H2 19, although the risks now seem to be to the downside.
The only area of demand growth that was consistent over Q2 19 was South Asia, one of the most price-sensitive regions for LNG. The sub-6 $/mmbtu pricing that has been predominant in summer prices since mid-March is starting to be felt on the demand side. Indian growth of 0.8 Mt y/y across Q2 19 has been helped by some infrastructure developments, with the imminent commissioning of the 2.5 Mtpa Dahej expansion and the long-awaited completion of the Kochi downstream pipeline both suggesting further growth opportunities during the rest of the year.
Still, all of the supply growth has kept the focus on Europe and its ever-loosening summer gas balances. Over Q3 19, that looseness will increase. Europe still has a y/y surplus of gas in storage of around 25 bcm, little changed from the start of the injection season, with Q2 19 injections largely flat y/y. High supply, combined with a steep contango in the TTF curve, has incentivised continued storage injections. As a result, injection rates will need to fall sharply in Q3 19 as storage facilities begin to hit capacity weeks in advance of the likely start of the withdrawal season.
European looseness, and the fact that the arb is still open between the US and European markets, highlights an emerging tension between the prompt focus of hubs and the M+2 decision-making of the LNG market. Given that we expect to see considerable and growing pressure on the TTF as we move to the end of the injection season, how such an oversupplied hub will deal with a continued flow of incremental LNG is a big question for the markets. While hedged cargoes could still physically swing into the market, it could be far more profitable to meet that contract obligation with gas bought at the hub itself. Will the hedges be unwound and the US gas left to go into US storage facilities, or will EU pipes turn down? Or will more of those cargoes be used for floating storage? Given the extent of the contango between the summer and winter contracts, paying for a two-month floating storage position is certainly economical. We could see both a closing of the US–global gas price arb window and an eventual swelling of the floating storage play, and the latter should start to erode some of the wide summer-winter contango currently in the market.