Spot Strength for Liquefied Natural Gas
November 2017
After a strong start, October LNG spot prices plateaued mid-month as spot demand from China eased, and December delivery forward contracts remained weak, due to an expectation of warmer weather.

Arbitrage opportunities between Europe and Eastern destinations remain steady as compared to September. The Asian spot price for winter deliveries occurred in a relatively high band from US$8.50/Mbtu to US$9.00/Mbtu, but this is relatively stable after September’s steep rise from levels close to US$6.90/MBtu.  Western Europe’s gas prices over the month ranged from US$6.90 to US$7.70/Mbtu.  Henry Hub ended the month on a bearish note, at US$2.89/Mbtu, but this is not a remarkable departure from the September average of US$2.98/Mbtu. US Sabine Pass netbacks into Europe were estimated at around US$6.00 to US$6.40/Mbtu while for Asia, these were US$7.40 to US$7.50/MBtu range. Western European gas prices are stable at the end of the month, and bullish due to lower hydro-energy supplies, at around US$7 to 7.20/Mbtu.

Contracted prices paid by Asian importers also reflected higher Brent-linked pricing, roughly aligned with spot prices. Pakistan January delivery contracts with an oil linkage, ranged from 16% to 16.9% of the Brent price, somewhat higher than the 13.95 to 14.5% linkage recently applied to longer term supply deals.

With global liquefaction capacity largely already committed, spot volumes were also coming from trader portfolios in addition to sales from remaining spare capacity. Currently, the spot market is around 25-30% of total traded volumes, representing around 70Mtpa or higher, but over the month buyers in China and Korea appeared to be returning to contracted arrangements.

At 88 vessel loadings over the final week of October, seaborne volumes were down on the previous week’s total of 93 shipments, but are still higher month-on-month over the same week in the previous month which totalled just 82 loadings. Qatar remains the leader, shipping 19 cargoes each week over the month, while Australia managed to ship between 16 and 19 cargoes, just ahead of the combined Brunei, Indonesia and Malaysia numbers, who averaged 14. Algeria and Nigeria consistently loaded up to seven vessels each over most of the period.

But bearish sentiments led potential buyers to hold off on taking up new long term contracts, an ongoing obstacle to the commercialisation efforts by proposed liquefaction ventures in North America. In sharp contrast, ENI’s US$2.8bn deal to sell off 25% of its Area 4 in Mozambique to ExxonMobil will likely accelerate the development pathway for MZLNG. We view ExxonMobil’s portfolio trading division as a strong candidate to provide

commercialisation for MZLNG, and this could therefore provide the impetus to speedup collaborative development agreements between the Area1 and 4 partners.

We note that growth in demand in Latin America, the Middle East, including Turkey, South and South-East Asia as well as in Korea could absorb much of the estimated 70Mtpa available to the global spot volumes.

Costs and commercialisation issues have also pushed back the 10Mtpa Kitimat LNG’s project timeline, with operator Chevron indicating that its British Columbia based terminal will start operation from 2027, at the earliest.

But overall, LNG’s flexibility and relative immediacy also means that regas terminals continue to proliferate. These represent a relatively low-cost, precautionary infrastructure that can ensure rapid gas inflows for main consumption centres in times of emergency, even those with pipeline access to large gas fields. As such AME expects that the number of import terminals will continue to grow, and that the average global utilisation rate for most will continue to be less than 40%. The projection for demand growth is exemplified in a spate of proposed, regasification terminals, especially in southern Asia, and these are expected to operate at higher than average utilisation rates due to domestic demand growth in Pakistan, Bangladesh, India and further to the East, China, The Philippines and Thailand.

The current supply glut is expected to deepen during 2018-19 as capacity nears 380Mtpa, but the lower prices for liquefied natural gas trades continue to stimulate demand growth. While concern remains over the long lead time between a final investment decision and first LNG cargo delivery – typically more than five years, there continues to be steady pace of LNG trade growth as seen during the last two years.

Committed liquefaction capacity contracts, globally close to 320Mtpa, is estimated to exceed current production by around 24Mtpa; however, a part of the delivered volume is going into reseller portfolios of major IOCs and traders, creating much of the volumes into the spot market.  This not only includes traders and majors, such as ExxonMobil, Shell, Chevron, Qatar Petroleum, Total, BP, ConocoPhillips, Petronas, Vitol, Glencore, Petronet and Trafigura, but also end-users such as Osaka gas who resells around 1Mtpa per year of LNG. In a growing sign of the trend, Osaka Gas is planning to resell around 3Mtpa by 2020, now possible after a Japanese court ruled against destination clauses. 

The negative balance of contracted vs actual supply is offset by contract flexibility in ramp-up and other clauses.  But should a tightening of the remaining, uncommitted liquefaction capacity occur in the next 12 months, this could radically change the supply-demand condition in the short-term market. Overall, the hangover from delayed FIDs on most new projects has created a definitive ceiling for global liquefaction capacity between now and 2021, potentially exposing spot buyers to less favourable buying conditions.