Buyers happy to pay above variable cost for US LNG

Friday, 01 June 2018

In contradiction to the narrative of a supply glut, global natural gas prices rallied strongly in the latter half of last year. February 2018 forward prices reached $9.90/mmBtu in December, a 80% jump from $5.50/mmBtu seen during the summer period. 

Commenting on this phenomenon, S&P analysts led by Aneesh Prabhu in New York and Simon Redmond in London said “despite the strong growth in LNG supply in 2016 and 2017, global markets absorbed the available supply.”

China absorbs much of the oversupply

Demand is dominated by Asian markets whereby China along with new markets like India, Bangladesh and Pakistan accounts for 67% of the demand increase seen last year. China’s gas demand alone jumped by 12 million tons, or 40%, in 2017 fueled by the country’s push to use more gas in power generation to improve air quality in its major cities.

In 2018, strong demand from China continues but roughly half of the global LNG growth to absorb the excess supply comes from temporary factors like fuel-switching in Europe, given that utilities have sufficient spare regasification capacity and are fully exposed to spot prices of coal and gas. But Europe cannot balance global gas markets alone. Hub prices at the UK’s National Balancing Point (NBP) have increased above short-run marginal costs, according to S&P figures, but they are still not consistently above full-cycle cost of U.S. LNG.

Spot markets conditions are forecast to stay “well-supplied” at least through the next three to four years and it appears LNG seller needs China to balance global gas markets. The country is expected to become the “swing consumer” and one of the largest LNG importers once it seeks to meet the Paris Agreement decarbonisation targets towards the latter part of the 2020s.

Underused capacities during off-peak

On the supply side, analysts see more LNG output coming to the market than is needed globally even though demand is growing at 6% to 7.5% annually through to 2020.

“Given that eastern Australian and U.S. capacities have the highest production costs, we expect to see some of this capacity to be underused during off shoulder (non-peak weather) months when spot prices dipped below their short-run marginal costs of production,” Mr Prabhu and Mr Redmond stated in the report.

East Coast Australian projects often underestimated their price sensitivity to the oil price, which together with some resources issues and the implementation of the Austrian Domestic Gas Security Mechanism in October 2017, has rendered projects “rather expensive.”

Built at a cost exceeding $1,250/ton, the average Australian project is considerably more costly than the $750-$800/ton for a U.S. greenfield liquefaction project. Delivered cash costs to Asia is about $2.25-$2.50/mmBtu from Qatar and $5.25-$5.50/mmBtu from the U.S. Gulf Coast, according to S&P estimates.

Returns on Australian LNG projects overall are unlikely to live up to their pre-FID expectations due to cost overruns and lower oil prices. Hence S&P analysts say “we should expect Western Australian and Northern territories projects focus on debottlenecking and also efficiency gains and cost reductions, to maximise production and excess wellhead capacities.”