Until the end of 2014, it used to be common wisdom that a premium on Asia-bound cargos was a long-term structural feature of the global LNG market. In fact, LNG oil-linked prices surged during the past three years of high crude prices and burgeoning final demand in East Asia. Spot cargos followed a similar price trend, too.
At the same time, prices in North America and Europe constantly remained on a lower level (Figure 1). In the former case, due to the supply effects of shale boom, while in the latter case due to a shrinking final demand.
Different basins – Atlantic and Pacific ones – and different price trends appeared to be an inevitable long-term situation, driving away marginal cargos from the European terminals, attracting investments in Asian and Oceanian upstream and increasing the centrality of Asian customers at global level.
However, since the third quarter of 2014, plummeting oil prices and weaker-than-expected demand growth have changed dramatically price trends in the Pacific basin: spot prices immediately decreased, while oil-indexed, long-term contracts experienced a gentler but clear downward trend during the third quarter of 2014, due to the delay embedded in their price formula.
Figure 1 – Natural gas prices.
Asia LNG long term proxy is based on the formula 14,75% JCC (3 months average) + 0,5. JCC: Japanese Crude Cocktail. NBP: National Balancing Point. HH: Henry Hub. WTI: Western Texas Intermediate. Source: elaboration on BG, European Commission, EEX, EIA, Platts, Thomson Reuters.
Unlike piped gas, LNG provides a certain degree of flexibility, driven by price signals. During the last few years, as mentioned, Asian premium attracted part of the export originally intended to supply European customers. However, competition for spot cargos has decreased since the beginning of 2015, as the narrowing of Asia-Europe differential began to reduce the attractiveness of Asian market, considering that the shipping cost from North-western Europe to Asia is approximately $1.75/MMBtu.
Spot transactions account for 29% of the global market, according to GIIGNL, but their share is expected to increase in the future, as liquid markets will emerge at regional level, especially in the Pacific, where more than three quarters of the global LNG demand is located (Figure 2). Arbitrage opportunities between regional markets will be influenced by the differential between spot prices: if Asian and European prices remain as close as they became in early 2015, regional markets will remain largely isolated in their supply dynamics.
Figure 2 – Regional LNG markets.
Source: elaboration on GIIGNL(2007-2015).
Oil price may well quickly recover in the next few years, but a second factor is bound to influence price dynamics in the Asian Basin (and beyond): structural oversupply. According to IEA’s Gas medium-term market report 2015, liquefaction capacity is expected to increase by 44% by 2020 to 575 Gmc/y. Indeed, the equivalent of 176 Bmc/y are already under construction around the world. The core of this new capacity will be located in Australia (73 Bcm/y) and the US (66 Bcm/y) (Figure 3).
Figure 3 – LNG regasification, existing and under construction.
Source: elaboration on IEA.
Australian LNG export are mainly oil-indexed, but Asian buyers have review clauses in their contracts after a five or six-year time span. This implies that we might see major changes at the beginning of the next decade, according to the market situation of the moment and the workability of the emerging gas hubs at regional level. In the case of high oil prices and plentiful supply (in China, also via pipeline), gas-to-gas competition may spread significantly in the Asian market, pushing down average price.
Australian production, nonetheless, is bound to remain mainly in the Pacific Basin due to geographical proximity, but the case of US exports is quite different. Liquefaction plants are located in the East and Gulf coasts: LNG cargos have to cross the Panama Channel and the Pacific before reaching Eastern Asian customers, with shipping costs of up to 3 $/MMBtu. Shipping costs for the US to Europe are instead expected to be lower, approximately 2 $/MMBtu: a negligible difference while Asian price premium over Europe was 5 $/MMBtu, but a potentially relevant swing factor in the future, when Australian gas will supply massively the Pacific Basin.
In other words, even with a consistent but low Asia price premium, US exporters may end up by preferring a delivery to their Atlantic customers rather than supplying Asian customers, now unwilling to pay a premium high enough to allow for a profit. Thus, a converging price trend may end up by keeping Atlantic and Pacific basins only loosely connected by physical flows in the medium term.
This outcome would be the consequence of purely economic dynamics, but it would have a politically relevant impact on Europe. In fact, this mix of oversupply in the Pacific markets and low oil prices affecting long-term contracts may provide an unexpected plausibility to the essentially rhetorical idea of supplying sizeable quantities of American gas to the European customers.
This would not eliminate European dependence on Russian gas, but it could increase the competitiveness of the EU gas market, at least in North-western Europe. The impact on Southern and Eastern EU countries will instead depend on the improvement of the interconnections between national grids. As usual, external opportunities require internal action to be fully grasped.