‘America Third’ to turn down LNG supply
US liquefaction plants are typically cited as the first to turn down if the global LNG markets cannot absorb supply
Global LNG markets will struggle more in 2020 than in 2019 to absorb the scheduled increases in liquefaction. Asian import growth is slowing because of insufficient infrastructure to unlock new demand and macroeconomic headwinds checking industrial consumption. This inability of Asian markets to absorb the final stages of the current global LNG export expansion—85mn t/yr in 2016-20—will push more supply towards other markets. We see the Latin America and the Middle East markets further reducing their takes next year, leaving some 16mn t more LNG year-on-year headed towards European terminals.
But Europe already used all of its balancing tricks in 2019—coal-to-gas fuel switching in the power sector, using all available storage capacity, and nominating down pipeline imports. Europe will therefore struggle to take more LNG next year unless there is a major disruption in pipeline supply.
On 30 December, Russia and Ukraine struck a gas transit deal to avoid stoppage of energy supplies to Europe. The continent already has little room for much more LNG in 2020 than in 2019. So, what happens if Europe—the world’s balancing market—stops being able to balance?
The conventional wisdom is that US liquefaction plants represent the stop valve. The argument goes that the colossal internal US gas market can reabsorb the gas if offtakers opt not to load cargoes at the country’s liquefaction plants because of limited options to sell them on global LNG markets.
The trouble is that, as liquefaction grows, it represents an increasing share of the US market. Daily supply of 7.5bn ft³/d (212mn m³/d) to the six liquefaction projects online in early November is 6-10pc of US demand, depending on the time of year. If offtakers reject a substantial share of their cargoes and that supply is offered back on the Henry Hub, it could immediately push feedgas costs low enough to re-open the export arbitrage.
No US offtaker would want to be the first mover in rejecting cargoes
The likelihood of substantial cargo rejection reopening the export arbitrage is further increased by the limited storage space available to accommodate feedgas being turned away from export plants. Storage infrastructure in the US South Central region, adjacent to Gulf Coast export plants, equates to c.1.35tn ft³ (38bn m³) of working gas capacity—31pc of the US total. But burgeoning domestic output is already pushing its inventories to multi-year highs. The equivalent of a full liquefaction train halt—in addition to the shutdowns we expect as part of regular maintenance—could quickly use up the free storage space during low consumption periods, crushing US prices.
US exporter Cheniere argues that no offtaker would want to be the first mover in rejecting cargoes, as this would only make it easier for the offtaker’s competitors to continue taking US LNG. Cheniere contracts stipulate that offtakers, even at late notice, only have to pay the liquefaction fee plus the difference between the contract price for the gas and what Cheniere can make through a mitigation sale.
That mitigation sale can be to the US gas market, but it can also be to another offtaker or Cheniere can sell the cargo itself, maintaining exports out of US facilities even when the cargo is initially rejected.
Curve shape key
A strong contango—i.e. future prices higher than current—structure in global LNG markets, which we expect in the second half of 2020, also provides resistance to turning down US exports. Large US offtakers have built up their LNG fleets to handle the variable needs for shipping capacity associated with most US exports having no fixed destination.
When the US netbacks from JKM and TTF front-month markets dropped below feedgas costs to export facilities in late summer 2019, there was still an export arbitrage if firms sold these cargoes on further-dated markets. Large offtakers therefore used their ample shipping capacity in the second half of the year to continue loading US cargoes and held them as floating storage.
Admittedly, the backwardation, or future prices lower than current, in the curve early in 2020 removes the incentive to load cargoes for later sale. Global demand then must be high enough to accommodate the immediate sale of US supply or there is a risk of some cargo rejection in winter 2019-20. One cargo was already rejected from Cameron LNG in November—with Singapore’s Pavilion Energy opting to pay for the LNG without taking delivery. But winter demand should still keep most US exports flowing.
Although this US cargo was rejected, this was not the first reduction in exports from a liquefaction facility for commercial reasons. Indonesian exporter Donggi Senoro chose earlier in 2019 to turn down spot exports because of the low-price environment. Egypt’s Egas, which buys gas at a guaranteed domestic price, similarly chose to cut exports because it was no longer profitable to sell the LNG on global spot markets.
So, while the US may play a role in balancing the LNG market next year, it will be at least third—after Egypt and Indonesia—to turn down supply. Any rebalancing in 2020 may therefore need to be more of a collective effort.
James Waddell, Senior Global Gas Analyst, Energy Aspects
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