U.S. liquefied natural gas (LNG) exports will likely reach capacity of roughly 10 Bcf/d by the winter after dropping to about 30% of capacity in July because of the demand devastation caused by Covid-19, analysts told NGI this week.
Some analysts see capacity ramping through the end of the year, while others expect a sharp uptick as soon as next month.
“We’ve gone through the worst of it,” said Wood Mackenzie’s Alex Munton, principal analyst for Americas LNG. “I think clearly in terms of customers of U.S. LNG canceling cargoes because of the economics being unviable, that situation has changed.”
Asian and European gas prices were close to parity with U.S. gas prices for much of the summer, in the range of about $1.50-$2.00/MMBtu, he said. That caused long-term U.S. LNG customers to frequently cancel cargo loadings. About 165 U.S. cargoes have been canceled through September and about 35 are likely to be canceled in the fourth quarter, Flex LNG Ltd. CEO Oystein Kalleklev said last month. A typical cargo is equivalent to about 3.5 Bcf.
With gas demand growing as the world recovers from the Covid-19 pandemic, the October New York Mercantile Exchange gas futures contract settled Tuesday at $2.527/MMBtu, while Asian spot LNG prices for October delivery are currently at about $4.50/MMBtu, Munton said.
European or Asian gas prices typically need to be at least $1/MMBtu higher than U.S. gas prices for the economics of American LNG exports to work and “we are seeing that now,” Munton said, adding that European gas prices have also increased recently. He expects U.S. LNG exports to reach capacity in November or December.
U.S. LNG customers must be able to at least recover their “cash cost,” which comprises feed gas, fuel gas, pipeline transportation and shipping, to export U.S. supplies, he said. The customers don’t need to recover their respective liquefaction fees in the range of $2.25-$3.00/MMBtu because they must pay those fees whether they take LNG or not, so they are sunk costs.
NGI calculations show U.S. LNG being profitable again next month in both Europe and Asia for offtakers with vessels chartered and those who would need to charter a vessel.
The maximum Gulf Coast LNG netback price for October delivery on Tuesday between the Dutch Title Transfer Facility, Japan Korea Marker and National Balancing Point was $3.286/MMBtu, or about 76 cents higher than where Henry Hub futures settled. NGI calculations on Tuesday also showed the netback climbing to $4.665 in December, or $1.399 above Henry Hub.
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With the improving price spreads, shipbroker Poten & Partners expects “to see pretty significant growth” in U.S. LNG exports this month and full output in October, said Jason Feer, global head of business intelligence. For example, the Freeport LNG terminal in Texas is scheduled to load 10 cargoes in September and 17 in October, which would be close to capacity, he added.
“Mostly the drivers are seasonal increases in demand as importers prepare for colder weather, which essentially balances the market during winter, and traders and other market participants position themselves to take advantage of higher prices,” Feer said.
Poten & Partners was “a bit surprised” that 24 LNG sales contracts for a total of 24 million tons were signed in the first half of the year as buyers wanted to lock in historically low prices.
“Some of that urgency remains for buyers as pricing has fallen to the low 11% of Brent range for new contracts, and historically speaking, that is a very attractive price,” Feer said. “However, there is a lot of legacy volume, or volume from expired long-term contracts, so a lot of buyers prefer to sign shorter deals with those producers because it tends to be cheaper.”
Two Louisiana LNG facilities that were shut by Hurricane Laura, Sabine Pass and Cameron, must come back online for U.S. output to reach capacity. The hurricane made landfall on August 27 near Lake Charles, Louisiana, with winds of 150 mph. Both facilities remain offline and when exactly they’ll restart remains unclear.
U.S. LNG exports in July dropped to an average of 3.1 Bcf/d after peaking in January at what was then capacity of 8.0 Bcf/d, the Energy Information Administration said last month.
Feed gas levels increased to an average of 4.33 Bcf/d in August, according to Genscape Inc., but dropped to less than 3 Bcf/d this week because of the shutdowns at Sabine Pass and Cameron.
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