Future trends not all rosy for LNG sellers and developers
Liquefied natural gas is in short supply, the tight market is expected to continue for two or three more years, and new Russian LNG production planned to come online during that time could be delayed by Western sanctions.
It’s all driving up prices, while more buyers are signing contracts to lock in supplies.
That’s good news for sellers and export project developers.
The market is so tight that global demand is forecast to exceed supply by 26 million tonnes this year — the equivalent of two good-sized LNG export projects — Oslo-based research firm Rystad Energy reported last month.
But a lot more supply is on the way for the mid- and late 2020s. However, construction costs for those new export terminals are rising, adding stress to investment decisions. Meanwhile, competition is fierce for the long-term sales contracts that suppliers need to underpin multibillion-dollar project financing. All not such good news for LNG project developers.
Adding to the downside, a trio of market analysis firms expect China’s LNG imports to fall by as much as 19% this year from 2021, the first sizable drop since the country started buying the fuel in 2006. The forecast was attributed last month to U.S.-based S&P Global Commodity Insights, U.K.-based Wood Mackenzie and SIA Energy, a Beijing-based oil and gas consulting business.
That’s particularly glum news for LNG project developers, such as Alaska, looking to sell into what some had predicted would be a never-ending growth market.
China’s import volumes for the first four months of the year already are down 18% from a year ago, according to data from Refinitiv, a U.S./U.K.-based market data provider.
COVID-19 lockdowns have cut deeply into China’s industrial demand for the fuel. In addition, an increase in domestic gas production and higher volumes of pipeline gas imports from Russia, along with a softening economy, appear to be weakening China’s demand for LNG imports in the longer term.
“I think demand destruction has become a major concern,” particularly at high prices for imported gas, said Jason Feer, global head of business intelligence at Poten & Partners, an international advisory firm on oil, gas and shipping markets.
“We believe that a lot of the Chinese demand that has been lost this year has been lost permanently,” Feer said in a May 25 webinar.
The Chinese government is focused on dialing back energy costs amid a weaker economy, which is providing a boost to coal and a hit to gas imports, according to Lu Xiao, an analyst at S&P Global Commodity Insights, as reported by Reuters on May 26.
China’s imports of pipeline gas from Russia, through the Power of Siberia line, continue to grow after the pipeline started operations in 2019, with full capacity of more than 3.6 billion cubic feet per day planned by 2025. That would equal more than 10% of China’s total gas consumption last year.
Domestic gas consumption in China is up more than 6% in the first four months of the year, to about double what it was 10 years ago.
Even if China disappoints on LNG imports growth, increasing demand from European nations will help project developers, as Europe pulls away from Russian gas supplies and builds new LNG import terminals to source their gas from overseas suppliers. But even that presents a challenge for developers. European customers tend to favor shorter-term contracts than the traditional 20-year deals in Asia.
For example, Germany, which has no LNG import facilities but is rushing ahead with $3 billion in government assistance to lease four floating receiving and storage units, is reluctant to sign the 20-year supply contracts that QatarEnergy is offering.
The same hesitancy exists across Europe, particularly as utilities work toward the European Union’s goals to reduce greenhouse gas emissions from fossil fuels and transition to more renewables.
“Utilities are not convinced that they will be able to sell LNG in Europe 20 years from now,” Feer said, calling long-term gas supply contracts “a huge liability to put on the books.”
“A handful of European buyers are only willing to commit to 10 years, while QatarEnergy prefers a contract duration of at least 15 or 20 years,” Poten & Partners reported in a recent world markets newsletter.
Another disagreement is over the price index for LNG contracts. Qatar prefers to sell LNG linked to the cost of a barrel of crude oil, which is the traditional index on long-term sales to Japan and other Asia buyers. European customers prefer a rate tied to benchmark natural gas prices on the continent.
It’s a future guessing game as to which is a better deal for suppliers and buyers.
European gas prices crashed to a record low of $1.20 per million Btu in May 2020, at the worst of COVID’s demand destruction, but accelerated to record highs in the $50s this past winter for spot-market LNG sales. Oil-linked pricing on long-term LNG contracts has held within a much narrower band, generally $6 to $13 in the past couple of years.
Qatar, which vies with the United States and Australia for the title of world’s largest LNG producer, is undertaking a $30 billion capacity expansion project to boost production by 40%. The increased output is scheduled to start ramping up in 2026.
A second phase, at an additional $20 billion, could add even more liquefaction and export capacity, raising Qatar’s nameplate production to 126 million tonnes per year, about 25% above current U.S. LNG output.
U.S. developers, however, are not resting after moving the nation from zero LNG exports in January 2016 to take over the world’s top spot this spring.
A couple more export facilities are under construction on the U.S. Gulf Coast, both expected to start operations by late 2024 or early 2025, bringing to nine the number of terminals on the Gulf and Atlantic coasts. More capacity is expected to follow as at least two more ventures are moving toward final investment decisions and several existing terminals are looking at possible expansions.
One problem, however, is rising costs for labor, equipment and the expensive production modules that go into building LNG facilities.
“U.S. projects are facing significantly higher costs,” Feer said in the webinar.
Reuters reported a month ago that materials prices have shot up 20% in the past two years while gas compressors are 30% more expensive. That means developers either will have to pass on higher costs to buyers, accept lower rates of return on their investments, or find contractors willing to absorb the risk of construction cost escalation.
“The race to the bottom (for liquefaction costs) in the U.S. is really winding down,” Feer said. While in the past couple of years some developers were offering to accept contracts to liquefy gas at $1.80 to $1.90 per million Btu (plus the price of feed gas), higher construction, capital and financing costs are driving the liquefaction rates up over $2, “sometimes significantly so,” he said.