IEEFA: New U.S. LNG export projects face quartet of stiff headwinds

June 7, 2021 (IEEFA)—Like many businesses, the U.S. liquefied natural gas (LNG) industry spent most of 2020 in a state of financial quarantine. As COVID-19 spread through gas-importing nations in Europe and Asia, global LNG demand fell, prices plummeted—and major U.S. liquefaction facilities stood mostly idle for the summer, their capacity neither needed nor wanted. Even though federal regulators have granted permits to 16 new LNG export projects, not a single one has completed financing in almost two years.

Yet we’re now hearing speculation about a new round of U.S. LNG construction. Global LNG prices spiked to multi-year highs during last winter’s Asian cold snap, rekindling optimism. Prices remain well above last year’s lows, and U.S. LNG plants operated at nearly full capacity for much of the spring. Now, say the boosters, all the new projects need is some firm commitments from long-term buyers, and they’re off to the races.

Exhibit A is Tellurian, Inc., which recently secured 10-year purchase commitments from two trading houses for its proposed Driftwood LNG plant in Louisiana. Time will tell whether these contracts will attract the financing needed to get the project off the ground. In the past, lenders demanded longer-term contracts with guaranteed liquefaction fees, rather than Driftwood’s shorter-term agreements tied to volatile international price indexes.  

But before they can secure the types of stable, blue-chip contracts that lenders prefer, new LNG projects will have to navigate four troublesome market headwinds that are weakening the industry’s momentum.

EXISTING EXPORTERS HAVE SPARE LNG TO SELL. In the U.S. alone, more than 17 million metric tons per year (MTPA) of LNG may be sold on spot markets or through short-term contracts, rather than long-term commitments. Shell has no dedicated customers lined up for the 2.4 MPTA of liquefaction capacity it buys from the Elba Island facility in Georgia. BP purchases 4.4 MTPA from Freeport LNG in Texas, again with no dedicated end buyers. The list goes on. 

The situation will worsen when ExxonMobil and Qatar Petroleum finish the Golden Pass LNG plant in Louisiana, with 18 MTPA looking for buyers. It will get worse again when Shell and its partners complete the first phase of the LNG Canada project, with 14 MPTA in capacity but less than 4 MTPA in firm contracts.

To lock in customers, new projects will have to compete against these existing suppliers. It’s not a fair fight: Why would a buyer commit to a project that’s still on the drawing board when there’s plenty of spare capacity already up and running? Suppliers are thinking the same way: Cheniere Energy plans to sell as much as 7 MTPA of uncontracted capacity from its existing plants before it invests in new ones.

COSTS ARE ON THE RISE. When U.S. gas costs $2.50 per million British thermal units (MMBTU) and shipping costs are low, U.S. LNG can break even in Asia at about $7 per MMBTU. But every extra penny for gas feedstocks or transportation makes it one penny more difficult for U.S. exporters to compete. 

Rising costs have already started to weaken the industry’s prospects. Natural gas prices are now above $3/MMBTU, up more than a dollar from last year. Shipping costs are higher than last year as well, making it harder for the U.S. to compete with Australian, Russian, and Qatari exports that benefit from shorter trips to Asia. Recent price increases for steel, labor, and other construction expenses could drive up capital costs, making it harder for new U.S. LNG projects to offer price breaks. To top it off, construction firms that build LNG plants have been burned by delays and cost overruns, and hope to shift costs and risks back to the project owners.

While it’s too soon to say that higher costs are here to stay, there’s little sign of a return to last year’s lows. U.S. gas drilling remains subdued, and low output is boosting prices as the nation emerges from the pandemic. Besides, LNG plants already consume about one-tenth of the nation’s gas, and new plants will add to the demand—which could lift feedstock prices, making it harder for U.S. exports to compete.

INTERNATIONAL DEMAND REMAINS FICKLE. A growing global gas market once seemed like a sure bet. With gas seen in both Europe and Asia as a cleaner alternative to coal, many analysts saw nothing but blue skies for U.S. LNG.

Europe was the first to crack. With climate concerns rising throughout the continent and an aggressive new EU climate law on the books, all fossil fuels have become suspect. That’s bad news for U.S. gas, which has earned a particularly grim climate reputation due to methane flaring and venting in the shale industry. Last November, French energy giant Engie, under pressure from the French government, cancelled a 2 MTPA deal with NextDecade’s Rio Grande LNG project over rising concerns about the fuel’s climate impact. The climate imperative has even found its way into the halls of finance, with the president of the European Investment Bank flatly declaring: “To put it mildly, gas is over.” (This declaration, of course, ignores the new pipeline gas poised to flood European markets—yet another headwind for U.S. LNG imports.)

Even in Asia, long-term LNG demand growth is far from certain. The International Gas Union’s 2020 LNG report found that Japan and South Korea—the globe’s largest and third-largest LNG consumers, respectively—trimmed imports even before the coronavirus hit. In China, major gas utilities have been losing money on LNG, and will likely require guaranteed, low-price contracts—as well as Beijing’s approval—before they commit to new U.S. supplies. Meanwhile, in the energy growth markets of India and Southeast Asia, building up LNG demand from scratch will require a slow and complex dance among governments, capital markets, and global LNG developers. Financing and building all of the necessary infrastructure, from terminals to pipelines to power plants, could take years—a stark contrast to the go-go mentality that fuels the U.S. LNG industry’s market ambitions.

QATAR IS BREATHING DOWN EVERYONE’S NECK. Anyone who follows international gas markets understands that Qatar is both the ringmaster and strongman in the global LNG circus. Qatar’s LNG industry can thrive at prices that would break the bank for virtually every other producer. And the country has pledged to enlarge its LNG footprint by nearly two-thirds—or an additional 49 MTPA—by 2027, as it moves forward with its mammoth North Field and Ras Laffan Industrial City expansions.

Qatar’s growth plans, coupled with recent price cuts, signal that it is engaged in a volume play: It plans to make money by selling lots of gas for low prices, locking in long-term market share as it scares other players off the field. Investors recognize that Qatar’s low-cost, high-volume strategy radically increases the financial risks for every other player in the market, undermining confidence in U.S. LNG and throttling inflows of capital. 

U.S. LNG PROJECTS MUST OVERCOME ALL OF THESE HEADWINDS before they can lock in long-term sales contracts with creditworthy buyers. Lenders don’t want to risk the capital to build a multi-billion-dollar LNG plant and simply wait for the customers to come. They demand more certainty about their market. But while global LNG is relatively abundant right now, certainty remains in short supply. Until that situation reverses, we expect the rebound hype for U.S. LNG to exceed the reality.

Clark Williams-Derry ([email protected]) is an IEEFA energy finance analyst.

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