Liquid Assets

Thanks to the fracking revolution, Texas is awash in so much natural gas that we’re gearing up to export it to other countries. Should Vladimir Putin be worried?

June 2014By Comments

An aerial view of the Sabine Pass Liquefaction Project, located in southwestern Cameron Parish along the Louisiana Gulf Coast.
Monsour's Photography

Four years ago, things looked bleak for Houston’s Cheniere Energy. It had about $3 billion in debt, its stock price had plunged from more than $40 to less than $1 in a year’s time, and bankruptcy seemed imminent. Cheniere had made one of the biggest wrong-way bets in the history of natural gas, a commodity that is the poster child for wrong-way bets. With America’s natural gas supplies growing thin, Cheniere built a massive terminal in Sabine Pass, just across the border in Louisiana, to import liquefied natural gas (LNG). But by the time it completed the project, the hydraulic fracturing boom had changed everything. U.S. gas production was soaring. The idea of importing the stuff suddenly looked like a Texas twist on the British idiom of carrying coals to Newcastle.

Cheniere’s response: take advantage of the fracking boom by betting billions more on revamping its terminal and sending the gas the other way—which turned out to be a right-way bet. In May 2011 Cheniere became the first company in the country to get a permit from the Department of Energy to export LNG to countries in Asia. More precisely, Cheniere’s customers will bring natural gas to the Sabine Pass facility, which Cheniere will turn into LNG and pump onto customers’ ships that are bound for overseas markets.

Cheniere isn’t alone. Freeport LNG, also based in Houston, has been on the same roller coaster. It too got burned by investing a billion dollars in an import facility, on Quintana Island, just down the coast from Galveston. Last year Freeport got approval to export LNG to nations that haven’t signed Free Trade Agreements  with the U.S. (The DOE usually fast-tracks approval for exports to countries that have trade agreements with us, but many of them don’t need the gas. Japan and Europe, which don’t have FTAs, are among the most lucrative LNG markets.) Next month, Freeport expects to receive approval to convert its terminal to handle those exports. It already has contracts in place that will last for the next twenty years. 

Other companies are racing to catch up. “Freeport and Cheniere are the first in this wave of construction that we know is going to happen on the Gulf Coast,” says David Pursell, managing director with Tudor, Pickering, Holt & Co., an energy investment bank in Houston. The federal government has already approved five more permits for export terminals serving non-FTA markets. 

The scramble to build such facilities is a multibillion-dollar game of musical chairs. If all the current applicants were to complete the projects they propose—there are around 25 of them—the combined export capacity would be almost 36 billion cubic feet of gas a day, which is much more than the market can bear. “There is absolutely zero chance that all those terminals get built,” Freeport chairman and CEO Michael Smith says. “There aren’t that many quality customers to base long-term financing on.” With the exception of a few of the biggest oil companies, most permit applicants will have to borrow the billions they need to develop facilities. Lenders require applicants to show proof of long-term contracts from buyers with the financial resources to back them up—major global companies like Toshiba or BP. Smith says that a more realistic level of exports would be about 15 billion cubic feet a day—less than half of what’s been applied for. And we aren’t likely to hit even that level before 2022, at the earliest.

You wouldn’t know that, though, from listening to the breathless discussion of exports going on in Congress. Lawmakers have been urging the Obama administration to expedite permits in hopes of using U.S. exports to weaken Russia’s strong position in European energy markets. “Increased exports of American gas could cut Vladimir Putin off at the knees and increase American power,” Congressman Pete Olson, a Republican from Sugar Land, said in an op-ed for the political website The Hill. Russia currently supplies about 30 percent of Europe’s gas. Imports from the U.S. could shield Europe from repercussions if Russia decided to curtail the supply of gas to the continent in response to sanctions over its incursion into Ukraine. 

Cheniere, though, won’t begin exports for more than a year, and Freeport a few years after that. And both have contracts to send much of the gas they are handling to Asia, not Europe. Everyone else will be even farther behind, so the U.S. won’t be providing energy relief to Europe any time soon. 

While Europe could use an alternative supplier, Asia—Japan especially—is a far more attractive market for U.S. exporters. In the wake of the 2011 Fukushima Daiishi nuclear accident, Japan shuttered its nuclear power plants and turned to gas for generating electricity. Demand for LNG imports—the country has no domestic gas deposits—surged 30 percent, and prices almost doubled. 

At the same time, prices in the U.S. were tumbling thanks to a glut of production brought on by fracking. In Japan the average price for gas this year is about $16.50 per thousand cubic feet; in the U.S., an exporter can purchase gas for around $4.50. The trick is to get it from here to there to take advantage of that difference. In its natural state, gas must be transported by pipeline. Shipping it overseas requires transforming it into a liquid by cooling it to minus 260 degrees Fahrenheit, then pumping it into specially insulated tankers. The process is expensive. Freeport charges its customers about $3.50 per thousand cubic feet to cool the gas and transfer it to tankers. Factor in shipping costs of another $3 per thousand cubic feet or so and Freeport’s customers will have spent about $11 per thousand cubic feet of LNG by the time they get it to Japan—leaving a margin of about $5. Even though the liquefaction and shipping more than double the cost of the gas, companies can still make more by selling it in Asia than they can by selling it in the U.S. 

In Europe the numbers aren’t quite as compelling. Gas is selling for about $11.50 per thousand cubic feet, and the cost for U.S. exporters to get it there would be about $10.50, Smith estimates. That doesn’t leave a lot of room for market upheavals, which are surely on the near horizon. With the U.S. embracing exports, gas is becoming an increasingly competitive global market. Qatar, currently the world’s biggest LNG exporter, has said it plans to boost exports to Europe by 22 percent this year. And new reservoirs are being tapped around the world. Australia, for example, is increasing LNG exports, and several African countries are working on plans for terminals as well. Houston’s Noble Energy discovered a major gas field off the coast of Israel in 2009, and the country is now making plans to export gas. Nearby Cyprus is developing an export facility with plans to ship Israel’s gas to Europe. The island nation also hopes that the Israeli field may extend into its own waters, enabling it to join the ranks of new producers.  

Many of these projects are a long way off. Without infrastructure, facilities, or even policies governing exports, it could be well into the next decade before some of them get off the ground, says Kenneth Medlock, the senior director of the Center for Energy Studies at Rice University’s James A. Baker III Institute for Public Policy. So America is where the next big expansion is set to take place. “There’s a race to be the first LNG exporter from the U.S. to capture part of the global market,” Medlock says. 

While Texas has an edge, hurdles for a viable export business still loom. A lack of pipelines makes it difficult to get gas from drilling sites to export facilities. In North Dakota’s Bakken Shale, for example, producers are concentrating on oil because it commands a high price and can be shipped by railcar. Gas is treated as an unwanted by-product and burned off at the wellhead in a process known as flaring. Flaring is also common in South Texas’s Eagle Ford Shale for much the same reason; as a result, gas that could fetch a premium in Japan is simply being wasted. 

The biggest threat to exports, though, is opposition from manufacturers and chemical companies who fear that exporting gas would cause prices at home to rise. The Gulf Coast, with its high concentration of petrochemical plants, is at the forefront of this debate. Petrochemical companies, such as Dow and LyondellBasell, have expanded their Texas operations in recent years, capitalizing on cheap gas not only as fuel for their factories but also as the key raw material, or “feedstock,” for making plastic resins and other products. In the early 2000’s, when it appeared that U.S. gas prices would keep rising, many chemical companies shifted operations to places like the Middle East, where gas was cheaper. Now the operations have shifted back, and companies are expected to add more than 46,000 jobs and spend about $72 billion on capital investments by 2020, according to the American Chemistry Council. 

The companies, however, warn that if gas prices rise, all that economic growth could evaporate as they once again look to other countries for cheaper feedstock. “Sending large volumes of American natural gas abroad will raise consumer energy prices, discourage manufacturing investment, and impede economic growth and job creation,” Dow chairman Andrew Liveris said in November. Ironically, Dow invested in the Freeport when it was building an import facility and maintains its interest in the company, though it has no active involvement in the export project.

Smith dismisses Dow’s concerns. “There is just a ton of gas in the United States,” he says. “We do not understand why Dow and other manufacturers who rely on ethane, propane, and butane are even arguing.” Smith and Medlock both say that while exporting gas may cause a slight rise in energy prices, it will also encourage more drilling. And as more gas is produced, it will be stripped of more liquids that are used to create more feedstock, likely decreasing the costs for Dow and other chemical makers. What’s more, if U.S. exports help lower gas prices in other parts of the world, global companies like Dow could benefit. “The biggest price impacts will be abroad,” Medlock says. “If the price in Asia falls by five dollars and here it goes up fifty cents, then that benefits manufacturers who have plants abroad.” Nevertheless, the threat of higher prices and potential economic consequences has provided fodder for lawmakers such as Democratic congressman Henry Waxman, of California, who has opposed efforts to expedite the pending export applications. 

While it’s unlikely the opposition to exporting LNG will prevail, it could slow down the process enough to give an advantage to the companies that are already at the front of the line. Cheniere, whose stock now trades at around $55, is signing contracts to supply LNG from a second terminal to be built in Corpus Christi. Its permit application is pending. Freeport’s Smith owns another company, Gulf Coast LNG, which is planning an export terminal for Brownsville, and its permit is fifth in line. “I fully intend to develop that project,” he says. He’s already been left standing once by natural gas’s shifting fortunes. This time he’s making sure his seat is secure before the music stops. 

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