Correction: An earlier version of this article misstated the location of an Exxon Mobil project to produce liquefied natural gas. It is in Papua New Guinea, not Sri Lanka. This version has been corrected.
COVE POINT, Md. — A vast dock stands a mile offshore here, its concrete legs planted in the water and its steel tentacles poised to suck natural gas in a liquid state from special refrigerated tankers up to a thousand feet long.
But on a recent clear fall afternoon, there wasn’t a tanker in sight. Inside a control room, operator Ron Keraga watched computer monitors that did not blink. The only flurry came from the sea gulls, which perched on the railings outside and then left a white trail behind them.
“Like any job, there’s going to be some downtime,” Keraga said.
In this case, a lot of downtime. Dominion Resources’ Cove Point terminal, originally designed in the 1970s, can import liquefied natural gas — or LNG — from up to 220 tankers a year. But this year only one tanker has unloaded here, back in May.
That’s because the international trade in natural gas — and the rest of the energy business — has been turned upside down. It’s as startling as it would be if rivers decided to run upstream.
As recently as four years ago, energy experts agreed that the United States would need to import LNG to fill the gap between rising U.S. consumption of natural gas and stagnant or diminishing domestic supplies.
But U.S. supplies didn’t diminish or stagnate. Instead, oil and gas companies figured out how to combine horizontal drilling and hydraulic fracturing techniques to tap vast gas reserves trapped in layers of shale rock. And thanks to the surge in shale gas from deposits in places that include Pennsylvania, Texas and Louisiana, the United States is awash with cheap natural gas and could soon turn into a net exporter rather than a net importer.
Now Dominion Resources wants to reverse course. It is seeking permission from federal regulators to build $2 billion of new facilities so that it can export — rather than import — natural gas. Instead of taking liquid from tankers and warming it into natural gas for U.S. consumers, the company would cool and liquefy U.S. natural gas for shipment and sale abroad.
“There has been such a transformation,” said Sen. Ron Wyden (D-Ore.), the likely next chairman of the Senate Energy and Natural Resources Committee. “In my home state, until recently we were having pitched battles over whether to construct import facilities. Fishing folks against environmental folks against landowners. High-decibel stuff. And virtually overnight, we’re not going to have import facilities but export facilities.”
As U.S. supplies have surged, U.S. prices have slumped. Suddenly, producing companies are looking for ways to sell gas abroad, where prices are three to five times as high. And customers are lining up. Japan’s Sumitomo and another Asian buyer have signed long-term agreements to buy LNG from Cove Point; those contracts include guarantees that enable Dominion to line up financing. In Japan, gas prices have run as high as $16 for a thousand cubic feet; in the United States, prices are currently about $3.70. Even after adjusting for the costs of liquefaction and shipping, it’s a good deal for customers like Japan.
“This is a win-win for many people,” said Donald R. Raikes, vice president of marketing for Dominion. “The gas industry is in search of markets, and the price has been pushed down for lack of markets.”
“We have so much gas we don’t know what to do with it, and it’s unlikely that we can create enough demand for all the gas coming on stream,” said Cherif Souki, chief executive of Cheniere Energy, which is spending $10 billion to add LNG export capability to an idle import facility in Sabine Pass, La.
Cheniere has its permit, but Dominion is one of 15 companies that have applications pending at the Energy Department to build export facilities.
Not so fast, Wyden says. He wants to be sure gas exports don’t raise prices and hurt U.S. consumers and manufacturers.
Under current law, the Energy Department must decide whether an LNG gas export operation safeguards domestic needs and meets the public interest, especially for gas going to countries with which the United States does not have a free-trade agreement. Japan is one of those countries.
On Wednesday, the Energy Department released a long-awaited study, carried out by NERA Economic Consulting, that acknowledged exports would raise U.S. gas prices. But it said that in all of the scenarios it modeled, “LNG exports have net economic benefits in spite of higher domestic natural gas prices. This is exactly the outcome that economic theory describes when barriers to trade are removed.”
Natural gas liquefaction dates to the 19th century, and the first commercial plant was built in Cleveland in 1941. Natural gas becomes a liquid at minus 260 degrees Fahrenheit. Storing it as a liquid has great advantages; natural gas in its gaseous state takes up 600 times as much space as it does when a liquid.
In 1959, the first specialized LNG tanker — a converted World War II freighter — carried LNG from Lake Charles, La., to Britain. In 1964, Britain began importing LNG from Algeria. Five years later, the United States shipped LNG from Alaska’s Kenai Peninsula to Japan.
But until now, the U.S. focus has been on imports. Four LNG import terminals, including Cove Point, were built in the United States during the 1970s. Then imports fell because of the boomlet in domestic gas production following price deregulation. Importers also became locked in contract disputes with Algeria. Cove Point was mothballed.
It was bought by Dominion and reopened in 2003 as the United States started to import supplies from such places as Trinidad and Tobago. Today, Cove Point is the nation’s largest gas storage facility, with rows of spotless storage tanks, each built like a giant thermos bottle with four feet of insulation to keep the gas cold enough to stay in liquid form.
The unwieldy nature of LNG facilities — both costly and time-consuming to build — makes the global natural gas market a peculiar animal, different from markets in oil or commodities such as sugar. Those prices are international; natural gas prices are negotiated project by project. Long-term, fixed-price contracts, rather than fluctuating spot markets, help give exporting companies the certainty they need to get financing for facilities and the special refrigerated tankers needed to ship the gas.
Dominion Resources already has billions of dollars worth of tanks, boilers, pipelines and docks at Cove Point, so conversion to export is cheaper than starting from scratch. (There is a low-tech touch: a 1.2-mile-long, six-foot-wide underwater tunnel through which workers bicycle to get from shore to the receiving dock.)
Even so, by the time export terminals are finished, market conditions could be upended yet again. If private companies haven’t been good at figuring this out, will the Energy Department do any better at recognizing the tipping point at which exports will drive up U.S. prices to unacceptable levels?
That’s exactly what worries much of corporate America about LNG export plans. Energy experts doubt that all 15 projects awaiting permits will be built because of financing and market uncertainties. But if even half are built, the new terminals could ship 10 billion cubic feet a day of U.S. natural gas — equal to about 15 percent of U.S. consumption in 2011. The NERA report estimates that after five years, exports could raise U.S. prices by 22 cents to $1.11 per thousand cubic feet.
U.S. industrial firms worry about even steeper price increases.
“We’re reluctant to say our concern is exports,” said George J. Biltz, Dow Chemical’s vice president of energy and climate change. “We believe in free trade. We export chemicals.”
But, he said, the United States should use cheap natural gas at home to revive its industrial economy and then export manufactured products, capturing the value added at home. “Our view is we should export ‘solid’ natural gas. We should create goods and export the goods,” he said.
“Some people say ‘no exports.’ People on the other side say ‘free market, free trade, let us manage this.’ Frankly, Dow is not at either one of those extremes,” Biltz added. “We see the right balance somewhere in the middle because you have a massive competitive advantage here. Companies should not be deciding for the United States what’s best for the country. We think that’s a role government can play.”
He said the Energy Department had to figure out the point where the appetite of foreign markets might endanger the cheap prices at home. “We’re creating very inflexible 20-year contracts for natural gas. It’s going offshore to Japan, China, pick your favorite,” Biltz said. “At some point, you start changing the whole price structure in the country and lose that competitive advantage. No one knows where that point is.”
Cheniere’s Souki brushed aside Biltz’s concern. “I’m really going to start crying for them,” he said. “They pay $3 for gas, and the poor bastard in India or China who wants to compete has to pay $3.50 for the gas plus $3.50 to liquefy it and $3.50 to $4 for transportation. So foreign companies are paying 3½ times more than Dow Chemical is paying for their gas. If Dow still can’t compete, it needs to revisit its business strategy.”
As far as gas supplies, Souki said that “we’re never going to have a problem . . .There are new discoveries almost every month.” Even though natural gas prices are low, he said, supply is still growing because oil prices are high, and when companies look for oil they usually find gas, too. Hence, in places like North Dakota, large volumes of natural gas are being flared until pipeline infrastructure can be built.
Key members of energy committees in Congress are urging the Obama administration to exercise caution before issuing permits. “I’ve tried to say, ‘Let’s just step back here for a minute and think through the implications,’ ” Wyden said.
Wyden considers himself a free-trade Democrat, but he views energy as a separate issue.
“I believe you ought to grow things in America and that you’ve got to add value to things in America, and ought to ship them somewhere,” he said. “But I also think that when you’re talking about strategic national assets, which is what I think you have with natural gas, you should look before you leap.”
The International Energy Agency forecasts that U.S. domestic prices will rise to $5.50 a thousand cubic feet by 2020, primarily because of growing domestic demand. With the high cost of liquefaction and shipping, LNG exports from the United States aren’t a sure bet.
“This notion that LNG exports are a no-brainer is just not true,” said Robin West, chairman of the Washington-based consulting firm PFC Energy and a former Cheniere board member, who expects that only a few export terminals will be built. “This fear that there’s going to be this great big sucking sound for U.S. LNG and that [exports] will drive up U.S. costs is highly unlikely.”
Even if they’re not exported, the deep U.S. natural gas reserves have rocked the global market, squeezing out many big LNG exporters who had planned to ship here.
Qatar, the world’s largest LNG exporter with the world’s biggest LNG tanker fleet, had counted on the U.S. market. In its 2007 annual report, Exxon Mobil said that Qatar was building an export facility capable of shipping 1 billion cubic feet a day just for the U.S. market. In Texas, Qatar Petroleum took a 70 percent stake and Exxon Mobil a minority stake in the Golden Pass terminal, with a capacity to import 2 billion cubic feet a day, primarily from Qatar. Now the terminal is idle, and Golden Pass is asking the Energy Department to permit a $10 billion conversion to exports.
Qatar and other gas-rich countries — which only four years ago talked about forming a cartel modeled on OPEC — need to find new homes for their shipments. And they’re doing that at a time whengas demand in Europe is collapsing, falling 9 percent below the levels of 2009, at the depths of the Great Recession.
Asia remains a major destination — and has kept global gas prices high. Demand in China is growing steadily, and its current five-year plan calls for expanding gas use. And Japan’s appetite for LNG soared after it closed its nuclear plants in the wake of the tsunami that destroyed the Fukushima Daiichi nuclear complex. With new supplies coming online, however, even Japanese companies have been pressing to link their payments to the low spot price for U.S. natural gas at Louisiana’s Henry Hub, the U.S. benchmark.
The decline in Europe has put pressure on Russia and its state-owned gas monopoly, Gazprom.
Russian gas pipelines — built in Soviet days — are still the principal suppliers to Europe. When built, they were criticized by President Ronald Reagan, who said they would allow the Soviet Union to blackmail Western Europe. In recent years, strategists and companies have worked to diversify supplies by building new pipelines from the Caspian Sea through Turkey. And Poland, heavily dependent on Russian gas, has been trying — albeit with disappointing results — to tap its own shale deposits.
But Europe is now adding LNG importing facilities. Just as important, it has recently used cheap U.S. coal for electricity generation. That coal, displaced by cheap U.S. natural gas, is replacing expensive Russian gas. Gazprom’s share of European gas imports has dropped from half a decade ago to about a third. In response, Russia has renegotiated gas contracts — previously linked to the price of oil — and reduced prices to Germany, Italy and Poland. Gazprom also has told some independent Russian gas producers that it would no longer guarantee the same level of purchases. Russia’s gas exports will drop 4 to 5 percent this year, Energy Minister Alexander Novak, according to the newsletter Petroleum Argus.
“The United States gave a gift to European importers, deliberately or not,” said Fatih Birol, chief economist of the International Energy Agency. “It is making importers’ hands stronger.”
Birol notes that by 2015, the United States will overtake Russia as the world’s biggest natural gas producer. In the past four years alone, he said, U.S. natural gas production increased by an amount equal to total Russian exports today.
That isn’t stopping enormous wagers on LNG export terminals around the world. Chevron is the lead partner on three mega-projects in Australia. Exxon Mobil has an LNG project in Papua New Guinea whose cost estimate recently ballooned to $19 billion. BP is launching a $12 billion expansion of an Indonesia project targeted at Korean and Japanese customers.
Will they succeed or become white elephants? No one forecast the economic crisis in Europe or the tsunami or the surge in U.S. shale gas supplies. And then there’s China, whose substantial shale formations are still waiting to be unlocked.
To get an idea of how abruptly assumptions have changed in a decade, consider the decision by Chevron and France’s Total Gas and Power to back LNG imports at Cheniere’s terminal at Sabine Pass. Each of the two oil giants guaranteed it would pay to import natural gas. Without the contracts, Cheniere would not have been able to raise the money needed to build the import facility.
Today, the import portion of the facility is idle. Four tug boats gaze out toward the languid Gulf of Mexico. And Chevron and Total are each paying Cheniere about $125 million a year until 2029 — essentially for nothing.
Now Cheniere, heavily indebted, has attracted new money from investors, including $1.5 billion from the Blackstone Group, to finance the conversion of Sabine Pass into an export facility. Cheniere already has federal approval there and is seeking approval to add an LNG export terminal in Corpus Christi, Tex.
“Nobody saw it coming,” Cheniere’s Souki said. “Not their planning departments, and certainly not us. Nobody foresaw the shale gas revolution in the United States.”