Supply, pricing uncertainty cloud LNG

Changes in industry weighing on both buyers and sellers, with buyers demanding lower prices, producers saying they can’t go too low

Larry Persily

Federal Coordinator, Office of the Federal Coordinator

The speed — and uncertainty — of changes in global LNG supply, demand and pricing are weighing on buyers and sellers, said speakers at an international gas conference in London.

“There is no industry that is as volatile and cyclical as the LNG business — maybe pig farmers,” was how Philip Olivier, president of Paris-based GDF Suez Global LNG, put it at the Gastech 2012 conference held Oct. 8-10.

“We find ourselves in very uncertain times as an industry,” said Andrew Walker, vice president for global LNG at U.K.-based BG Group.

Conference registration totaled 1,500 delegates, with the largest contingent, 52, coming from ExxonMobil and its affiliates.

LNG buyers made clear at the conference that they want lower prices for the fuel. Producers were clear they couldn’t go too low. And many speakers made clear that nothing is clear about future LNG pricing.

“I suggest North American and European prices will have to increase” to a level that will encourage exploration and development of new gas supplies, said Noel Tomnay, head of global gas research at U.K.-based energy consultants Wood Mackenzie. At the other end, high prices in Asia likely will drop as new LNG suppliers compete for customers, Tomnay said.

But regardless of what buyers may want, there is no cheap natural gas left in the world, said Fereidun Fesharaki, chairman of FACTS Global Energy, a Singapore-based international consulting firm. New LNG projects generally need to receive around $12 per million Btu for their output, he said.

Tomnay said it’s a struggle to find new Australian LNG export projects that can break even at less than $11. Some, he added, need to sell their output at $14. That’s about $1 higher than this month’s spot market price in Asia.

Meanwhile, some Asia buyers are signing shorter-term contracts as they wait for new supplies later this decade from Australia, Papua New Guinea, Africa and possibly Russia, Canada and the United States, Fesharaki added. They are betting a supply surplus will drive down prices in a few years, he said.

They could win that bet. LNG supply will exceed Asian demand though 2025, according to forecasts from Japan’s Institute of Energy Economics, said Kunio Nohata, senior general manager at the gas resources department of Tokyo Gas. And that doesn’t count proposed export projects waiting final investment decisions by corporate boards.

Though buyers and sellers are haggling over pricing, particularly in Asia where buyers want to break the LNG link to oil prices, long-term deals are still the norm for LNG projects to justify the huge upfront capital cost of liquefaction plants. “Oil is like dating, gas is like getting married,” Fesharaki said of the difference between the oil and LNG markets.

The LNG industry has seen spectacular growth since Gastech, held every two years, started in 1972. Global LNG trade totaled 105 billion cubic feet in 1970. In 2011, it topped 11 trillion cubic feet.

Just 11 LNG tankers sailed the oceans 40 years ago. Today, 370 tankers ferry liquefied natural gas between continents, said Chris Clucas, commercial director at Cyprus-based Bernhard Schulte Shipmanagement. An additional 82 tankers are on order, said Mike Rowley, LNG division director at Tokyo-based Mitsui OSK Bulk Shipping.

Global pricing

“Henry Hub just happens to be the lowest price in the world today,” so everyone wants it, said Sir Frank Chapman, chief executive of BG Group. But Henry Hub, especially at today’s low prices, has nothing to do with the actual cost of production, particularly capital-intensive LNG, he said.

“We don’t think Henry Hub is always cheap,” said Nohata, of Tokyo Gas. The price at Henry Hub spiked above $10 for several months in 2005 and again in 2008 — a fact that did not escape the notice of LNG players.

“It is important to note that Henry Hub pricing doesn’t necessarily mean cheaper pricing,” said BG Group’s Walker.

“I believe that a fungible, global gas market eventually will come,” Chapman said. Buyers will want more flexibility to divert LNG cargoes to take advantage of market fluctuations. But he expects gas prices will be “highly regionalized for the foreseeable future.”

The Henry Hub price for pipeline gas delivered in the U.S. this month has hovered around $3.50, with the price just under $13 for spot-market LNG cargoes delivered in Asia. LNG buyers, however, have to cover the substantial cost of liquefaction and shipping to have gas delivered to their receiving terminal. Those “handling” costs would add at least $6 per million Btu to the Henry Hub price from any of the proposed U.S. Gulf Coast and Canadian West Coast liquefaction terminals.

Nohata said Japanese buyers would like to add Henry Hub prices as a factor — but not as the exclusive link — to their LNG purchase contracts, along with a softer oil-price link when world crude markets are high. “We believe diversification is the biggest keyword,” he said, both in pricing formula and supply.

Oil-linked pricing

A new pricing formula, removed or at least cushioned from high global oil prices, is especially important for China and India, Muraki said, because expensive LNG strains their government subsidies of gas prices to consumers. “That kind of market cannot continue.”

But there is a limit to how much LNG suppliers can drop their price, said Wood Mac’s Tomnay. Developers must cover their heavy upfront costs, which can run tens of billions of dollars for the most expensive projects. Whereas the long-term contract price for 1 million Btu of LNG — roughly 1,000 cubic feet of gas — had been around 17 percent of the cost of a barrel of crude oil, it has softened in recent years to 14 percent, Tomnay said. “You can only go so far because of the high cost of these projects.”

When the world’s first LNG contracts were negotiated decades ago the fuel replaced oil, so oil-linked pricing made sense, said Jonathan Stern, chairman and senior research fellow for the natural gas program at the Oxford Institute for Energy Studies in England.

But no one expected oil prices to rise so much or gas demand to grow so much. As market fundamentals changed, the contracts did not adapt. “The discontent ... is growing” with crude-linked LNG prices, Stern said.

“How do you get a price that works for buyers and sellers,” said Robin Baker, global head of project and reserve-based finance at Paris-based bank Societe Generale. Finding that balance will be important in putting together project deals, he said.

North American LNG

“The impact will not be overwhelming,” said BG’s Chapman. Other projects from outside North America still will be needed to satisfy demand in the years ahead, and those projects will need higher prices to cover their costs.

First, the U.S. Department of Energy must decide how many LNG export projects it will approve from among the 15 or so applications that are on hold pending a consultant’s report on how gas exports could affect the nation’s economy.

“The issue in the Americas is an issue of political will,” said Andy Brogan, global leader of oil and gas advisory services at international consultants Ernst & Young. “There is a lot of skepticism that any politician in the U.S.” will have the will to allow exports, he added. Brogan is more optimistic of Canadian export projects, noting there is not the same political resistance to exports as in the U.S.

Supply and demand and the markets should set the level of U.S. exports, not the government, said Richard Guerrant, vice president for LNG at ExxonMobil Gas and Power Marketing.

BG Group’s Walker said he expects the Energy Department eventually will approve projects totaling more than 2 trillion cubic feet of liquefaction capacity a year, or 6 billion cubic feet a day. The industry will self-limit what it produces, he said, not wanting to flood the market.

Catherine Verdier, vice president for markets and strategy at France’s Total Gas & Power, offered a two-tier prediction: About 4.5 bcf a day of U.S. exports by 2020, growing to 8 bcf a day by 2030. Still, she does not believe it will be enough to substantially affect global pricing. The LNG trade worldwide totaled 32 bcf a day last year, a figure expected to grow substantially in the coming decades.

The availability of gas to supply U.S. liquefaction terminals depends on continued use of hydraulic fracturing in shale plays. “As we all know, fracking has many opponents, especially in Hollywood,” said Derek Brower, editor at Petroleum Economist magazine.

The fracking fight is mostly about water — keeping the dirty stuff deep underground and away from community water supplies — said Susan Sakmar, energy law scholar at the University of Houston. “By far one of the most critical issues ... is what the EPA calls the water life cycle,” she said, adding that fracking a typical deep Marcellus Shale well consumes 5 million to 6 million gallons of water. Much of it comes back up and requires safe disposal.

Environmental controversies over fracking and shale drilling were cited as a good example of needing a “social license” to develop a project. “A social license is earned and it’s intangible,” said Julie Nelson, director of public and governmental affairs at BG Group. “It’s simply not good enough to have all of your permits in place. ... A company must go above and beyond” to earn the public’s credibility and trust.

“You have to seek out the people who don’t want you and explain it to them,” said Darron Granger, senior vice president for engineering and construction at Cheniere Energy, developer of the first LNG export plant in the Lower 48 states.

Demand Variables

A gas pipeline from Russia is another option under consideration, Muraki said. A supply of pipeline gas to Japan “is the other issue that could change the pricing” of LNG. A pipeline, however, faces political hurdles, in addition to the technological challenge of crossing 500 miles of water almost 2 miles deep at its low point.

Several speakers said China will be a bigger market driver than Japan in the years ahead.

If China sees LNG at $15, “they’ll say, fine, let’s develop (our) shale,” said Stern, of the Oxford Institute. The U.S. Energy Information Administration estimates China’s shale gas reserves could top those of the United States, though exploration and development is in its infancy.

Ernst & Young’s Brogan also warned that pipeline gas could displace LNG in China. “Don’t be surprised if some markets lose out to indigenous production and piped gas.”

China already is turning to pipeline gas in greater quantities. This year China has imported more pipeline gas than LNG, the first time that has happened.

China consumed about 4.6 trillion cubic feet of gas in 2011, producing about 3.6 tcf from its own fields and importing the rest — with a slight advantage for LNG — said Jennifer Coolidge, executive director of CMX Caspian and Gulf Consultants, based in Cyprus. And although she expects the gap between consumption and domestic production could grow to several trillion cubic feet a year by 2020, Coolidge said China already has made plans to take more pipeline gas from Turkmenistan in the near term, adding Kazakhstan and Uzbekistan gas longer term.

Two west-to-east pipelines already move gas from Central Asia into China, with a third starting construction this fall.

That pipeline gas has been less expensive than LNG this year.

The high cost of LNG was a recurring theme among speakers. China, with India, relies on government subsidies to hold down the cost of gas to consumers and may try to boost domestic production or even build coal-to-gas conversion plants if LNG is too expensive, said Anna Howells, head of Asia energy for Herbert Smith Freehills, the world’s third largest law firm by number of attorneys.

Supply variables

Almost half of the 250 tcf in natural gas discoveries worldwide in 2010-2012 have come in East Africa, said Wood Mac’s Tomnay.

But a lack of infrastructure, a shortage of skilled labor and local government issues are problems, said Bill Dudley, president and CEO of Bechtel Corp., a builder of LNG facilities worldwide.

Citing East Africa’s undeveloped infrastructure and regulatory uncertainty, Howells said she doesn’t expect to see any LNG tankers sailing from East Africa before 2020.

Still, Tomnay said, “East Africa looks tremendously exciting. ... There are so many supply options, it’s very difficult to pick a winner.”

Qatar is the world’s leader in LNG production capacity at 10 bcf a day. The nation’s moratorium on new projects expires in 2014, noted Khalid Sultan R. Al Kuwari, marketing and shipping executive at Qatar’s RasGas, though he did not speculate whether the government would decide to undertake new projects.

Qatar’s drawback in the Asia market is its distance — almost 7,500 miles to Tokyo, said Rowley, of Mitsui OSK Bulk Shipping. Australia is several thousand miles closer, as are Canada’s West Coast and Alaska. (LNG tanker costs from Australia to Japan run about 85 cents per million Btu less than from the Mideast, according to recent figures from ICIS Heren, a global energy information firm.)

The LNG supply even farther away from Japan than Qatar is the U.S. Gulf Coast, Rowley said, at more than 10,000 miles. And that is after the expanded Panama Canal opens in 2014.

Coming up fast on Qatari gas production is Australia, which is poised to overtake the Mideast nation as the world’s largest LNG supplier before the end of the decade, with more than $170 billion in liquefaction projects under development.

Those are costly projects, especially the three projects that will source their gas from coal-seam plays, Howells said. The coal-seam gas is low on valuable liquids and condensates, putting more of a burden on getting a strong price for the methane.

Project delays, labor shortages and cost overruns are making it tough on new projects in Australia, said William Breeze, a colleague of Howells at Herbert Smith Freehills. “The window of opportunity for Australia projects may be closing.”

Project financing

Baker, of Societe Generale, said lenders signed up for the Papua New Guinea project because they saw the same window for Asia LNG demand as the developers; there are solid off-take contracts for the gas; ExxonMobil brings strength as the plant operator; and the project has national support. The project was financed with 70 percent debt at 15- to 16-year terms.

That’s a typical term for project debt, Craen said, noting, “There is quite a lot of scope for lenders to lend longer.” Extending the payments over more years — just like homeowners and car owners often do — lowers the loan payments.

Since 2005, most LNG projects have been project financed with cash flow from the plant to pay off the debt, rather than the owners using their own balance sheets and other profits to cover the mortgage, said James Ball, a director at Gas Strategies, an international gas consulting firm. He predicts financing deals will grow more complex as many projects are attracting multiple partners, each with different needs and aspirations.

The industry can handle complex deals, Ball said, but he doubts financing will be available for developers without a proven track record.

Pre-2009, commercial banks covered about half the debt, Baker said, but since the global financial crisis banks are down to one-quarter of the debt, with government export-import banks helping to take up the slack. Looking ahead, government export credit agencies will be increasingly important, and marginal projects will have a harder time getting financing unless developers put up more equity, Baker said.

The U.S. Export-Import Bank this year agreed to help finance an LNG project in Australia that includes ConocoPhillips as a partner.

There will be challenges ahead, Brogan said. Banks are weaker, especially in Europe; governments are running deficits; and many lenders are risk adverse and are thinking short term. “In the short term what we’ll be looking at” is a heavier use of corporate balance sheets pledged for financing.

Another possibility for project financing, Baker said, may come from insurance companies and pension funds looking for long-term, stable cash flows.

A project cost warning came from Colin Harrison, of the downstream oil and gas infrastructure team at international energy consultants Gaffney, Cline and Associates. Almost 78 percent of oil and gas megaprojects since 2000 “have exhibited poor cost and/or schedule performance,” Harrison said. Deep-water construction, environmental restrictions, political interference and remote locations all contribute to the problem, he said. The answers are robust front-end engineering, a realistic project development strategy and identifying risks.

Cheniere’s Louisiana project

When Cheniere approached Societe Generale for help with financing, the bank told the company to get its federal export authorization and construction approval, gather up a lot of equity, and get 20-year contracts with investment-grade customers, Simon said. Cheniere raised $2 billion for its equity contribution to the project: $1.5 billion from Blackstone Group-affiliated investment funds and a combined $500 million from a Singapore investment bank and U.S. private-equity firm.

Cheniere will first spend the equity on construction, Simon said, tapping the debt later in the project. U.S., Canadian and European banks participated in the debt, which totaled $3.6 billion and included issuing bonds rated by Standard & Poor’s one notch below investment grade.

That was more a reflection on the parent company, Cheniere Energy, than on the LNG export project itself. Cheniere had fallen to the brink of default on its debt after building an LNG import terminal that today only rarely receives shipments as U.S. shale gas production reduced the nation’s need for gas imports.

“For us it was a matter of life and death,” said Charif Souki, Cheniere’s CEO. The company was close to bankruptcy and needed to find a way to salvage its investment in LNG storage tanks, a loading terminal and docks, pipes and the rest. It also still had half of its 1,000-acre riverfront site available for construction. All of which made it a very economical project to add a liquefaction plant and run it as an LNG export terminal.

The almost $6 billion in equity and debt will cover construction of the first two trains at the plant, Simon said. The first production train is scheduled to come online in late 2015, with Cheniere counting on $255 million in cash flow from that first train to help pay for construction of the second train — a strategy cited by S&P’s as a point of concern in its credit rating.

The development budget covers $4.9 billion for construction, $661 million for interest during construction, and $214 million in upfront fees and development expenses, Simon said.

After the first two trains are completed, Cheniere plans to construct two more trains, bringing total capacity to more than 2 billion cubic feet a day, ranking it among the world’s largest liquefaction plants. The capacity of all four trains is fully subscribed under 20-year contracts, with customers paying a fixed charge for liquefaction and whatever the market price is for gas. Cheniere takes no commodity price risk — it falls entirely on the plant’s customers. This is a new LNG pricing approach that global buyers and sellers are watching keenly.

Cheniere also has applied for federal approval for an LNG export project at Corpus Christi, Texas. Construction could start in 2014, pending federal approval and a corporate go-ahead, Granger said, adding, “Cheniere could not be happier.”

Editor’s note: This is a reprint from the Office of the Federal Coordinator, Alaska Natural Gas Transportation Projects, online at www.arcticgas.gov/print/supply-pricing-uncertainty-cloud-lng-industry