Kitimat LNG faces Australian rivals

A West Coast LNG terminal will have to compete with gas from Down Under

April 01, 2011

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China is fast emerging as a giant blip on corporate radars in Calgary. But the drive to connect gas supplies from Alberta and British Columbia via what is set to become the only export terminal for liquefied natural gas (LNG) on North America’s Pacific coast is only the latest example of Western Canada’s shifting focus to the Far East.

Kitimat LNG terminal partners Apache Canada Ltd. and EOG Resources Inc. have acquired total control of the proposed Pacific Trail Pipeline. They hope the acquisition can expedite plans to offload western Canadian hydrocarbons to hungry Asian tigers that need fuel and are willing to pay big money for it.

The ambition is underscored by political commitments like the Alberta government’s vow to link Alberta with Asia economically. While the provincial government claims that diversification of clients away from the United States is the main strategic purpose of supporting Asian-oriented export projects, a massive incentive for Canadian producers – particularly in the gas sector – is the high gas price in the Far East and the LNG-focused structure of that market.

“If you’re talking Taiwan, Korea, Japan, these are purely LNG markets,” says Robin Mills, petroleum economics manager for the Emirates National Oil Company. “China currently has some imports via pipeline from Turkmenistan, so it’s developing its pipeline but it’s still fairly small.”

As opposed to Europe, the Russian state-owned gas giant Gazprom is a “pretty small player” in Asia. The Russians have been making gradual headway toward increasing their market share in Asia with a pipeline to China, but gas from the former Soviet empire won’t be coming on stream for a number of years.

The lag makes the Asian market more competitive than Europe, especially to North American gas producers surveying the difference between the collapsed domestic price and the prices in Asia that are twice or even three times as high.

Mills estimates that a new supply contract with Asian gas users today would be oil-indexed at about 15 per cent of the oil price per million British thermal units (BTUs). But he notes that Asian LNG prices are getting softer overall because a lot of new big Australian projects are advancing, which could bring the oil-indexation down to 13 to 13.5 per cent. But Asian prices are far from uniform, Mills notes. “There’s a different formula for every contract. Some contracts end with much higher prices than others, some have floors and some have ceilings, so even though they’re all oil-indexed there are differences.”

The disparities are partly linked to how dependent a given country is on gas, especially LNG. Relationships with traditional suppliers also matter. For instance, India and China represent strong growth markets, but they also boast several energy options including domestic coal and gas. Along with smaller niche markets like Thailand, Singapore, Vietnam and Pakistan, Chinese and Indian gas buyers tend to be more price-sensitive. Japan and Korea, on the other hand, are very dependent on LNG, which makes them ideal targets for exporting producers.

Apache and EOG are currently holding discussions with potential LNG customers in Eastern Asia and expect to have firm sales commitments in place by the 2015 expected launch date of the export facility. The outlet is promising, although it doesn’t necessarily mean Asia is about to open up to large-scale exports and become a sop for the North American gas glut.

A number of big LNG players like Shell, ExxonMobil, BP and BG Group that are active in Indonesia, Malaysia, Brunei, Australia and Qatar are supplying the Asian market, says Mills. The Eastern market is “not nearly as monopolized as Europe but it’s still a tightly closed market and it’s not easy for new companies to get in,” he says. “It’s also about relationships. These companies have strong relationships with companies like Tokyo Gas and other companies that operate the imports.”

The problem with the higher-priced markets is that the same reliance on LNG that makes them lucrative also makes them very reluctant to switch suppliers. “It’s funny because you’d think that oil indexation is a very bad thing for Asian buyers because it’s expensive, particularly right now,” Mills says.

Not so. Whereas the European spot-market system has weakened recently and gas is sold on the spot market more often, Asians generally remain committed to the oil-indexed prices because they believe producers need price certainty in order to make large-scale investments. “Asian buyers, particularly Korean or Japanese, are very traditional and this is a system that works for them,” Mills says. “In a lot of cases, these are monopoly utilities that want reliable supply and they’re just passing through the price. There isn’t so much pressure on them to get the best possible price. All they care about is reliability of supply.”

Non-oil-indexed gas supplies are not necessarily unreliable. Asian producers have been buying from Australia for a long time. The test will be convincing buyers that unconventional doesn’t mean unreliable. Mills says that even at $4 per million BTU, North American gas might not be competitive against Australian gas, as North American producers would face steeper transportation and regasification costs.

“If there are enough Australian projects and they’re aggressive in pricing, I think they will have an advantage,” the economist predicts. But project delays and inflated costs could still stymie proposed export schemes from Down Under. Whether North American producers can capitalize on the Aussie shortfall remains to be seen. Mills is non-committal. “There’s definitely a niche for North American LNG, but is it going to turn out to be a big thing in comparison to Australia? I kind of think it’s less likely – at least short term.”

Patrycja Romanowska is a former Alberta Oil associate editor and Alberta-trained economist currently working in Poland.

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