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China has tremendous shale gas resources, Russia wants to move aggressively into the LNG export business, and the potential for North American LNG projects to sign up customers in Asia "may not be open indefinitely," said Ian Nathan, manager for global gas and LNG research at Energy Intelligence.

In the world of Asian gas supply and demand, "a lot could change very quickly," Nathan told the audience at the 12^th annual Arctic Oil & Gas Symposium in Calgary March 13.

"The Russians are moving on a number of LNG plants," all targeting the Asia market, he said.

Nathan particularly warned against thinking of China as a "bottomless sink" for LNG sales. Rather than pay high prices for imported liquefied gas, the government is making it a priority to boost domestic production by developing China's own shale gas resources.

Price also is an issue in China, said Nathan, whose research and advisory work at Energy Intelligence is separate from the company's oil and gas newsletters.

The government generally sets low prices for natural gas and electricity, forcing losses on power generators and others that import gas. Natural gas prices differ by region but average roughly $5 per million Btu, far below the cost of most imported LNG and pipeline gas. That wasn't so bad until LNG deliveries to Asia started climbing past $7 and $8, toward $10 and higher four or five years ago.

China is experimenting with market-based pricing in a couple of provinces, Nathan said. (Under the experiment announced last December, the government will allow prices to rise to around $12 per million Btu in the two provinces).

While any pricing transition nationwide will be gradual, the effort is "a big deal," he said. The intent is to constrain China's energy consumption, while stemming the losses at companies that import gas.

In addition to developing its own shale, China can take delivery of pipeline gas from Turkmenistan and elsewhere, Nathan said, providing additional competition to LNG.

GLOBAL GAS PRICING

Though many companies around the world, including U.S. producers, see Asia as the best market because of high LNG prices there, Nathan asked: "What if those markets change?" Cheniere Energy's sales contracts for its proposed LNG export terminal at Sabine Pass, La., are based on lower U.S. natural gas prices, not the oil-linked prices accepted in the past by Asian buyers. "This is absolutely key," Nathan said. "The whole way that LNG is sold into Asia could change" if low U.S. gas prices become the basis for pricing in Asia rather than high global oil prices.

Regardless of any changes in global gas pricing, or Russia's LNG plans, or China's shale gas resources, investment decisions in LNG export projects will come down to shipper confidence, he said.

"It's a little bit obvious what needs to happen for these plans to be feasible," Nathan said. Shippers need confidence in the market at the end of the tanker voyage. And governments may need to get more involved if they want to see their nations' LNG projects get built.

He fears high prices for LNG will not last, while also doubtful of a return to strong North American gas prices anytime soon. But, he acknowledged, "Ten years is a long time ... 10 years from now you might be having a very different conversation."

North American gas prices depend in large part on shale production and demand from power plants. Longer laterals, faster drilling operations, more fracking stages per well are boosting shale productivity, Nathan said. But environmental issues such as wastewater disposal, policy concerns such as local land-use regulations and rising costs are "lurking in the shadows" and could dampen production growth.

Even with all the shale gas entering the North American market, shale's heyday may be less long term than people expect, he said. It will take all of the shale gas to cover for the decline in conventional production in the United States and Canada, while also meeting growing demand expected for power generation, Nathan said.

But so far, shale-gas supply is overwhelming demand. "Power-generation demand is expected to be the big market mover," he said, especially as power plant operators deal with coal-emission rules and see stable future gas supplies. "A lot could change very quickly."

MACKENZIE GAS PIPELINE

Supporters of Canada's long hoped for Mackenzie Valley natural gas pipeline point to declining North American conventional gas production as a big reason for why they retain hope for their project.

Canada needs to add 3 billion cubic feet a day of new supply each year to maintain current production, said Robert Reid, president of the Aboriginal Pipeline Group, a partner in the proposed Mackenzie gas line. Project supporters see that declining conventional production as an opportunity, even with the growth of shale gas coming online.

But even if the demand is there, the high cost of the project vs. the risk of low gas prices makes the pipeline difficult, Reid said at the symposium. "The real problem right now is the economics." The Mackenzie line needs $6 or $7 gas to pencil out, he said. "It's not the gas price today that is important. It's the gas price in 2020 that is important."
The Mackenzie Gas Project partners are still in talks with Canada's federal government on a "fiscal framework" for the pipeline, Reid said, including loan guarantees and financial help with infrastructure costs for the remote project. The most recent federal offer was not enough, he said.

In addition to the Aboriginal Pipeline Group, the Mackenzie partners include Imperial Oil, ExxonMobil, ConocoPhillips and Shell. The 742-mile pipeline initially would move 1.2 billion cubic feet of gas a day from Mackenzie Delta fields in the Canadian Arctic on the Beaufort Sea, feeding into the North American gas pipeline grid at the northern Alberta border.

Total cost was estimated in 2007 at $16 billion.

"The Mackenzie pipeline is a big pot of gold at the end of our rainbow," said David Ramsay, Minister of Industry, Tourism and Investment and Minister of Transportation for the Northwest Territories.

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