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Forget Alaska Highway pipeline, think LNG or GTL, says analyst CIBC World Markets’ Chris Theal believes economics, not politics, will settle future of Alaska’s stranded gas; thinks Mackenzie Valley line makes more sense Gary Park PNA Canadian Correspondent
For purely economic reasons, the prospects of a conventional natural gas pipeline from Alaska’s North Slope to the Lower 48 are “dead in the water,” said Christopher Theal, an investment analyst with CIBC World Markets Inc.
He said that delivering the gas by overland pipeline has no hope of competing on an equal footing with liquefied natural gas available in the U.S. Atlantic basin.
The best bet for Alaska’s stranded gas, he said, is conversion to liquids for shipment through the existing crude pipeline to Valdez, then by tanker to California markets.
“I don’t think it is going to be a political decision, despite what is in front of Congress right now,” Theal told a Conference Board of Canada seminar last month on strategic options for growth by oil and gas companies. Subsidies would devalue Canadian gas The U.S. Senate plan to use subsidies to establish a floor price of $3.25 per thousand cubic feet for gas shipped by an Alaska Highway pipeline would devalue the remaining gas in the Western Canada Sedimentary Basin and likely trigger opposition from U.S.-based companies who have made major purchases of Canadian gas assets in the last couple of years.
“For the U.S. producers who came up here and spent C$27 billion on acquisitions last year, you are going to put a hair cut of about 25 percent on the value of those assets,” said Theal. “So I think you are going to see political pressure put on (President George W.) Bush from his friends down in Texas.”
He said Canadian industry opposition to subsidies, notably from EnCana Corp., is likely to find allies among Anadarko Petroleum Corp., Burlington Resources Inc., Devon Energy Corp. and Conoco Inc., all of whom now have extensive Canadian holdings, with a heavy emphasis on the Far North. Mackenzie makes sense On the other hand, he said a Mackenzie Valley pipeline from the Mackenzie Delta/Beaufort Sea would make economic sense at US$3 per thousand cubic feet.
But Theal said the rising demand among Alberta’s oil sands producers for gas to fuel their extraction and processing operations means Delta/Beaufort gas is unlikely to ever reach the Lower 48.
Forecasting that oil sands producers will more than double their gas demand by 2015, matching the entire proposed stream of 1 billion cubic feet per day of gas from the Canadian Arctic, he said:
“We don’t think gas is going to see the 49th parallel, given how much gas demand we are going to see out of the bitumen and in-situ projects over the next eight years.” Forecast smaller Toronto-based CIBC World Markets is predicting North American gas demand of 27 trillion cubic feet by 2010, or the equivalent of 74 billion cubic feet per day. That is short of the consensus forecasts of 30 tcf per year, partly because of recent cancellations of gas-fired power plants.
Even at the revised level, continental gas deliverability falls short of demand by close to 10 bcf per day, putting the spotlight on frontier reserves, coalbed methane, the possibility of gas hydrates, and monetizing strand gas through LNG or gas-to-liquids technology.
Theal said CIBC World Markets believes that LNG is “ultimately going to fill the void and account for 35 percent of U.S. gas imports by 2010.
“The economics of LNG are ultimately going to dictate the price of North American natural gas,” he said. LNG consumption predicted to grow Now that LNG can compete on a cost basis with pipelined gas in North America, annual consumption of LNG is expected to grow from 4.4 tcf to between 6.3 and 7.8 tcf over the next eight years.
U.S. import capacity is forecast to reach 3.4 bcf per day in 2003 and become the second largest import market in the world, he said.
His projections for LNG were echoed earlier this month by analysts who agreed that LNG will claim 10 percent of the U.S. gas market by 2007 if a dozen plants, each costing about $500 million, are completed.
Companies such as CMS Energy, El Paso and BG Group are in the forefront of those with major import plans in the works.
CMS, which already operates North America’s largest LNG terminal, is aiming to double capacity of the Louisiana facility to 1.2 bcf per day by 2005 and is weighing a new offshore terminal in the Gulf of Mexico.
El Paso, which owns two East Coast LNG terminals, has just negotiated a 17-year contract to import 91 bcf of LNG from Norway to its Maryland facility starting in 2006.
BG is adding to its fleet of LNG ships with the intention of tripling its worldwide LNG production to 6 million tonnes in 2006. Coalbed methane, gas hydrates also show potential On coalbed methane, Theal said the resource has increased from virtually zero to 7 percent of total gas consumption in only a decade, despite the considerable lead-time needed to bring projects into production.
The CBM resource in Canada is rated at about 550 tcf, close to matching the 592 tcf of conventional gas in place, and will make its debut over the next two years as EnCana completes a 1,000-well program in southern Alberta, likely producing 200 million cubic feet per day.
More remote but even more impressive could be gas hydrates — ice-like substances consisting of water and gas and found in permafrost regions and deepwater shelves that have been the object of a recently completed international research partnership in the Northwest Territories.
The U.S. Geological Survey concluded the domestic hydrate in-place resource could be in the range of 200,000 tcf, or 32 times the world’s conventional resources, but Theal cautioned that the potential for development is still many years away.
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