Call it a sure sign of changing times in Canadian production. A spring construction start has been set for a project that will convert Canada's 51-year-old original natural gas export mainline to oilsands service.

At a recent industry conference in Calgary TransCanada PipeLines Ltd. laid out a schedule for its C$5 billion Keystone oil export project that calls for completing the switch to 590,000 b/d by late 2009 or early 2010.

The conversion has more symbolic than practical significance, by way of confirming rather than starting a trend. Total capacity on the TransCanada gas network's multiple pipelines is forecast to be reduced by only 4%, or less than the space already vacant, due to flat western production, rising Alberta industrial consumption and competition from Alliance Pipeline since its completion in 1999.

But Keystone underscores the Canadian industry's changing emphasis. After two decades of concentrating on gas, as many companies as can find ways to switch targets are focusing on oil.

The action includes accelerated conventional drilling into difficult formations, justified only by high oil prices, such as a Canadian extension of the Williston Basin in the northern United States called the Bakken north of the border. But the primary development target is the Alberta oilsands, where producers such as Canadian Natural Resources Ltd. affirm when asked that they are changing from being primarily gas to chiefly oil companies.

There is more to the change than the estimated 174 billion barrels of reserves available by applying currently known technology to the Florida-sized, 56,000-square-mile bitumen belt of northern Alberta. There is also economics. While Canadian gas prices languish below C$8/Mcf due to oversupplies and the rising value of the loonie against the U.S. dollar, the oil side of the industry has much to gain just by expanding its markets via Keystone and similar developments by Enbridge Inc.

Oilsands plants will net price gains of up to $20/bbl by extending exports to the Gulf of Mexico coast, TransCanada President Harold Kvisle indicated in an interview. Thirsty Texas and Louisiana refineries routinely pay more than crowded markets closer to the Alberta bitumen belt, he reported.

Oilsands supplies are sought after in the region as secure and reliable replacements for unpredictable imports from declining production sources in Venezuela and Mexico, he said.

Completion of the 2,160-mile Keystone project will put oilsands output into southern Illinois and the key U.S. oil trading hub at Cushing in central Oklahoma.

A trickle of Alberta crude currently reaches the Beaumont area east of Houston on a recently reversed U.S. pipeline. Work is under way on increasing the southbound flows and spreading them across the Gulf Coast market by adding more southbound pipeline legs to Keystone, Kvisle said.

Increasing talk is heard in Alberta about how the U.S. Gulf Coast stands out as one of the world's biggest oil trading areas, where refineries buy 7.7 million b/d. After relying for decades on low-grade Latin American crude, the U.S. plants are equipped to use up to 1.4 million b/d of Alberta heavy oil, industry consultants inform Canadian producers.

With current oilsands export outlets limited, bitumen's value has fallen since last fall to as little as half of prices for international benchmark oil grades.

Oilsands producers have booked long shipping contracts on Keystone and U.S. Gulf Coast customers are showing interest in growing the trade in current discussions with TransCanada, Kvisle said.

Tolls to ship oil to the new market region from Alberta are about $6/bbl, but the price bonus earned by going the extra distance is bigger than the added delivery costs by a wide margin, he said.

Deterioration of Venezuelan and Mexican supplies has emerged as a serious concern among U.S. oil importers, said Neil Earnest, vice-president of Dallas energy consulting firm Muse Stancil & Co.

Political upheavals and industry withdrawals have cut Venezuelan deliveries by nearly 30% to 2.5 million b/d from 2.5 million b/d, Earnest said.

Mexico's problem is a slow but steady natural production decline averaging about 15% a year in an aging mainstay oilfield called Cantarell that accounts for about half the nation's output, he added.

"There is no issue with demand for Canadian heavy crude. The global market is insatiable," Earnest said. "The key issue for Canadian producers is market access."

Much the same continues to be said about the oilsands as a growth market for Canadian gas, potentially generating significant reductions in volumes available for U.S. exports.

Industry participants and analysts north of the border, including Kvisle, continue to predict gas use by thermal oilsands production processes will about triple within a decade to 15 years to 2 Bcf/d. While new projects reduce or even eliminate reliance on purchased gas by making fuels from bitumen residue, older plants continue to expand. Prevailing bitumen extraction and synthetic crude oil upgrading processes can use 1 Mcf gas for every barrel produced, and sometimes more depending on reservoir quality and production techniques.

In the latest affirmation of the Canadian production trend, Suncor Energy's board of directors gave "sanction" or approval to a long-range growth strategy known as Voyageur. The long engineering, construction and financing journey will increase capacity at the industry's 41-year-old pioneer oilsands mining and processing complex by about 60% to 550,000 b/d for C$20.6 billion.

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