While disclosing that prolonged negotiations will likely delay the delivery date, the senior partner in Canada’s Arctic natural gas project said securing native participation in the Mackenzie Valley pipeline will be worth the wait.

“We would like to push ahead as quickly as we possibly can,” Imperial Oil Ltd. Chairman Tim Hearn told a Calgary press briefing. “But it’s more important to get this right.”

Hearn said the earliest conceivable date remains 2007 for deliveries to start from the Arctic gas team of Imperial, ConocoPhillips Canada, Shell Canada and ExxonMobil Canada. But he rated the target as “now really difficult to hit” unless collaboration promised by the National Energy Board and a host of northern agencies accelerates regulatory approval.

The consortium held off pulling the trigger that starts the process — filing a formal “preliminary information package” that has been ready since last October — in order to let its native partner catch up. The Aboriginal Pipeline Group says it has lined up financing for its one-third interest in the project. The identity of the backer remains confidential while native leaders explain the deal and seek support in their communities across the Northwest Territories.

Rather than name the new partner, Hearn said “we would welcome any party that can bring value-added participation and that is willing to provide funding to the aboriginal pipeline group.”

The mystery backer continued to be widely rumored to be TransCanada PipeLines, kicking in support for the natives in trade for the right to build the new delivery route as an extension of its own system. Hearn and northern project spokesman Hart Searle said no decision had been made on which company will construct, operate and own the Mackenzie Valley line.

The gas-producer team has sought proposals from several pipelines capable of handling the project, a club understood to include Enbridge Inc., Duke Energy Gas Transmission Canada, Alliance Pipeline and possibly ATCO Pipelines, which has a relatively small delivery system but large northern experience.

Hearn said “we’re trying to get to a coalition of people who can each bring something of value to the equation.” Besides technology, the qualifications include skills, expertise and relationships.

As a veteran of Arctic operations since the 1920s, including the death of the ’70s version of the Mackenzie Valley pipeline due to native resistance, Imperial highlighted the high priority it gives to northern community relations in a presentation to a February investment conference in Toronto.

“We believe the critical strength of our initiative is that we have significant Aboriginal direct involvement with the Mackenzie gas project,” The company’s corporate planning director, G.E. Bezaire, told a financial community crowd assembled by Scotia Capital Markets. “We have stated from the outset that Aboriginal support is essential to development.”

Hearn and Searle said that while engineers are still working on designs and estimates, the main outlines of the project continue to be a package expected to cost in the range of C$4-$5 billion (US$2.7-$3.3 billion): C$1 billion-plus (US$667 million) in production facilities on the Mackenzie Delta, and a C$3 billion-plus (US$2 billion) pipeline capable of taking an initial 1 Bcf/d and up to 15,000 b/d of liquid byproducts south to connections with established facilities in northern Alberta.

Except to dismiss the mid-winter highs on skittish commodity markets as a temporary spike, Hearn did not disclose the northern producer group’s forecasts of gas prices or the levels needed to justify the project. “We’ve made some assumptions,” he said. “We’re hopeful we do have a viable project. But there’s risk in this thing. There are no guarantees at this point. It’s not a done deal.”

TransCanada highlighted the supply motivation driving the Arctic consortium to advance the project as rapidly as possible despite its admitted uncertainties over markets and prices. In a new filing in a toll case before the NEB, the pipeline insists that established western Canadian gas fields have turned a historic corner onto a path of natural productivity declines.

TransCanada predicts the trend will be too strong to be offset by a widely anticipated switch in emphasis among producers away from multiple low-cost, shallow wells out on Canada’s share of the Great Plains, toward deeper, bigger targets farther west along the foothills of the Rocky Mountains in Alberta and northern British Columbia. The pipeline says “this shift to the west will only partially mitigate the declining trend of well initial productivity, as pools get smaller and development drilling continues to develop.”

The TransCanada forecast anticipates a drop in average initial well productivity in Alberta and B.C. to a level as low as 100 MMBtu per day from a range of 250 to 300 MMBtu over the next five years. Just to maintain supplies if that decline develops, TransCanada calculates that the western Canadian industry would have to sustain a high level of activity, including aggressive development of an entirely new supply source north of the international border. This could mean an annual flood of more than 12,000 conventional wells, plus up to 5,000 unconventional wells to tap coalbed methane and possibly “tight” geological formations.

The Mackenzie Valley project says its first phase will draw on 6 Tcf of reserves found by frontier drilling since the 1960s. The opening phase taps only about half the reserves already established by exploration on the Mackenzie Delta and in shallow waters of the Beaufort Sea. Drilling continues on the Delta, with discoveries being scored, but kept confidential due to competition for land positions while federal and territorial authorities offer new packages of exploration rights along the Mackenzie River.

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