Fresh life is being breathed into a decades-old Canadian visionof a mammoth production and pipeline project to tap Arctic naturalgas reserves. For the first time in nearly a decade, theproduction community, with help from a U.S. producer, is revivingexploration on its formerly most dramatic frontier. A Canadiangovernment auction of drilling rights drew takers for 2,934 squarekilometres (1,132 square miles) of the Mackenzie Delta-Beaufort Searegion. Initial work is expected to start within a year. TheNorthwest Territories awarded the rights as four nine-year resourcehunting licences, in exchange for C$183 million (US$122 million) inwork commitments by four producers with a penchant for chasing biggas targets.

Poco Petroleums Ltd. and its new owner, Burlington ResourcesInc., pledged C$77.9 million (US$52 million) for two parcelstotaling 1,455 square kilometres (562 square miles), with eachcompany holding a 50% interest. Petro-Canada and Anderson ResourcesLtd. teamed up to take two parcels totaling 1,480 square kilometres(570 square miles) for work commitments of C$105.2 million (US$70million), with the ownership split 60% Petrocan and 40% Anderson.

Burlington chairman Bobby Shackouls put the producers’explanations in a nutshell: “This move into the highly prospectiveMackenzie Delta area is an excellent opportunity.” In Burlington’scase, he called the step into the Canadian Arctic “a prime exampleof the value-added growth exposure we are looking for and intend tocontinue upon completion of our acquisition of Poco Petroleums.”

It was the first time in a decade the Arctic has been portrayedin such glowing terms. It was anything but the first time highhopes have been pinned on Canada’s far north.

On paper, at least, the Arctic vision never really died afterbattered oil and gas prices put an end to high-rolling explorationon Canada’s northern frontier in the mid-1980s. Imperial Oil Ltd.,Shell Canada Ltd. and Gulf Canada Resources Ltd. still hold avalid licence from the National Energy Board to export 13 Tcf ofDelta gas they discovered in the 1960s, ’70s and early-’80s. Thelicence, granted in 1989 after high-profile hearings in Inuvik,stays live until Oct. 31 of 2000. The exports can proceed for 20years if the companies start making deliveries to the UnitedStates. There were tentative takers who signed precedentagreements, although not final contracts, at the time. While notall potential buyers agreed to be identified, the list disclosedincluded Enron, Texas Eastern, Pacific Interstate Transmission, ANRPipeline and Pacific Gas & Electric (through former Canadianbuying subsidiary Alberta & Southern Gas).

No one believes a Mackenzie Valley pipeline can be built beforethe export licences expire. A “hypothetical” transmission systemdeveloped for the hearings described a development on the scale ofC$4.5-billion (US$3-billion) Alliance Pipeline Project. The linewould be a C$5 billion, 1.4 Bcf/d route stretching from the Deltato an inlet to the Foothills and TransCanada-Nova systems atCaroline, about an hour’s drive northwest of the Canadian gascapital of Calgary.

But there is no sign that the NEB would change its mind aboutthe northern gas being available for export if it were asked toextend the licences. In approving Alliance and Maritimes &Northeast Pipeline – and in multiple export licence hearings, attimes over resistance by Canadian nationalists andenvironmentalists – the NEB has upheld an open market policy. Thereis considerable interest on the wider, international market and,in fact, 16 corporate sponsors paid for a major study of revivingnorthern gas development by the Calgary office of the internationalconsulting firm of Purvin & Gertz Inc.

The study, while being kept confidential in detail, concludedthere were possibilities for Arctic gas and a project could work ifbenchmark Henry Hub prices reach US$2.50 per MMBtu on a sustainedbasis. That figure echoes the economics of Arctic gas described inthe NEB export licence decision. At that time, the supply cost ofDelta gas delivered to Caroline was projected to start at $2.68then fall steadily as up-front costs of production and pipelinefacilities dropped. In five-year steps, Arctic gas supply costswere projected to drop to $2.13, then $1.90, then $1.59, and end upat $1.35 in the last quarter of the 20-year licences.

Since the Arctic licence decision, there have been both negativeand positive developments in the north – weighted toward thepositive.

On the negative side, a new appraisal of Delta-Beaufortdiscoveries, released by the NEB late last year, lowered estimatesof their size due to studies with improved seismic-surveytechniques. But the worst news was on the oil side. Estimates ofthe biggest oil find, Amauligak, were cut down to 235 millionbarrels – a far cry from hopes for a billion-barrel cornerstone ofan oil megaproject that the 1984 drilling success ignited.

Estimates of gas associated with Arctic oil likewise dropped.But even though estimates of separately discovered Delta-Beaufortnatural gas also have been trimmed, they still are rated in therange of 9-12 Tcf. Burlington and Poco stressed that their newexploration acreage lies beside the two largest Canadian Arcticland discoveries: Niglintgak and Taglu, which the NEB continues toestimate at reserves 2.5 Tcf plus 60 million barrels of liquidbyproducts and oil. The board also continues to rate the region ashighly prospective, with potential to yield 53 Tcf of gas and fivebillion barrels of liquid byproducts and oil.

On the positive side, events since the NEB’s Arctic gas exportlicence decision have confirmed a trend that showed at the Inuvikhearings. Native opposition to industrial development, which haltedthe first version of the Arctic pipeline megaproject in the 1970s,has turned into acceptance and even enthusiasm so long as benefitsare spread around. The native-dominated territorial government hasalso sent a message that the north is ready for development byaccepting a royalty regime billed as “one of the most competitivein the world”: 1% of gross revenues for first production, rising by1% steps every 18 months to a maximum 5%, then after payment of allproject costs the greater of 5% of gross revenues or 30% of netrevenues.

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