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Oil and gas explorers return to Canada’s Arctic
Only 250 wells have been drilled over 40,000 square miles with discoveries of 1.7 billion barrels of oil, 12 trillion cubic feet of gas Gary Park PNA Canadian Correspondent
They’re back in Canada’s Arctic, in greater numbers than ever before — the old, the
new, the cautious, the high-rollers.
Thirty years after the first wave of oil and gas explorers hit the Mackenzie Delta, Beaufort Sea and Western Arctic islands, enticed by billions of dollars in federal grants, incentives and loan guarantees, they are returning to Canada’s last great untapped energy frontier — this time on their own terms.
For more than a decade, not a single well of any consequence has been drilled because of a moratorium on pipeline construction and weak commodity prices that saw a huge Arctic infrastructure sold or mothballed and forced companies to beat a retreat to the safer confines of Western Canada.
The Arctic went into the deep freeze as key producers downplayed the prospect of Arctic exploitation in the foreseeable future. Many pushed the development horizon to 2020 and beyond.
But a sudden surge in prices, accompanied by new pipeline capacity to U.S. markets, a ravenous North American appetite for gas and an aboriginal desire to participate in the economic benefits of gas development have producers, pipelines, aboriginals and the Northwest Territories talking of commercial production from the Mackenzie Delta within five or six years.
So it’s back to the future.
The questions now being probed by several players include the economic feasibility of shipping onshore Delta gas, either in conjunction with a North Slope pipeline through Canada, or as a stand-alone venture.
Whatever the choice, not everyone is convinced the region is ready for a multi-billion dollar project. Canadian Arctic lightly explored Developing resources buried below the permafrost is no less challenging than 10 years ago. The regulatory issues, primarily those affecting the environment, are no less daunting. And aboriginal demands for jobs and economic benefits are no less ambitious.
On top of that, the Canadian Arctic is still a lightly explored region compared with its U.S. neighbor. Only 250 wells have been drilled over 40,000 square miles, generating 53 discoveries, including 1.7 billion barrels of oil, 70 million barrels of condensate and 12 trillion cubic feet of gas, 55 percent of it onshore - still a far cry from the Delta-Beaufort Sea’s ultimate reserves, projected at 64 trillion cubic feet.
But the key players are fast closing in on some pivotal decisions, most of them expected this year, that will determine whether the Canadian Arctic comes on stream in the short-term or languishes for an indefinite period.
In this first of a two-part series, Petroleum News ( Alaska offers a snapshot of the most prominent E&P companies operating in Canada’s Arctic. Next month, the spotlight shifts to the new arrivals. Imperial Oil: lead dog in Mackenzie Delta It started life in 1896 as a southern Ontario kerosene refiner, grew into Canada’s largest oil company and is now 69.6 percent owned by ExxonMobil.
Despite joining other majors in an almost-total pullout from Western Canada’s conventional oil and gas plays, Imperial keeps its No. 1 position with 6,550 employees, C$12 billion in assets, four refineries, 2,600 retail outlets under the Esso brand name and major stakes in the East Coast offshore, oil sands and heavy oil regions of Alberta and the Arctic.
As the lead dog in the Mackenzie Delta, with 3 trillion cubic feet of reserves from the 1971 Taglue discovery, Imperial is heading up a consortium of ExxonMobil Canada, Gulf Canada Resources and Shell Canada who control 5.8 trillion cubic feet of reserves and are jointly studying the feasibility of bringing the gas on stream by about 2007.
For Imperial to even join the study was a surprise to many. The Toronto-based giant - the only major Canadian oil company without a head office in Calgary - has consistently given the coolest reception to any notion of Delta development before 2010, at the very earliest.
In the 1970s, Imperial “chased a lot of rainbows” in the onshore Delta and Beaufort area in pursuit of oil only to find gas, said Imperial Chairman, CEO and President Bob Peterson. “There is no doubt there is a large gas resource there and, at today’s prices, you could probably show some pretty favorable arithmetic,” he said. “Whether these prices are sustainable you can speculate about that.”
He said one development concept might be a high-pressure line, with liquids-rich gas, running from the Delta to Norman Wells, in the central Northwest Territories, where liquids would be removed and shipped separately down Imperial’s oil pipeline to northern Alberta.
But he insisted that resolving environmental, regulatory and land issues will probably stall a pipeline start-up until 2008. “I used to say it was seven or eight years away and that was 27 years ago,” he said. “It’s still seven or eight years away.”
The skeptics aren’t even sure that Imperial is even in charge of its own destiny, as rumors repeatedly surface that ExxonMobil is poised to seize the 30.4 percent of Imperial that it doesn’t already own, although Peterson doubts that a take out is on the drawing board.
With Exxon Mobil holding such huge reserves in Alaska’s North Slope, some Canadians believe Canada’s Arctic will take a back seat in the critical decision making and may go untapped for years.
One observer told The National Post: “If you set up the paradigm that it’s one or the other, there’s definitely a conflict between Imperial and ExxonMobil. However, it may not be either or. It may be now and later.”
ExxonMobil’s public stance, according to spokesman Bob Davis, is that there could be a “synergy between the two (North Slope and Mackenzie Delta), which creates very interesting considerations.” ExxonMobil: almost exclusively a frontier player A wholly owned subsidiary of ExxonMobil and operating under a new moniker after years as Mobil Oil Canada, it exists in the shadows of Imperial.
It does not report separate financial results, but produced about 95,000 barrels per day of oil, 500 million cubic feet per day of gas and is estimated to have a market value of C$4 billion to C$7 billion.
With 950 Canadian employees, ExxonMobil Canada is almost exclusively a frontier player, off the East Coast, in Alberta’s oil sands and in the Mackenzie Delta, where a partnership with Gulf Canada yielded a 1.8 trillion-cubic-foot discovery at Parsons Lake in 1972.
For those who think Imperial has barely a 50-50 chance of surviving a parental takeover within the next few years, there is even greater doubt that ExxonMobil Canada can keep its shrinking identity much longer.
Since the creation of ExxonMobil, there have been studies and discussions within the Canadian operations on closer co-ordination of their activities.
In the latest development before Christmas, Imperial and ExxonMobil unveiled a plan to reduce duplication in Canada that will save an estimated C$40 million a year and cost 270 jobs - in other words, improved business ties while leaving them far less cozy than their merged parent companies.
They agreed to stay out of each other’s way in the geographic areas where each has particularly strong growth prospects. Imperial will operate all development projects in northern Canada and ExxonMobil Canada will operate East Coast projects.
Analysts said the pact indicates the parent company has no plans in the near-term to buy out Imperial’s minority shareholders and take the company private. They said, however, that a merger could still occur in time.
“You could speculate that this agreement is an interim step in combining the companies. But I don’t know if this is a precursor of anything,” said Terry Peters, an analyst at Griffiths McBurney & Partners. “It doesn’t look like it’s imminent.”
If nothing else, the regulatory path has been cleared to the altar. The Canadian government’s Competition Bureau said in November 1999 that it would not challenge a merger because the combined Canadian assets would have little impact on competition other than minor overlaps in the upstream sector.
That leaves ExxonMobil Canada free to pursue its impressive East Coast offshore holdings, including a 50.8 percent stake in the C$3 billion Sable offshore natural gas project, 33 percent controlling position in Newfoundland’s Hibernia oilfield and 22 percent of the Terra Nova oilfield, which comes on stream this spring.
In addition, it is moving ahead with a C$3.1 billion Kearl oil sands mine and upgrader in northern Alberta, aiming to start production at 160,000 barrels per day by 2005. Gulf Canada and the Comeback Kid In 1988, Gulf Canada wanted nothing to do with including its Parsons Lake gas find in the initial Mackenzie Delta-Beaufort Sea export applications filed by Imperial Oil and Shell Canada, which were left to do all of the regulatory work.
Given that background, Gulf Canada has surprisingly led the charge in this latest revival of Arctic hopes.
Maybe even more surprising is that the company has survived at all, after a whirlwind buying spree under J.P. Bryan, a flamboyant Texas financier who embarked on a debt-financed takeover to pull the company from the brink of bankruptcy to a respected international player in the space of three years, then relinquished the reins when Gulf Canada’s C$2.7 billion debt again threatened it with extinction.
The leadership controls passed to Dick Auchinleck, a 24-year Gulf Canada loyalist, who operates with less fanfare than Bryan, even though he is a licensed race car driver who is often seen cruising Calgary streets in a flashy sports car or hurtling across the Baja California desert in a dune buggy.
Auchinleck has righted the ship, unloading global non-core assets to pay down debt, notching major gas discoveries in Indonesia and the British North Sea and quietly pushing ahead with a C$1 billion Alberta oil sands project that the company hopes will produce 100,000 barrels per day from 15 billion barrels of bitumen.
The proof of Gulf Canada’s return to confidence came last October in its friendly C$2.3 billion takeover of Crestar Energy, giving it combined production of 278,000 barrels of oil equivalent per day and landing Auchinleck with the title of Comeback Kid.
“Clearly, we’re back in a growth phase, but we’re going to do it in a very considered way ... one of the mistakes we made in the past was too many, too fast,” he said.
That quiet resolve saw Auchinleck gradually overcome a solid wall of doubt after he emerged in mid-1999 as the lone proponent of reviving Arctic natural gas development. He even set a five-year start-up target. “My peers thought I was clutching at straw,” he remembers.
The critics have since melted into the background, silenced by Auchinleck’s apparent genius in promoting what seemed a wildly ambitious scheme just before gas prices skyrocketed and suddenly made the Far North an economic proposition. With 3.2 trillion cubic feet in permits, Gulf Canada has a big part of its future at stake in the Arctic.
Shell: a silent partner in Canada’s Arctic As with most things, Shell Canada, 78 percent owned by Royal Dutch/Shell Group and holding about C$6.5 billion in assets, is almost a silent partner in Canada’s Arctic, although it holds a 1 trillion cubic foot find at Niglintak in 1973.
Its primary interests are the East Coast offshore and Alberta oil sands, after years of shredding conventional assets and downsizing to 3,700 employees from 5,000-plus under former CEO Charles Wilson, known in the industry as Chainsaw Chuck.
When Mount Everest conqueror Sir Edmund Hillary was asked why he would want to challenge the world’s highest peak, he replied: “Because it’s there.”
That about sums up Shell Canada’s participation in the Mackenzie Delta studies - better to join than quit, although it avoids taking any public profile on Arctic development.
The company’s greater focus is its 31.3 percent stake in the Sable Offshore Energy Project, which is now yielding net production of about 110 million cubic feet per day, about 20 percent of its total gas output. In addition, it produces 23,300 barrels of condensate and 30,100 barrels of liquid petroleum gas per day. Shell Canada has also joined forces with U.S. independent Forest Oil to explore for deep gas in the foothills of the Canadian Rockies.
But the biggest venture on its plate is the C$5.2 billion Athabasca oil sands project - a partnership with Chevron Canada and Western Oil Sands that is scheduled to come on stream in 2002 at 155,000 barrels per day. Petro-Canada: taking a measured approach Petro-Canada verges on an Arctic anomaly, with vast exploration holdings in the Delta that it has bolstered over the last year, plans for the first Delta gas well in about 15 years, but no role in the Delta study consortium, primarily because it was not part of the quartet which obtained National Energy Board export licenses in the late 1980s.
The federal government created Petro-Canada in 1975, financed billions of dollars in takeovers and high-risk frontier exploration, then started to privatize the company in 1995, although it continues to hold 18.2 percent, which it has promised to sell off when share values can generate maximum returns for taxpayers.
In the meantime, Petro-Canada has slashed its payroll to 4,400 from a peak of 11,000, exited Western Canada’s conventional oil plays, taken a starring role in Newfoundland’s Hibernia, Terra Nova and White Rose oilfields, participated in massive expansions in the oil sands and started exploiting Alberta’s prolific Foothills gas corridor.
To round out its frontier portfolio, Petro-Canada, mostly in partnership with Calgary-based independent Anderson Exploration, has been picking up the lion’s share of exploration licenses from federal government and aboriginal land sales awarded over the past 18 months. Petro-Canada and Anderson are now ready to start the first natural gas exploratory well in the region since the 1980s, with a C$44.3 million onshore hole 100 miles northwest of Inuvik.
Even so, Petro-Canada is taking a measured approach to the Arctic, assigning only C$55 million to the area this year from a capital budget of C$1.4 billion, 11 percent greater than last year’s.
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