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Arctic ‘exciting’ prospect Outgoing Imperial CEO says ‘lots of ways’ to proceed with Mac gas project Gary Park For Petroleum News
The Arctic is part of an “exciting” exploration program for Imperial Oil, Canada’s largest integrated oil company, but whether and in what form the Mackenzie Gas Project will fit into that scheme of things remains a question mark.
That was the basic message delivered in a top-level change of power when outgoing Chief Executive Officer Tim Hearn handed the controls to Bruce March.
The only hint of a possible change in the Mackenzie structure came from Hearn when he was asked about reports that TransCanada might take control of the construction, ownership and operation of a Mackenzie Valley pipeline from Inuvik, Northwest Territories, to northern Alberta.
“There are lots of ways to go forward,” he said. “One way or another we are going to be involved.
“How this thing gets constructed and put together and ultimately financed, I think will sort itself out over time.”
Leaving the full range of doors open, he said: “Sometimes we own a pipeline and sometimes we don’t.”
Hearn said Imperial is “not committed to a one size fits all on this thing. We are really trying to find a way to make this work for everyone — government of Canada, peoples of the North, producers, consumers. If we can do that it will be an excellent outcome.
“It’s something that should get done in our country. We’ll see if it can,” he said.
Imperial tightlipped For now, Imperial is keeping tightlipped about the status of discussions with the Canadian government on fiscal terms for the Mackenzie project.
Company spokesman Pius Rolheiser told Petroleum News the discussions continue, but the details and the progress remain confidential.
It is now more than three months since a reworked financial plan aimed at improving the project economics was submitted to Canada’s Industry Minister Jim Prentice, who promised to “analyze and review (the proposal) as expeditiously as possible.”
Since then there has been a wall of silence around the government’s deliberations, possibly reflecting Prentice’s determination to prevent any leaks.
He was reportedly annoyed last year when stories circulated that the federal government was on the verge of taking an equity position in the project.
The longer the process has dragged on the more questions have been raised about the level of Imperial’s commitment, despite Hearn’s assurances that the company is serious about getting Arctic gas to market.
Sale of property Just how edgy things are was evident recently when Bloomberg News carried a story that Imperial was offering to sell a 50 percent stake in an unexplored property near Parsons Lake, one of three anchor fields underpinning the Mackenzie project.
Rolheiser was emphatic that the offering in no way indicated that Imperial was losing interest in the project.
In fact, the sale process for the property started in 2004.
Rolheiser pointed out that the 10,000 acres, covered under Significant Discovery License 62, covers a “much smaller” area than the two SDLs at the adjacent Parsons Lake discovery of 1.8 trillion cubic feet that is owned 75 percent by ConocoPhillips Canada and 25 percent by Imperial’s sister company, ExxonMobil Canada.
The other anchor fields are Imperial’s wholly owned Taglu field with 3 tcf and Shell Canada’s 1 tcf Niglintgak field.
SDL 62 was awarded on the basis of seismic work and a “reasonable assumption” of the reservoir that could exist in the area, but no drilling has occurred to establish the reserves, Rolheiser said.
He said it is not an economic proposition for Imperial to spend the money to significantly increase its geological understanding of the SDL.
A number of exploration prospects Of Imperial’s future directions, March said Hearn has “left big shoes to fill … coming in as a successor, it’s a little bit difficult to see a path forward to improve much” — a view shared by many analysts who note that Imperial has a strong balance sheet and little debt as it embarks on a number of megaprojects.
On that list is an exploration plan for a 508,000 acre permit in the Beaufort Sea, acquired last year by joint venture partners Imperial (69.6 percent owned by ExxonMobil) and ExxonMobil Canada for a C$525 million work commitment.
Other exploration prospects include the Athabasca oil sands region of northeastern Alberta and the deepwater Orphan Basin offshore Newfoundland.
“We are really encouraged by all of those,” said March. “What you see with Imperial is a kind of pipeline of opportunities that are in some stage or form over some 15 or 20 years.”
New technologies In the forefront of Imperial’s plans is the development of new technologies to raise the recovery rate at its Cole Lake bitumen operation above 50 percent; it started out at 11-12 percent and has reached 25 percent.
Hearn said new technology is being introduced to exceed 30 percent and “some exciting stuff” that will go through a pilot test over the coming year could push the number over 50 percent.
Imperial’s target for Cold Lake is 180,000 barrels per day, up 26,000 bpd from its fourth quarter 2007 average.
March, with extensive experience as an ExxonMobil refining executive, hinted that the second and third phases of Imperial’s massive Kearl oil sands mining project could incorporate an upgrader to convert bitumen into synthetic crude for later refining.
Kearl is on track to meet its revised startup date of 2011, producing an initial 100,000 bpd at a cost of C$8 billion, although it must first resolve a court challenge to its environmental approvals.
If the project moves ahead it will phase in two more stages of 100,000 bpd each, a time when March said the company may consider adding an upgrader to the operation.
Final refining could take place at Imperial’s own Canadian refineries, at other Canadian facilities, at upgraders in the northeastern Alberta region or by shipping the heavy sour oil into the United States, where ExxonMobil refineries are hungry for heavy crudes.
No shipment to Asia But March said Imperial has no thoughts of using pipelines to the British Columbia coast for tanker shipment to Asia, noting that Kearl-type production can only be refined in North America.
Upgrading decisions are a problem for all major oil sands producers, compounded by the Alberta government’s determination to keep more of the “value-added” end of the business in the province.
Rob Routs, a Royal Dutch Shell refining executive, told analysts in March that rather than upgrading in Canada, his company is examining its options “across North America,” just as its competitors EnCana and Husky Energy have done in joint ventures with ConocoPhillips and BP, respectively.
Shell, which aims to produce 770,000 bpd from its Alberta mining leases, could expand its Edmonton-area refinery, build a new 150,000-200,000 bpd refinery in Ontario and upgrade its US refining system in the Gulf Coast or California, as well as export to markets in the Pacific Rim region, he said.
Routs said the final decisions will be “guided by capital intensity, market access and transportation costs, taking into account the evolving market and regulatory environment.”
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