Imperial CEO doesn't think Mackenzie pipeline is dead
Imperial Oil Ltd. does not believe depressed natural gas prices have closed the door on the $16.2-billion Mackenzie pipeline project in Canada’s Far North, and the company still hopes for a financial deal with Ottawa to make it viable, its chief executive officer said on Wednesday.
Even so, a surge in costs and a major shift in North American gas markets during the seven years it took Imperial and its partners to win approval for the pipeline show the need for the federal government to reform its regulatory process, CEO Bruce March said.
Joe Oliver, Canada’s Natural Resources Minister, has made streamlining approvals a priority, aiming to support the industry’s goal to boost energy exports. Legislative and regulatory changes could form part of the federal Conservative government’s March 29 budget.
Environmentalists fear the moves, expected to include binding time limits for assessments, might limit the ability of project opponents to participate in public hearings.
Imperial, which is the Canadian affiliate of Exxon Mobil Corp., and the government resumed talks last year over a multibillion-dollar support package for Mackenzie. It would provide funding for roads, airstrips and other infrastructure in the sparsely populated and largely undeveloped Northwest Territories.
“We haven’t been able to achieve that yet. We continue to be hopeful and work that, but [there is] nothing more specific to talk to you about than that right now,” Mr. March told reporters following a company-sponsored investor meeting.
The pipeline, which would carry up to 1.2 billion cubic feet of gas to southern markets from the Mackenzie Delta on the Beaufort Sea coast, is several years behind schedule.
It won regulatory approval more than a year ago, but questions surround its viability given high construction costs and uncertain returns due to weak gas markets as the industry develops cheap shale gas reserves across the continent.
Last year, the proposal suffered another blow when one of the partners, Royal Dutch Shell PLC, put its stake up for sale. It has yet to announce that it has found a buyer.
Even so, Imperial is not planning the project based on today’s gas prices, but more on expectations for the 2018-2020 time frame, Mr. March said. The company sees rising demand for the fuel in the coming years as prices languish and more is used as a lower-carbon source for power generation.
“It’s fair to say that the developments in North American natural gas, certainly, are understood, and there are lessons learned there and it certainly factors into our thinking going forward. But we would never be thinking about the viability of Mackenzie with the current-day gas price,” he said.
“Again, we remain hopeful, and I wouldn’t say that the time for Mackenzie has passed.”
The Northwest Territories government and communities along the proposed route have waited for years for economic opportunities to flow from the project.
Imperial’s other partners are ConocoPhillips, Exxon Mobil and Aboriginal Pipeline Group.
Among Imperial projects that are under way, the $10.9-billion Kearl oil sands development in Alberta, a joint venture with Exxon Mobil, is 89-per-cent complete. It is on track to start producing 110,000 barrels a day of bitumen by the end of this year, Glenn Scott, president of the company’s resources division, said.
Eventual output is slated to hit 345,000 bpd by 2020, part of the company’s plans to double overall output by that year.
Mr. March said business for the company’s easternmost refinery, the 82,000-barrel-per-day plant in Dartmouth, N. S., is under pressure from the same factors that have hit other refineries along the Atlantic coast of North America.
Several companies have shut Atlantic basin facilities due to low margins as Brent-based oil prices surge compared with North American benchmark crudes. The latest is Valero Energy Corp., which said this week it will shut its 235,000 bpd Aruba refinery by the end of March.
“In the case of Dartmouth, there is nothing specific to update you on now. We’ve done studies of its long-term viability several times over the past couple of decades. This current environment is a difficult one – you’ve seen decisions by other competitors in the Atlantic basin,” he said. “But (we have) nothing specific to talk about today.”
Even so, a surge in costs and a major shift in North American gas markets during the seven years it took Imperial and its partners to win approval for the pipeline show the need for the federal government to reform its regulatory process, CEO Bruce March said.
Joe Oliver, Canada’s Natural Resources Minister, has made streamlining approvals a priority, aiming to support the industry’s goal to boost energy exports. Legislative and regulatory changes could form part of the federal Conservative government’s March 29 budget.
Environmentalists fear the moves, expected to include binding time limits for assessments, might limit the ability of project opponents to participate in public hearings.
Imperial, which is the Canadian affiliate of Exxon Mobil Corp., and the government resumed talks last year over a multibillion-dollar support package for Mackenzie. It would provide funding for roads, airstrips and other infrastructure in the sparsely populated and largely undeveloped Northwest Territories.
“We haven’t been able to achieve that yet. We continue to be hopeful and work that, but [there is] nothing more specific to talk to you about than that right now,” Mr. March told reporters following a company-sponsored investor meeting.
The pipeline, which would carry up to 1.2 billion cubic feet of gas to southern markets from the Mackenzie Delta on the Beaufort Sea coast, is several years behind schedule.
It won regulatory approval more than a year ago, but questions surround its viability given high construction costs and uncertain returns due to weak gas markets as the industry develops cheap shale gas reserves across the continent.
Last year, the proposal suffered another blow when one of the partners, Royal Dutch Shell PLC, put its stake up for sale. It has yet to announce that it has found a buyer.
Even so, Imperial is not planning the project based on today’s gas prices, but more on expectations for the 2018-2020 time frame, Mr. March said. The company sees rising demand for the fuel in the coming years as prices languish and more is used as a lower-carbon source for power generation.
“It’s fair to say that the developments in North American natural gas, certainly, are understood, and there are lessons learned there and it certainly factors into our thinking going forward. But we would never be thinking about the viability of Mackenzie with the current-day gas price,” he said.
“Again, we remain hopeful, and I wouldn’t say that the time for Mackenzie has passed.”
The Northwest Territories government and communities along the proposed route have waited for years for economic opportunities to flow from the project.
Imperial’s other partners are ConocoPhillips, Exxon Mobil and Aboriginal Pipeline Group.
Among Imperial projects that are under way, the $10.9-billion Kearl oil sands development in Alberta, a joint venture with Exxon Mobil, is 89-per-cent complete. It is on track to start producing 110,000 barrels a day of bitumen by the end of this year, Glenn Scott, president of the company’s resources division, said.
Eventual output is slated to hit 345,000 bpd by 2020, part of the company’s plans to double overall output by that year.
Mr. March said business for the company’s easternmost refinery, the 82,000-barrel-per-day plant in Dartmouth, N. S., is under pressure from the same factors that have hit other refineries along the Atlantic coast of North America.
Several companies have shut Atlantic basin facilities due to low margins as Brent-based oil prices surge compared with North American benchmark crudes. The latest is Valero Energy Corp., which said this week it will shut its 235,000 bpd Aruba refinery by the end of March.
“In the case of Dartmouth, there is nothing specific to update you on now. We’ve done studies of its long-term viability several times over the past couple of decades. This current environment is a difficult one – you’ve seen decisions by other competitors in the Atlantic basin,” he said. “But (we have) nothing specific to talk about today.”
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