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Make-or-break Mac budget Imperial doubles gas line cost projections, stalls work pending fiscal negotiations By Gary Park For Petroleum News
The Mackenzie Gas Project is now, beyond much doubt, on the verge of put-up-or-break-up decisions by government and corporate participants.
In laying out what figures to be the final working budget for producing gas from Canada’s northern regions, lead partner Imperial Oil estimated the cost of a main pipeline, gathering system and development of the three Mackenzie Delta anchor fields at C$16.2 billion.
That makes nonsense of the Mackenzie partners’ 2004 forecast of C$7.5 billion and consensus among analysts that the long-awaited revised budget would likely end up close to C$10 billion.
(The cost of developing the anchor fields is now pegged at C$4.9 billion, up from C$1.53 billion, including C$1.1 billion for future drilling and other spending to sustain production beyond the startup; the gathering facilities have climbed to C$3.5 billion from C$1.7 billion, while the Mackenzie Valley pipeline has hurtled to C$7.8 billion from C$3.66 billion).
“I don’t think it’s dead, but this doesn’t look good,” said Northwest Territories Industry Minister Brendan Bell. “The good news is that we now have cost certainty; the bad news is that the costs are so high.”
Imperial attributed the increase to its better grasp on project execution, inflation in the cost of materials, equipment and labor, and delays in the regulatory process.
Other alternatives evaluated Arriving at the new numbers included evaluating other alternatives — converting Delta gas into liquid natural gas; dropping a Mackenzie Valley pipeline in favor of a route along the Dempster Highway to connect with an Alaska pipeline in the Yukon; and scrapping a proposed gas liquids pipeline from the Delta to Norman Wells, where it would feed into Enbridge’s underutilized crude line to northern Alberta.
The conclusion from “leaving no stone unturned,” said Imperial Senior Vice President Randy Broiles, was that a Mackenzie Valley pipeline “continues to be the leading case.”
Although the immediate response from the partners to the new estimate was to stop new field work and new detailed engineering until the Canadian government provides “some indication” of the fiscal terms it is prepared to offer, Broiles was adamant the project is “not on hold.”
With costs already over C$600 million, he said it made sense to complete the regulatory process and negotiations with the federal government.
What kind of agreement the MGP can strike with Ottawa now shapes up as pivotal to the future of northern gas for this generation.
By late 2005, the potential value of federal support was thought to be C$1.2 billion.
Broiles agreed the number is “now greater,” without providing a figure.
Imperial sees four matters as key He listed four matters that Imperial views as key to any bargaining success:
• A depreciation rate that is tied to the economic life (the three anchor fields have an estimated reserve life for their 5.8 trillion cubic feet of 15 years) rather than the physical life of the project (the pipeline is figured to be good for 30 years);
• Federal commitments to supply gas from third-party sources to support a one-third equity stake in the pipeline by the Native-owned Aboriginal Pipeline Group;
• Risk-sharing tools that would see government revenues rise in lock-step with higher gas prices; and
• Sharing C$1 billion to C$2 billion worth of building roads, airports, work camps and barge landings — all investments that could benefit other resource development in the NWT.
Bell said now that Imperial has provided some “cost certainty” — although the magnitude of the cost increase was much higher than anticipated — his government, Ottawa and Imperial can enter serious negotiations on a fiscal regime.
Bell has no question that there is a role for the Canadian taxpayer, particularly to support shipping commitments and loan guarantees to ensure the APG can be a partner in the project.
He said the fact that Imperial has consistently made the case that there is more space available on the planned pipeline than there is gas available from the anchor fields requires the federal government to find a way to fill that spare capacity.
If the APG is to become a stakeholder, there must also be a resolution of the impasse between the MGP and the Mackenzie Explorer Group, which already claims to have 175 million cubic feet per day of production available for the pipeline, but has been unable to strike a deal with the MGP for “fair and reasonable” access to the pipeline.
NEB permits expected in 2008 On the regulatory front, Broiles said National Energy Board permits should be obtained in 2008, allowing corporate sanctioning and contracts to be awarded in 2009 for a four-year construction start in 2010.
Along with the new budget numbers, Imperial said the first gas would not move before 2014, at least three years behind the old schedule.
Repeating Imperial’s consistent refrain, Broiles said gas from Canada’s North and Alaska’s North Slope both represent “significant vital new supply sources.”
Although progress in Alaska has also been slowed, he said the “fundamental principle here is that North America needs the gas from both projects.”
At the same time, the Mackenzie must be able to compete with other global supply opportunities and the partners remain concerned about the project’s “competitiveness,” Broiles said.
Remarks such as those underlie a persistent belief among some observers that the MGP partners — Imperial (69.6 percent owned by ExxonMobil), Shell Canada, ConocoPhillips Canada and ExxonMobil Canada — will be content to obtain regulatory approvals, then direct their spending to more profitable ventures around the world.
Concern about when project would start Such a prospect prompted NWT Premier Joe Handley and Nunavut Premier Paul Okalik to suggest recently that Ottawa should impose a “sunset clause” on frontier developments, requiring construction to start within two years of regulatory approvals.
Their worry is that the partners could receive project certification and sit on the assets, preventing others from developing the resource.
Broiles said the co-venturers “expect double digit returns on this type of investment and we’re not anywhere near that right now.” He wouldn’t say how big the gap is or what gas price is being used as a yardstick.
Andrew Potter, an analyst with UBS Securities Canada, calculated that achieving a 10 percent after-tax return would need gas prices of US$7.75 per thousand cubic feet, well above current levels and likely much higher than Imperial’s price outlook.
Chris Theal, an analyst with Tristone Capital, told the Financial Post that getting the MGP “over the goal-line” will depend on big infrastructure subsidies, favorable accounting and possibly even tax relief.
“Do we, as Canadians, want government funding that sort of thing?” he asked.
Aside from financial help, Imperial said 10 percent of the cost escalation reflects complexity and delays in both regulatory and the access processes, according to company spokesman Pius Rolheiser.
Even if the NEB gives the green light, up to 7,000 permits will be required, all of which contributed to the altered timetable.
“Timely actions by all parties, including the proponents, governments and regulators, will be required to achieve (the 2014) schedule,” Imperial said in a letter to the NEB.
But Broiles was confident that the “right fiscal framework” would make the MGP economic at C$16.2 billion.
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