Imperial Oil Files for Regulatory Permits for the Mackenzie Gas Project

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Researched by Industrialinfo.com (Industrial Information Resources, Incorporated; Houston, Texas). Imperial Oil Limited (AMEX: IMO) (Toronto, Canada) has formally begun the regulatory process for its Mackenzie Gas Project (MGP) by filing a full application with the NEB and other government entities responsible for regulating energy developments in the Northwest Territories. A subsidiary of Imperial Oil, Imperial Oil Resources, on behalf of the MGP proponents filed the application on October 7, 2004, after a lengthy internal review process and expects it will take up to two or more years to complete the permitting process.

The MGP is a proposed 1,220 kilometer, 30" diameter natural gas pipeline originating above the Arctic Circle in the Mackenzie River delta and travels in a south-southeast direction and terminates at an interconnect with the existing gas pipeline system just across the Alberta border. The capacity for the pipeline depends on which scenario is chosen, whether it is the base case with 1.2 Bcf/d, or the expanded case with 1.9 Bcf/d or the reduced case with .8 - 1 Bcf/d. A final case will be selected when the three anchor fields have had their depletion schemes defined and when it is decided whether other producers will join the project.

The three anchor fields located in the vicinity of Inuvik, Northwest Territories, will supply approximately 800 mmscfd of natural gas to the project. The anchor fields are Niglintgak, Taglu, and Parsons Lake. The Taglu field, discovered in 1971 and owned by Imperial Oil is the largest of the Anchor fields, with three Tcf of natural gas in place. Second largest, discovered in 1972, is the Parsons Lake Field with 1.8 Tcf, which is owned 75% by ConocoPhillips (NYSE: COP) (Houston Texas) and 25% by ExxonMobil (NYSE: XOM) (Irving, Texas). Third is the Niglintgak field, discovered in 1973, with a reserve of one Tcf and owned by Shell Canada (TSE: SHC) (Calgary Alberta). Each field will need onsite power generation of between 4-10 megawatts apiece, due to the remote region the projects lie in. Field compression will require between 15,000 - 30,000 horsepower of turbine-driven compression per field. All three fields are within 120km of Inuvik and will be tied to a central processing and compression facility there. At Inuvik, depending on the case chosen, there would be either 12,000, 20,000, or 34,000 barrels per day of NGL's separated out and pumped through a new 480km, 10"-diameter pipeline from Inuvik to Norman Wells, where it will interconnect with an existing pipeline owned by Enbridge Incorporated (NYSE: ENB) (Calgary, Alberta). In the base and reduced cases, the pump units would be located at the Inuvik facility, but in the expanded case there would be a need for three new pump stations.

The amount of compression, as with most other facilities, would again vary, depending on the case selected. All compression would be turbine based, and each facility would have its own internal power generation facilities. In the most probable base case, compression would be supplied by the Inuvik facility and five other planned compressor stations, and would total 109,000 horsepower. In the expanded case, fifteen compressor stations would be constructed, and a total of 278,000 horsepower would be installed. In the least likely reduced case, a mere 57,000 horsepower of compression would be needed.

Imperial Oil, as leader of the consortium, retained the services of Colt Engineering Corporation (Calgary, Alberta) for the conceptual engineering and expects it will take a three-winter construction program to complete the project in either late 2009 or early 2010. Multiple engineering companies will be employed for some time on this project and will share in the estimated $150 million in engineering and project management income. The MGP will have an estimated operating lifetime of 25 years and will carry an initial capital cost, for the base case project, of approximately $3.5 billion in 2003 dollars.

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