Marathon Oil (MRO)

underway. The plant should be back on line and manufacturing LNG within the next few weeks. This outage will impact our annualized production volumes by about 7,500 BOEPD and is reflected in the fourth quarter guidance.

In Norway the Alvheim FPSO construction has been completed and commissioning, although taking longer then we expected, is now nearly complete. We expect to sail out of the Haugesund ship yard by Mid-December. We will stop in Amofjord, which is near Stavanger, to install the thrusters and commission the fire water and sea water pumps before sailing to location. First production is expected in the first quarter but is dependent upon having a weather window conducive to safely linking the vessel to the loading bouy.

Our production for the year will fall within the prior guidance of 350,000 to 375,000 BOEPD, but near the low end attributable to these two events.

Now Gary Heminger will make some additional comments.

Thanks Steve. As Clarence mentioned, we closed the Western transaction on October 18, 2007 and yesterday we announced the approval of the Detroit upgrade and expansion project. But before I get into the linkage between these projects, and the value proposition for Marathon, I’d like to welcome Steve Reynish and his team to Marathon. We are excited not only to have the Western assets but we are also pleased to have been able to retain a highly talented staff which Steve will lead as President of Marathon Oil Canada. Steve most recently was the Executive Vice president and Chief Operating Officer of Western and prior to that was the president and Chief Operating Officer of Albian Sands Energy which operates the Muskeg River Mine on behalf of the Athabasca Oil Sands Project (or AOSP) owners. Steve and his team bring valuable knowledge to the operation of the business.

To help investors, analysts and other interested parties better understand our value proposition we’ve prepared the following slides to compare our project with that of a typical Alberta upgrader. I want to emphasize that this example provides an illustrative case of the preliminary and hopefully you will recognize that we have a long way to go in the commercial negotiations around areas such as transportation and so this analysis is not intended as a reflection of our economic case for the project.

Slide 22 provides the relevant assumptions used in the rest of this presentation. While I won’t go over these individually I felt it important that you see what our the base assumptions for this illustrative case are and that they are reasonable, and not based on the much higher crude prices we’ve seen recently or the higher crack spreads refiners had this past summer.

Moving on, slide 23 illustrates the typical value chain moving from bitumen to refined products, using the previously outlined price assumptions. This slide reflects the three value chain options available to a Canadian Heavy Oil producer: selling Dilbit, upgrading to a synthetic crude oil, or gaining access to a refinery with heavy oil capability. As shown here and as further demonstrated in the following slides, the Midwest refinery option clearly provides the highest value.

Moving to slide 24, and using the value chain just demonstrated, the value of linking our AOSP production with our Detroit refinery is further demonstrated. This slide reflects the margin value of a Midwest refinery heavy oil upgrading solution on a bitumen basis. Starting with a 70/30 blend or 1 barrel of Bitumen and 0.43 barrels of diluents and using the previously stated price assumptions, adding $10.00 per barrel transportation and refinery expenses, this refinery feedstock of 1.43 barrels is then converted into finished products valued at approximately $94.60. The result of this value chain is a margin of $21.74 per barrel of bitumen.

Slide 25 reflects the margin value calculation of a typical Alberta upgrader. This option also starts with 1 barrel of bitumen but the diluent is recycled to the mine for repeated blending purposes. Other blend stocks of approximately 0.21 barrels are necessary to optimize the upgrader option. It is estimated that total costs, including feedstocks and blendstocks, transportation, opex and overhead  are approximately $13.61 per barrel of bitumen. The resulting blend of products reflects a yield of approximately 103% as a

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result of the expansion that occurs during upgrading to the bitumen barrel. The product output of the upgrader consists of a mix of premium synthetic crude oil, vacuum gas oil and heavy synthetic crude oil which yields $63.44 of revenue for every barrel of bitumen processed resulting in an operating margin of $19.54 per barrel of bitumen.

Slide 26, with a side-by-side comparison, illustrates the total value advantage of a Midwest refinery heavy oil upgrading solution when compared to an Alberta upgrader using the stated assumptions. As illustrated on the previous slides, there is an operating margin advantage of approximately $2.20 per barrel. In addition, as shown here, we estimate there is an additional value of approximately $1.25 per bitumen barrel when taking capital costs into consideration. This calculation imputes a market value for a base refinery to truly reflect comparable costs. In total, we believe Marathon’s integrated solution has approximately a $3.50 per bitumen barrel competitive advantage to upgrading at the field level. And with this solution, we are supplying refined product directly to a market that currently has excess demand.

And of course, we are still in the early days of our Canadian oil sands project and will continue to explore our options for gaining value from this asset. We continue to look at other potential long-term refining solutions within our network. And we look forward to working with our partners on the promising future of the AOSP project, including discussions about technology opportunities and options for optimizing the value of the current upgrader.

Let me finish by taking a few minutes to remark on the Alberta Royalty changes outlined in Premier Stelmach’s address last week. While we would have preferred that there would have been limited changes to the royalty regime, we believe there is minimal effect based on the pricing assumptions we used. It is disappointing the royalty will graduate with oil prices and this may limit upside and future capital spending. We will obviously continue to study and follow the open items still being discussed in the province pertaining to bitumen upgrading.

We are confident Marathon will deliver a superior competitive solution through the integration of the oil sands with our refining system. We will update you as we continue down the path of this integration.

Now I’ll turn the call back to Ken.