Selected Annual Financial Information

1. Trust Unit information has been adjusted to reflect the 5:1 Unit split that occurred on May 3, 2006
2. Long-term debt less cash and cash equivalents.
3. Includes employee future benefits and other liabilities as well as the asset retirement obligation.

In order to provide meaningful information to our Unitholders, the focus of our MD&A is to provide explanations of material variances in our financial results and significant events that have occurred since December 31, 2005. Canadian Oil Sands considers material information to be any information relating to the business of the Trust and its subsidiaries that would reasonably be expected to have a significant influence on an investor’s investment decision. We believe users of our financial results consider material information to be that which impacts the Trust’s net income, net income, cash from operating activities and free cash flow, which is available for distribution to Unitholders, for reinvestment in growth through expansions or acquisitions, or for repayment of debt. We endeavour to identify and provide in our MD&A, financial statements, and guidance documents on a timely basis and in an understandable form, the factors that impact our net income, cash from operating activities and free cash flow, namely: crude oil prices, production and sales volumes, our SSB net realized selling prices relative to WTI prices, hedging impacts, costs of operations, financing costs, capital and other relevant costs.

In each of 2006, 2005 and 2004, the financial results of Canadian Oil Sands reflect a 35.49% working interest in the Syncrude Joint Venture. The financial results do not include the additional 1.25% working interest acquired by Canadian Oil Sands from Talisman Energy Inc. (“Talisman”) on January 2, 2007. All Trust unit (“Unit”) information has been adjusted to reflect the 5:1 Unit split, which occurred on May 3, 2006. In the last half of 2006, Canadian Oil Sands acquired Canadian Arctic Gas Ltd., formerly Canada Southern Petroleum Ltd. (“Canadian Arctic”). The results of operations related to Canadian Arctic’s conventional oil and gas assets are reflected in “Loss from discontinued operations” on the Trust’s Consolidated Statement of Income and Unitholders’ Equity.

An important change in this MD&A compared to that of prior years is that we now are discussing “cash from operating activities”, as per the Trust’s Consolidated Statements of Cash Flows, as our measure of the Trust’s ability to generate cash from operations. Previously Canadian Oil Sands reported “funds from operations”, which did not include changes in non-cash working capital from operating activities and was not considered a Canadian generally accepted accounting principles (“GAAP”) measure. Cash from operating activities provides similar information to funds from operations and better comparability to other reporting entities as it is a GAAP measure.

Revenues, after crude oil purchases, transportation and marketing expense, reflect the additional Stage 3 volumes that came on stream in August 2006, supported by a higher average realized selling price for our SSB product. Canadian Oil Sands’ daily sales volumes averaged approximately 91,800 barrels, an increase of 21% compared to 2005, and of 9% over 2004. Prior to 2006, Syncrude’s highest production levels were in 2004, reflecting an unusual year without a coker turnaround. Comparatively, Coker 8-1 and Coker 8-2 underwent turnarounds in 2006 and 2005, respectively. As well in 2005, sulphur plant pump problems, maintenance activity on the heavy gas oil hydrotreaters, the vacuum distillation unit shutdown and throughput restrictions all served to reduce production in that year.

An increase in the average realized selling price reflects similar increases in WTI prices, which averaged US$66.25 per barrel, US$56.70 per barrel, and US$41.47 per barrel in each of 2006, 2005 and 2004, respectively. The full impact of the higher 2006 WTI benchmark price was not realized in 2006 due to a weakening of the SSB price differential to WTI as well as a strengthening of the Canadian dollar relative to the U.S. dollar, which averaged $0.88 US/Cdn in 2006, up from $0.83 and $0.77 in 2005 and 2004, respectively. In 2006, our SSB product traded at an average discount of $2.57 per barrel to Canadian dollar WTI prices compared with a premium of $1.05 per barrel in 2005 and a discount of $1.53 per barrel in 2004. We believe the movement in the differential primarily reflects varying supply levels of light synthetic crude oil from a number of producers over the past three years. Supply rose as additional production came on stream from new oil sands projects, including Syncrude’s Stage 3 expansion, and decreased during periods when producers were going through turnarounds or experiencing difficulties in their production facilities.

The increase in revenues, after crude oil purchases, transportation and marketing expense, was the primary reason for the overall increase in net income and cash from operating activities in 2006 compared with the two prior years. However, partially offsetting the increase in 2006 revenues were increases to Crown royalties, operating costs, depreciation, depletion and accretion (“DD&A”) expense, and future income tax expense, combined with lower foreign exchange gains relative to both 2005 and 2004. The increase in DD&A and future income tax expense and the reduction in the unrealized portion of the foreign exchange gains in 2006 reduced the Trusts’ net income, but did not impact cash from operating activities. Crown royalties rose to $232 million, or $6.93 per barrel in 2006, reflecting the shift in May 2006 to the higher royalty rate of 25% of net revenues compared to the minimum 1% of gross revenues that had been in place for 2005 and 2004, which resulted in Crown royalties of $19 million, or $0.71 per barrel, and $18 million, or $0.58 per barrel, in each of those years, respectively.

Operating costs were $907 million, or $27.07 per barrel, in 2006, compared with $731 million, or $26.34 per barrel in 2005, and $601 million, or $19.40 per barrel in 2004. Equipment and staff to support Syncrude’s Stage 3 operations were in place throughout 2006, although production from the new facilities was not established until the end of August 2006, which contributed to higher production costs of $20.97 per barrel, compared to $19.25 per barrel and $15.16 per barrel in 2005 and 2004, respectively. Purchased energy accounted for $6.10 per barrel of the total operating costs, slightly lower than $7.09 per barrel in 2005, but higher than $4.24 per barrel recorded in 2004. While the cost of natural gas was comparable in each of 2006 and 2004 at approximately $6 per gigajoule (“GJ”), consumption per barrel in 2006 was substantially higher, reflecting larger volumes being mined at the Aurora mine, which relies mainly on purchased gas for its energy needs, as well as increased use of purchased natural gas while the Stage 3 facilities were being brought on-line compared to 2004. Purchased energy costs were higher in 2005 than both 2006 and 2004, primarily reflecting an average natural gas price of $8.40 per GJ.

DD&A expense increased in 2006 relative to the two prior years because of a higher depreciation and depletion (“D&D”) rate and larger production volumes. The per barrel D&D rate was $7.34, $6.11, and $5.50 in each of 2006, 2005 and 2004, respectively, as a result of increasing Stage 3 capital costs and higher future development costs. Unrealized foreign exchange gains were $1 million in 2006, a decrease of $35 million and $88 million compared to 2005 and 2004 as the Canadian dollar strengthened more in 2005 and 2004, resulting in larger gains in each of those years. Future income tax reduced net income by $18 million in 2006 compared to a reduction of only $1 million in 2005 and an increase of $27 million in 2004.

Total assets continued to increase significantly in 2006 compared to 2005, reflecting a build in the Trust’s cash balance of $265 million at year-end, of which $237 million was paid to Talisman on January 2, 2007 to satisfy the cash component of the additional Syncrude interest acquisition. Capital assets increased by $237 million, reflecting both capital expenditures for our share of Syncrude’s capital program in excess of depreciation and depletion, as well as the acquisition of the Arctic gas properties of Canadian Arctic during 2006. The Canadian Arctic acquisition increased capital assets by $165 million and goodwill by $52 million. In 2005 and 2004, our share of Syncrude’s capital expenditures, largely related to the Stage 3 capital program, increased capital assets by approximately $800 million and $942 million, respectively. Accounts receivable rose at December 31, 2006 due to the higher SSB sales volumes and sales price, compared to December 31 in each of 2005 and 2004.

Total other long-term financial liabilities rose substantially at the end of 2006 and 2005 compared to 2004 year-end mainly due to an increase in the asset retirement obligation (“ARO”) in 2006 and 2005. Each of the Syncrude owners are liable for their share of ongoing environmental obligations for the ultimate reclamation of the Syncrude project. The ARO represents the present value estimate of Canadian Oil Sands’ share of these costs, which, as at December 31, 2006, increased to $173 million from $148 million and $44 million at year-end 2005 and 2004, respectively.

Syncrude’s undiscounted estimate of the total cash flows required to settle the Trust’s share of the obligation rose to $595 million at December 31, 2006 from $525 million at December 31, 2005 and $275 million at December 31, 2004. The increases in 2006 and 2005 from 2004 are mainly the result of revised assumptions regarding the volume of reclamation material required and the costs associated with storing and handling the additional material. Cost escalation associated with revegetation, landforming, and additional regional drainage requirements also contributed significantly to the estimate increases. In addition, adjustments totalling $37 million were recorded in 2005 to correct the Trust’s ARO balance.

Cost escalation, particularly as a result of inflationary pressures in the Fort McMurray area, has been a significant trend that has arisen over the last few years. The Trust’s D&D rate, ARO, operating and capital costs have all been impacted by higher cost of materials and services and the associated costs of labour shortages. We anticipate these inflationary pressures will continue in light of the significant level of oil sands activity that is expected, particularly over the next three years as the other major oil sands projects are completed.

Net debt at December 31, 2006 decreased to $1.3 billion from $1.6 billion at December 31, 2005 as a result of a larger cash balance at year-end and repayment of amounts owing on the Trust’s credit facilities in 2006 compared to the prior year-end. Net debt at December 31, 2005 fell slightly from December 31, 2004 as funds from operations in 2005 were more than sufficient to cover capital expenditures and distributions, and a stronger Canadian dollar reduced the carrying value of our U.S. dollar denominated long-term debt.