Canadian Oil Sands Press Releases

Canadian Oil Sands Trust Announces 2010 Second Quarter Results

Thu, 29 Jul 2010 17:47:00 -0400

CALGARY, ALBERTA -- (MARKET WIRE) -- 07/29/10 -- All financial figures are unaudited and in Canadian dollars unless otherwise noted.

Canadian Oil Sands Trust (TSX: COS.UN) ("Canadian Oil Sands", the "Trust" or "we") today announced second quarter 2010 cash from operating activities of $358 million, or $0.74 per Unit, compared with cash used in operating activities of $44 million, or $0.09 per Unit, for the same quarter in 2009. The increase was due to higher revenues during the second quarter of 2010 compared with 2009, partially offset by higher Crown royalties. Year-to-date cash from operating activities increased to $667 million for 2010 from $6 million in 2009. The increase was mainly due to higher revenues, partially offset by higher Crown royalties.

Net income for the second quarter of 2010 was $237 million, or $0.49 per Unit, compared with $46 million, or $0.10 per Unit, recorded in the second quarter of 2009. Net income was also higher in the first six months of 2010 than in the same period of 2009, totaling $404 million, or $0.83 per Unit, versus $89 million, or $0.18 per Unit. The increases in net income primarily reflect higher revenues partially offset by higher Crown royalties and foreign exchange losses.

The Trust has declared a distribution of $0.50 per Unit payable on August 31, 2010 to Unitholders of record on August 23, 2010. The $0.50 per Unit third quarter distribution reflects the Trust's objective of increasing tax pools to approximately $2 billion by the end of 2010, which may raise debt levels if achieved. As a result of this strategy, in 2010 the Trust expects distributions to exceed cash from operating activities less its capital expenditures. Beyond 2010, the Trust will look to avoid significant increases in net debt in advance of a larger sustaining capital program and future expansion plans. As we have done in the past, we will use cash from operating activities as a source of investment financing. Our anticipation of an increase in capital expenditures, therefore, indicates a reduction in distributions in order to reinvest in our business post-2010. Further information about Canadian Oil Sands' approach to distribution/dividend payments is further described under "Unitholder Distributions" in the Management's Discussion and Analysis ("MD&A") section of this report.

"Production at Syncrude was strong during the second quarter of 2010, averaging 324,000 barrels per day," said Marcel Coutu, President and Chief Executive Officer. "We were expecting these robust rates to continue into the third quarter, however, unplanned outages, particularly recent outages in the upgrader during July, have led us to reduce our 2010 annual production outlook by five million barrels for Syncrude to 110 million barrels. While these outages have all been remedied, the resulting production impact illustrates why the current focus on reliability is paramount and key to achieving design capacity of 350,000 barrels per day."

During the second quarter of 2010, Canadian Oil Sands' sales volumes averaged approximately 119,000 barrels per day compared with 76,000 barrels per day for the second quarter of 2009. For the first half of 2010, sales volumes averaged about 109,000 barrels per day compared to an average of 89,000 barrels per day during the comparable period in 2009. Sales volumes for 2010 reflect: the turnaround of the LC Finer and associated upgrading units, unplanned maintenance on a hydrotreater in the first quarter, and unplanned repairs and maintenance on two diluent recovery units in the second quarter. By comparison, sales volumes for 2009 were impacted by: the Coker 8-3 turnaround, circulation issues in Coker 8-1, reliability issues in mining and upgrading operations, and constrained bitumen production during the first quarter.

Canadian Oil Sands' operating costs were $336 million, or $31.18 per barrel, in the second quarter of 2010, compared to $345 million, or $50.23 per barrel, in the same quarter of 2009. The decrease in operating costs was primarily due to lower turnaround costs and stock-based compensation expenses in the second quarter of 2010, partially offset by additional mining activities to support higher production levels and additional unplanned repairs and maintenance. Lower per barrel operating costs also reflect the increased sales volumes in 2010.

The Syncrude Joint Venture's ("Syncrude") total recordable injury rate year-to-date for 2010 was 0.40 compared with a rate of 0.37 for the same period of 2009. Strong safety performance for Syncrude is a priority with efforts focused on achieving an injury-free workplace.


CANADIAN OIL SANDS TRUST
Highlights

(millions of Canadian dollars,       Three Months Ended    Six Months Ended
 except per Trust Unit and per                  June 30             June 30
 barrel volume amounts)                  2010      2009      2010      2009
----------------------------------------------------------------------------

Net Income                             $  237  $     46  $    404 $      89
 Per Trust Unit - Basic                $ 0.49  $   0.10  $   0.83 $    0.18

Cash from (used in) Operating
 Activities                            $  358  $    (44) $    667 $       6
 Per Trust Unit                        $ 0.74  $  (0.09) $   1.38 $    0.01

Unitholder Distributions               $  242  $     73  $    412 $     145
 Per Trust Unit                        $ 0.50  $   0.15  $   0.85 $    0.30

Sales Volumes (1)
 Total (MMbbls)                          10.8       6.8      19.7      16.1
 Daily average (bbls)                 118,569    75,553   108,980    89,114

Operating Costs ($/bbl)          $      31.18  $  50.23  $  34.99 $   43.66

Net Realized SCO Selling Price
 ($/bbl)                         $      78.07  $  67.92  $  79.87 $   60.69

West Texas Intermediate (average
 $US/bbl) (2)                    $      78.05  $  59.79  $  78.46 $   51.68
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(1) The Trust's sales volumes differ from its production volumes due to
    changes in inventory, which are primarily in-transit pipeline volumes,
    and are after purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.

Outlook

The Trust has revised its outlook for 2010. Syncrude production is now estimated to total 110 million barrels (40.4 million barrels net to the Trust), with a production range of 108 million to 113 million barrels. We are estimating operating costs of approximately $37 per barrel, and capital expenditures totaling $544 million. Based on the Trust's assumption of WTI crude oil averaging U.S. $75 per barrel in 2010, together with the other assumptions outlined in our outlook, we are estimating cash from operating activities of $1,098 million, or $2.27 per Unit in 2010.

More information on the Trust's outlook is provided in the MD&A section of this report and the July 29, 2010 guidance document, which is available on our web site at www.cos-trust.com under "Investor".

Corporate Conversion

Canadian Oil Sands is continuing with its plans to convert to a corporate structure on or about December 31, 2010. The arrangement to convert has been approved by Canadian Oil Sands' Board, its Unitholders and the Court of Queen's Bench of Alberta. Following conversion to a corporate structure, Canadian Oil Sands expects its approach to dividend payments to be very similar to its management of distribution payments as a Trust. See the "Unitholder Distributions" section of the MD&A below for discussion on the dividend approach following conversion.

Syncrude Sustainability Report

Syncrude's 2008/2009 Sustainability Report has been posted on Syncrude's website at www.syncrude.ca. The report describes Syncrude's economic, environmental and social performance in 2008 and 2009; highlights include:

- Cumulative land reclaimed now totals 4,567 hectares

- Landscape construction began on a 52-hectare wetland, including the industry's first reclaimed fen

- Cumulative spending of $1.4 billion with Aboriginal-owned businesses since 1992

- Community investment of $7.5 million during 2008/09

- $6.3 billion in procurement of goods and services across Canada during 2008/09

A copy of the report or a summary of the highlights can be requested by email to info@syncrude.com.

Syncrude Waterfowl Incident

In February 2009, Syncrude Canada Ltd. ("Syncrude Canada") was charged under the Federal Migratory Birds Convention Act and the Alberta Environmental Protection and Enhancement Act for a 2008 waterfowl incident. On June 25, 2010, a provincial court judge ruled in favour of the federal and provincial Crowns on the case involving this waterfowl incident. A further hearing on the matter is scheduled for August 20, 2010. Syncrude continues to review the basis of the conviction before determining if any further action, including any potential appeal, will be made.

Syncrude has always acknowledged its moral obligations for this waterfowl incident and has implemented new waterfowl deterrent systems. Syncrude and its owners remain committed to improving their environmental performance. More information on the environmental issues is contained in the Annual Information Form of the Trust dated March 22, 2010.

Syncrude Appoints New President and CEO

Scott Sullivan has been appointed to the role of President and Chief Executive Officer of Syncrude Canada effective August 1, 2010. Mr. Sullivan succeeds Tom Katinas, who was assigned to the position in May 2007 for a three-year term. Both are employees of ExxonMobil Corp. ("ExxonMobil") seconded to Syncrude under the Management Services Agreement ("MSA") between Syncrude and Imperial Oil Resources Ltd.

Mr. Sullivan brings extensive operating experience to Syncrude, having worked at a number of ExxonMobil refining facilities around the world. In his most recent assignment, he held the position of deputy general manager of the Fujian Refining and Petrochemical Co., a major refining and petrochemical joint venture among ExxonMobil, Sinopec, Saudi Aramco and the Chinese province of Fujian.

This press release contains forward-looking statements, which are qualified by the advisory in the MD&A section of this report.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") was prepared as of July 29, 2010 and should be read in conjunction with the unaudited interim consolidated financial statements of Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust") for the three and six months ended June 30, 2010 and June 30, 2009, the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2009 and the Trust's Annual Information Form ("AIF") dated March 22, 2010. Additional information on the Trust, including its AIF, is available on SEDAR at www.sedar.com or on the Trust's website at www.cos-trust.com. The Trust's financial results have been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP") and are reported in Canadian dollars, unless stated otherwise.

ADVISORY- in the interest of providing the Trust's Unitholders and potential investors with information regarding the Trust, including management's assessment of the Trust's future production and cost estimates, plans and operations, certain statements throughout this MD&A and the related press release contain "forward-looking statements" under applicable securities law. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to the cost estimate for the Sulphur Emissions Reduction ("SER") project and the expectation that the SER project will significantly reduce total sulphur dioxide and other emissions; the completion date for the SER project; future distributions and any increase or decrease from current payment amounts; the Trust's plans with regard to its net debt level by the end of 2010 and beyond; the expected impact on Syncrude Canada Ltd. ("Syncrude Canada") of being convicted under both federal and provincial charges related to the waterfowl incident; plans regarding crude oil hedges and currency hedges in the future; the expected production, revenues and operating costs for 2010; the expected level of sustaining capital for the next few years and longer term; the expectations regarding capital expenditures and operating costs; the plans and expected impact of converting to a corporate structure; the plans and expected impact of adopting International Financial Reporting Standards including, without limitation, its impact on the Trust's accounting policies, financial statement disclosure, information technology requirements, data systems, internal controls and business activities, and the results that the Syncrude Joint Venture ("Syncrude") reports to the Trust; the expected impact of any current and future environmental legislation, including without limitation, regulations relating to tailings; the expected funding increases in 2010 for the Trust's share of Syncrude's pension and reclamation funding; the expected realized selling price, which includes the anticipated differential to WTI to be received in 2010 for Canadian Oil Sands' product; the potential amount payable in respect of any future income tax liability; the level of energy consumption in 2010 and beyond; capital expenditures for 2010; the level of natural gas consumption in 2010 and beyond; the expected price for crude oil and natural gas in 2010, and the anticipated impact that certain factors such as natural gas and oil prices, foreign exchange and operating costs have on the Trust's cash from operating activities and net income.

Although the Trust believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A include, but are not limited to: the impacts of regulatory changes especially as such relate to royalties, taxation, and environmental charges; the impact of technology on operations and processes and how new complex technology may not perform as expected; skilled labour shortages and the productivity achieved from labour in the Fort McMurray area; the supply and demand metrics for oil and natural gas; the impact that pipeline capacity and refinery demand have on prices for our products; the unanimous joint venture owner approval for major expansions and changes in product types; the variances of stock market activities generally; global economic environment/volatility of markets; normal risks associated with litigation, general economic, business and market conditions; the impact of any decisions rendered by a court in relation to litigation including without limitation: the decision relating to the trial against Syncrude Canada regarding the 2008 waterfowl incident, regulatory change, the impact of Syncrude being unable to meet the conditions of its approval for its tailings management plan under Directive 074, and such other risks and uncertainties described from time to time in the Trust's Annual Information Form dated March 22, 2010 and in the reports and filings made with securities regulatory authorities by the Trust as well as those assumptions outlined in the Trust's guidance document being correct. You are cautioned that the foregoing list of important factors is not exhaustive. No assurance can be given that the final legislation implementing the federal tax changes regarding income trusts will not be further changed in a manner which adversely affects the Trust and its Unitholders. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and unless required by law, the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

REVIEW OF SYNCRUDE OPERATIONS

During the second quarter of 2010, crude oil production from the Syncrude Joint Venture ("Syncrude") totaled 29.5 million barrels, or 324,000 barrels per day, compared with 18.8 million barrels, or 206,000 barrels per day, during the same period of 2009. Net to the Trust, production totaled 10.8 million barrels in the second quarter of 2010 compared with 6.9 million barrels in the second quarter of 2009, based on our 36.74 per cent working interest.

Production volumes in the second quarter of 2010 were stronger than the same period in the prior year. While the second quarter of 2010 was impacted by unplanned repairs and maintenance on two diluent recovery units, the second quarter of 2009 was impacted by a scheduled turnaround of Coker 8-3 and related units, circulation issues with Coker 8-1 and operational reliability issues.

Year-to-date, Syncrude produced 53.7 million barrels in 2010, or about 297,000 barrels per day, compared with 43.4 million barrels, or about 240,000 barrels per day in 2009. Production in 2010 reflects the first quarter turnaround of the LC Finer and associated upgrading units and unplanned repairs and maintenance on a hydrotreater and two diluent recovery units. Production volumes in the first half of 2009 were impacted by a coker turnaround, coker circulation and operational reliability issues as well as first quarter 2009 bitumen production constraints.

Syncrude's facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. Under normal operating conditions, scheduled downtime is required for maintenance and turnaround activities and unscheduled downtime will occur as a result of operational and mechanical problems, unanticipated repairs and other slowdowns. When allowances for such downtime are included, the daily design productive capacity of Syncrude's facilities is approximately 350,000 barrels per day on average and is referred to as "barrels per calendar day". All references to Syncrudes' production capacity in this report refer to barrels per calendar day, unless stated otherwise. The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes.


SUMMARY OF QUARTERLY RESULTS

                               2010                      2009
($ millions,
 except per Trust
 Unit and volume
 amounts)               Q2       Q1        Q4        Q3       Q2         Q1
----------------------------------------------------------------------------
Revenues (1)     $     842 $    734 $     863 $     773 $    467  $     512

Net income       $     237 $    167 $      96 $     247 $     46  $      43
 Per Trust Unit,
  Basic &
  Diluted        $    0.49 $   0.35 $    0.20 $    0.51 $   0.10  $    0.09

Cash from
 operating
 activities      $     358 $    309 $     328 $     213 $    (44) $      50
 Per Trust
  Unit (2)       $    0.74 $   0.64 $    0.68 $    0.44 $  (0.09) $    0.10

Unitholder
 distributions   $     242 $    170 $     169 $     121 $     73  $      72
 Per Trust Unit  $    0.50 $   0.35 $    0.35 $    0.25 $   0.15  $    0.15

Daily average
 sales volumes
 (bbls) (3)        118,569   99,286   119,287   114,544   75,553    102,825

Net realized SCO
 selling price
 ($/bbl) (4)     $   78.07 $  82.06 $   78.67 $   73.31 $  67.92  $   55.32

Operating costs
 ($/bbl) (5)     $   31.18 $  39.59 $   30.18 $   27.80 $  50.23  $   38.78

Purchased
 natural gas
 price ($/GJ)    $    3.68 $   4.95 $    4.33 $    2.90 $   3.09  $    4.96

West Texas
 Intermediate
 (avg.
 US$/bbl) (6)    $   78.05 $  78.88 $   76.13 $   68.24 $  59.79  $   43.31

Foreign exchange
 rates
 (US$/Cdn$):
 Average         $    0.97 $   0.96 $    0.95 $    0.91 $   0.86  $    0.80
 Quarter-end     $    0.94 $   0.98 $    0.96 $    0.93 $   0.86  $    0.79


                                                                 2008
($ millions, except per Trust Unit and volume
 amounts)                                                 Q4             Q3
----------------------------------------------------------------------------
Revenues (1)                                       $     704      $   1,381

Net income                                         $     124      $     604
 Per Trust Unit, Basic & Diluted                   $    0.26      $    1.25

Cash from operating activities                     $     466      $     921
 Per Trust Unit (2)                                $    0.97      $    1.91

Unitholder distributions                           $     361      $     602
 Per Trust Unit                                    $    0.75      $    1.25

Daily average sales volumes (bbls) (3)               110,197        116,656

Net realized SCO selling price ($/bbl) (4)         $   69.40      $  127.55

Operating costs ($/bbl) (5)                        $   32.10      $   32.15

Purchased natural gas price ($/GJ)                 $    6.41      $    7.86

West Texas Intermediate (avg. US$/bbl) (6)         $   59.08      $  118.22

Foreign exchange rates (US$/Cdn$):
 Average                                           $    0.83      $    0.96
 Quarter-end                                       $    0.82      $    0.94

(1) Revenues after crude oil purchases and transportation expense.

(2) Cash from operating activities per Trust Unit is a non-GAAP measure that
    is derived from cash from operating activities reported on the Trust's
    Consolidated Statements of Cash Flows divided by the weighted-average
    number of Trust Units outstanding in the period, as used in the Trust's
    net income per Unit calculations.

(3) Daily average sales volumes after crude oil purchases.

(4) Net realized SCO selling price after foreign currency hedging.

(5) Derived from operating costs, as reported on the Trust's Consolidated
    Statements of Income and Comprehensive Income, divided by the sales
    volumes during the period.

(6) Pricing obtained from Bloomberg.

During the last eight quarters, the following items have had a significant impact on the Trust's financial results:

- Fluctuations in U.S. dollar WTI oil prices have impacted the Trust's revenues, Crown royalties, net income and cash from operating activities;

- Net income was reduced in the fourth quarter of 2009 by $148 million due to an impairment charge and goodwill write-down on the Arctic natural gas assets;

- Planned and unplanned maintenance activities as well as turnarounds have impacted quarterly production volumes, sales revenue and operating costs;

- U.S. to Canadian dollar exchange rate fluctuations have resulted in foreign exchange gains and losses on the revaluation of U.S. dollar denominated debt and have impacted commodity pricing;

- Transition to a new Crown royalty framework effective January 1, 2009; and

- Tax rate reductions substantively enacted in the first quarter of 2009 resulted in additional future income tax recoveries of $63 million.

Quarterly variances in net income and cash from operating activities are caused mainly by fluctuations in crude oil prices, production and sales volumes, operating costs and natural gas prices. Net income also is impacted by unrealized foreign exchange gains and losses, impairment charges and future income tax amounts. While the supply/demand balance for crude oil affects selling prices, the impact of this equation is difficult to predict and quantify and has not displayed significant seasonality. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is influenced by weather conditions and North American natural gas inventory levels.

Syncrude production levels may not display seasonal patterns or trends. While maintenance and turnaround activities are typically scheduled to avoid the winter months, the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages may occur. Maintenance and turnaround activities impact both production volumes and operating costs. In addition, a large proportion of operating costs are fixed and, as such, per barrel operating costs are variable to production volumes. The costs associated with these activities are expensed in the period they are incurred, which can lead to significant increases in operating costs. The effect on per barrel operating costs of these maintenance activities is amplified as the facility is generally producing at reduced rates when maintenance work is occurring.

REVIEW OF FINANCIAL RESULTS

In the second quarter of 2010, the Trust reported net income of $237 million, or $0.49 per Unit, compared with $46 million, or $0.10 per Unit, recorded in the second quarter of 2009. The increase in net income reflects higher revenues partially offset by higher Crown royalties. In addition, the second quarter of 2010 included foreign exchange losses whereas the second quarter of 2009 included foreign exchange gains.

Net income for the first six months of 2010 totaled $404 million, or $0.83 per Unit compared with net income of $89 million, or $0.18 per Unit, recorded in 2009. The increase reflects higher revenues partially offset by higher Crown royalties. In addition, 2010 included foreign exchange losses whereas 2009 included foreign exchange gains.

Revenues after crude oil purchases and transportation costs totaled $842 million in the second quarter of 2010 versus $467 million in the second quarter of 2009. On a year-to-date basis, revenues after crude oil purchases and transportation costs totaled $1,576 million in 2010 versus $979 million for the first half of 2009. The increases in revenues were due mainly to higher crude oil prices and higher production volumes in 2010 (see the "Revenues after Crude Oil Purchases and Transportation Expense" section of this MD&A for further discussion).

Cash from operating activities was $358 million, or $0.74 per Unit, for the second quarter of 2010. This compares with cash used in operating activities of $44 million, or $0.09 per Unit, for the second quarter of 2009. The increase was due to higher revenues during the second quarter of 2010 than in the same period of 2009, partially offset by higher Crown royalties. Year-to-date cash from operating activities increased to $667 million for 2010 from $6 million in 2009. The increase was due to higher revenues partially offset by higher Crown royalties. In addition, non-cash working capital decreased during the first half of 2010 versus an increase during the first half of 2009.

Non-cash working capital reduced cash from operating activities by $14 million in the second quarter of 2010, primarily as a result of lower accounts payable at June 30, 2010 relative to March 31, 2010. By comparison, non-cash working capital decreased cash from operating activities by $67 million in the second quarter of 2009, primarily as a result of higher accounts receivable, reflecting higher oil prices, as well as higher inventory levels and lower accounts payable at June 30, 2009 relative to March 31, 2009.

In the first six months of 2010, non-cash working capital increased cash from operating activities by $90 million, primarily as a result of higher accounts payable and lower accounts receivable at June 30, 2010 relative to December 31, 2009. In the same period of 2009, non-cash working capital decreased cash from operating activities by $86 million, primarily as a result of higher accounts receivable and higher inventory levels at June 30, 2009 relative to December 31, 2008.

Non-cash working capital and changes therein can vary significantly on a period-by-period basis as a result of the timing and settlements of accounts receivable and accounts payable balances, and are impacted by a number of factors including changes in: revenue, operating expenses, Crown royalties, capital expenditures, inventory fluctuations, and the timing of payments.

Non-GAAP Financial Measures

In this MD&A we refer to financial measures that do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). These non-GAAP financial measures include cash from operating activities on a per Unit basis, net debt, total capitalization, net debt to total capitalization, and certain per barrel measures. Cash from operating activities per Unit is calculated as cash from operating activities as reported on the Trust's Consolidated Statement of Cash Flows divided by the weighted-average number of Units outstanding in the period. This measure is an indicator of the Trust's capacity to fund capital expenditures, distributions, and other investing activities without incremental financing. In addition, the Trust refers to various per barrel figures, such as net realized selling prices, operating costs and Crown royalties, which also are considered non-GAAP measures. We derive per barrel figures by dividing the relevant revenue or cost figure by our sales volumes, which are after purchased crude oil volumes in a period.

Non-GAAP financial measures provide additional information that we believe is meaningful regarding the Trust's operational performance, its liquidity and its capacity to fund distributions, capital expenditures and other investing activities. Users are cautioned that non-GAAP financial measures presented by the Trust may not be comparable with measures provided by other entities.


Net Income per Barrel

                              Three Months Ended           Six Months Ended
                                         June 30                    June 30
($ per bbl) (1)          2010     2009  Variance    2010     2009  Variance
----------------------------------------------------------------------------

Revenues after crude
 oil purchases and
 transportation expense 78.12    67.92     10.20   79.92    60.69     19.23
Operating costs        (31.18)  (50.23)    19.05  (34.99)  (43.66)     8.67
Crown royalties         (7.88)   (3.33)    (4.55)  (8.27)   (1.69)    (6.58)
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                        39.06    14.36     24.70   36.66    15.34     21.32
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Non-production costs    (1.78)   (5.65)     3.87   (2.80)   (4.46)     1.66
Administration and
 insurance              (0.95)   (1.15)     0.20   (1.04)   (0.96)    (0.08)
Interest, net           (2.02)   (3.64)     1.62   (2.44)   (2.78)     0.34
Depreciation,
 depletion and
 accretion              (8.74)  (11.82)     3.08   (9.99)  (11.60)     1.61
Loss on disposal of
 assets                 (0.44)       -     (0.44)  (0.24)       -     (0.24)
Foreign exchange gain
 (loss)                 (3.59)   11.22    (14.81)  (0.28)    2.96     (3.24)
Future income tax
 recovery and other      0.47     3.37     (2.90)   0.60     6.99     (6.39)
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                       (17.05)   (7.67)    (9.38) (16.19)   (9.85)    (6.34)
----------------------------------------------------------------------------
Net income per barrel   22.01     6.69     15.32   20.47     5.49     14.98
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Sales volumes (MMbbls)
 (2)                     10.8      6.8       4.0    19.7     16.1       3.6
----------------------------------------------------------------------------
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(1) Unless otherwise specified, net income and other per barrel measures in
    this MD&A have been derived by dividing the relevant revenue or cost
    item by the sales volumes in the period.

(2) Sales volumes, after purchased crude oil volumes.
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Revenues after Crude Oil Purchases and Transportation Expense

                             Three Months Ended            Six Months Ended
                                        June 30                     June 30
($ millions)             2010    2009  Variance    2010      2009  Variance
----------------------------------------------------------------------------

Sales revenue (1)      $  879  $  525  $    354 $ 1,777   $ 1,073  $    704
Crude oil purchases       (29)    (52)       23    (188)      (81)     (107)
Transportation expense     (9)     (7)       (2)    (15)      (15)        -
----------------------------------------------------------------------------
                          841     466       375   1,574       977       597

Currency hedging gains
 (1)                        1       1         -       2         2         -
----------------------------------------------------------------------------
                       $  842  $  467  $    375 $ 1,576    $  979  $    597
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Sales volumes (MMbbls)
 (2)                     10.8     6.8       4.0    19.7      16.1       3.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The sum of sales revenue and currency hedging gains equals Revenues on
    the Trust's Consolidated Statements of Income and Comprehensive Income.
    Sales revenue includes revenue from the sale of purchased crude oil and
    sulphur revenue.
(2) Sales volumes, after purchased crude oil volumes.


($ per barrel)
----------------------------------------------------------------------------

Realized SCO selling
 price before
 hedging (3)          $ 77.98 $ 67.79  $  10.19 $ 79.78   $ 60.58  $  19.20
Currency hedging
 gains                   0.09    0.13     (0.04)   0.09      0.11     (0.02)
----------------------------------------------------------------------------
Net realized SCO
 selling price        $ 78.07 $ 67.92  $  10.15 $ 79.87   $ 60.69  $  19.18
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----------------------------------------------------------------------------

(3) SCO sales revenue after crude oil purchases and transportation expense
    divided by sales volumes, after purchased crude oil volumes.

The increase in sales revenue after crude oil purchases and transportation expense in the second quarter of 2010 versus 2009 primarily reflects a higher realized selling price for our synthetic crude oil ("SCO") combined with higher sales volumes. During the second quarter of 2010, WTI averaged U.S. $78 per barrel compared to U.S. $60 per barrel in the second quarter of 2009. The impact of the higher U.S. dollar WTI price in the second quarter of 2010 was offset somewhat by a stronger Canadian dollar, which averaged $0.97 U.S./Cdn for the second quarter of 2010 versus $0.86 U.S./Cdn for the second quarter of 2009. Year-to-date, WTI averaged U.S. $78 per barrel in 2010 versus U.S. $52 per barrel in 2009 while the Canadian dollar averaged $0.97 U.S./Cdn in 2010 versus $0.83 U.S./Cdn in 2009.

The Trust's SCO price is also affected by the premium or discount realized relative to Canadian dollar WTI (the "differential"). In the second quarter of 2010, the Trust realized a weighted-average SCO discount of $2.04 per barrel versus a $2.59 per barrel discount for the same period of 2009. The differential is dependent upon the supply and demand for SCO and, accordingly, can change quickly depending upon the short-term supply and demand dynamics in the market and pipeline availability for transporting crude oil.

The Trust's second quarter sales volumes averaged 119,000 barrels per day and 76,000 barrels per day in 2010 and 2009, respectively. Year-to-date sales volumes averaged 109,000 barrels per day in 2010 versus an average of 89,000 barrels per day for the first half of 2009. Sales volumes for 2010 reflect the turnaround of the LC Finer and associated upgrading units, unplanned maintenance on a hydrotreater during the first quarter and unplanned repairs and maintenance on two diluent recovery units during the second quarter. By comparison, sale volumes for 2009 were impacted by the Coker 8-3 turnaround, circulation issues in Coker 8-1, reliability issues in mining and upgrading operations, and constrained bitumen production during the first quarter.

The Trust purchases crude oil from third parties to fulfill sales commitments with customers when there are shortfalls in Syncrude's production and to facilitate certain transportation and tankage arrangements and operations. Sales revenue includes the sale of purchased crude oil. Increased crude oil purchases in 2010 reflect additional activities to support unanticipated production shortfalls due to the advancement of the LC Finer turnaround and incremental purchases associated with tankage arrangements, as well as higher crude oil prices as compared to 2009.

Operating Costs

The following table breaks down operating costs into their major components and shows bitumen costs both on a per barrel of bitumen and a per barrel of SCO produced basis. The information allocates costs to bitumen production and upgrading based on deductibility for bitumen royalty purposes. The Syncrude Royalty Amending Agreement provides for allowed bitumen costs, before internal fuel allocation, to be 64.5 per cent of Syncrude total operating costs until December 31, 2010.


                                           Three Months Ended June 30
                                           2010                2009
----------------------------------------------------------------------------
                                        $/bbl     $/bbl     $/bbl     $/bbl
                                      Bitumen       SCO   Bitumen       SCO
----------------------------------------------------------------------------

 Bitumen production                  $  17.60  $  19.66  $  26.97  $  31.95
 Internal fuel allocation (2)            2.31      2.58      2.64      3.13
----------------------------------------------------------------------------
 Total produced bitumen costs           19.91     22.24     29.61     35.08

 Upgrading costs (1)                              11.62               16.65
 Less: Internal fuel allocation to
  bitumen (2)                                     (2.58)              (3.13)
 Bitumen purchases                                    -                0.95
----------------------------------------------------------------------------
 Total Syncrude operating costs                   31.28               49.55
 Canadian Oil Sands' adjustments (3)              (0.10)               0.68
----------------------------------------------------------------------------

Total operating costs                             31.18               50.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(thousands of barrels per day)        Bitumen       SCO   Bitumen       SCO
----------------------------------------------------------------------------
Syncrude production volumes (4)           362       324       245       206
----------------------------------------------------------------------------
----------------------------------------------------------------------------


                                             Six Months Ended June 30
                                             2010                2009
----------------------------------------------------------------------------
                                        $/bbl     $/bbl     $/bbl     $/bbl
                                      Bitumen       SCO   Bitumen       SCO
----------------------------------------------------------------------------

 Bitumen production                  $  19.76  $  23.21  $  23.74  $  28.73
 Internal fuel allocation (2)            2.77      3.26      2.45      2.97
----------------------------------------------------------------------------
 Total produced bitumen costs           22.53     26.47     26.19     31.70

 Upgrading costs (1)                              12.82               15.46
 Less: Internal fuel allocation to
  bitumen (2)                                     (3.26)              (2.97)
 Bitumen purchases                                    -                0.57
----------------------------------------------------------------------------
 Total Syncrude operating costs                   36.03               44.76
 Canadian Oil Sands' adjustments (3)              (1.04)              (1.10)
----------------------------------------------------------------------------

Total operating costs                             34.99               43.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(thousands of barrels per day)        Bitumen       SCO   Bitumen       SCO
----------------------------------------------------------------------------
Syncrude production volumes (4)           349       297       290       240
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Upgrading costs include the production and ongoing maintenance costs
    associated with processing and upgrading of bitumen to SCO. It also
    includes the costs of major upgrading equipment turnarounds and catalyst
    replacement, all of which are expensed as incurred.
(2) Natural gas prices averaged $3.68 per GJ and $4.31 per GJ for the three
    and six months ended June 30, 2010, respectively and $3.09 per GJ and
    $4.31 per GJ for the three and six months ended June 30, 2009,
    respectively.
(3) Canadian Oil Sands' adjustments mainly pertain to actual reclamation
    costs, Syncrude-related pension costs, as well as the inventory impact
    of moving from production to sales as Syncrude reports per barrel costs
    based on production volumes and the Trust reports based on sales
    volumes.
(4) Syncrude SCO production volumes include the impact of processed
    purchased bitumen volumes.


                                     Three Months Ended    Six Months Ended
                                            June 30              June 30
($/bbl of SCO)                           2010      2009      2010      2009
----------------------------------------------------------------------------

Production costs                        27.67     46.30   $ 30.71   $ 38.75
Purchased energy                         3.51      3.93      4.28      4.91
----------------------------------------------------------------------------
 Total operating costs                  31.18     50.23   $ 34.99   $ 43.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(GJs/bbl of SCO)
----------------------------------------------------------------------------
Purchased energy consumption             0.95      1.27      0.99      1.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------

In the second quarter of 2010, operating costs were $336 million, averaging $31.18 per barrel, compared to $345 million, or $50.23 per barrel in the second quarter of 2009. Year-to-date operating costs were $690 million in 2010, averaging $34.99 per barrel, compared to $704 million, or $43.66 per barrel, in 2009.

The decrease in year-over-year operating costs was primarily due to the following:

- Lower turnaround costs in 2010; while the first quarter of 2010 reflected the turnaround of the LC Finer and related upgrading units, the second quarter of 2009 reflected the comprehensive and extended turnaround of Coker 8-3 and related units; and,

- Lower stock-based compensation expense in 2010; stock-based compensation expense for 2010 reflected a decrease in the fair market value of the Trust's Units and other Syncrude owners' public shares whereas 2009 reflected an increase.

The decrease in costs was partially offset by:

- Additional mining activities in 2010 relative to 2009 to support higher production levels; and,

- Additional unplanned repairs and maintenance activities in 2010 on two diluent recovery units and a hydrotreater.

Non-Production Costs

Non-production costs totaled $19 million and $39 million in the second quarters of 2010 and 2009, respectively. Year-to-date non-production costs totaled $55 million for 2010 and $72 million for 2009. The decrease in non-production costs was primarily due to the 2010 capitalization of costs relating to mine train replacements and relocations, and tailings initiatives. In 2009, costs relating to these activities were expensed as non-production costs.

Non-production costs consist primarily of development expenditures relating to capital programs, such as pre-feasibility engineering, technical and support services, research and development, and regulatory and stakeholder consultation expenditures. Non-production costs can vary on a periodic basis depending on the number of projects underway and the status of the projects.

Crown Royalties

In the second quarter of 2010, Crown royalties increased to $85 million, or $7.88 per barrel, from $23 million, or $3.33 per barrel, in the comparable 2009 quarter. Year-to-date Crown royalties increased to $163 million, or $8.27 per barrel, in 2010 from $27 million, or $1.69 per barrel in 2009. Crown royalties in the first half of 2009 were recorded at the minimum one per cent of deemed bitumen revenues, while Crown royalties in 2010 were accrued at 25 per cent of net revenues and reflect higher deemed bitumen revenues. Crown royalties in 2010 also reflect the additional royalty expense under the transition agreement with the Alberta government, which did not apply until January 1, 2010.

The Syncrude Amended Royalty Agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil price adjusted for reasonable quality, transportation and handling deductions (including diluent costs) to reflect the quality and location differences between Syncrude's bitumen and the reference price of bitumen. The Alberta government, Syncrude, and the Syncrude owners are in discussions to determine the appropriate adjustments for quality, transportation and handling. For estimating and paying royalties, Syncrude has used a bitumen value based on Syncrude and its owners' interpretation of the Syncrude Amended Royalty Agreement, and their estimates of the appropriate quality, transportation and handling adjustments. These adjustments are different than those provided under the Alberta government's generic bitumen valuation methodology. Canadian Oil Sands' share of the royalties recognized for the period from January 1, 2009 to June 30, 2010 are estimated to be approximately $75 million less than the amount calculated under the generic bitumen valuation methodology. The Syncrude owners and the Alberta government continue to discuss the basis for these reasonable adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter.


Interest Expense, Net
                                     Three Months Ended    Six Months Ended
                                                June 30             June 30
($ millions)                             2010      2009      2010      2009
----------------------------------------------------------------------------

Interest expense on long-term debt    $    22   $    25    $   48   $    46
Interest income and other                   -         -         -        (1)
----------------------------------------------------------------------------
 Interest expense, net                $    22   $    25    $   48   $    45
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Interest expense during the second quarter of 2010 was lower than in the second quarter of 2009, reflecting the 2009 refinancing of long-term debt that matured subsequently in that year. On a year-to-date basis, 2010 interest expense was higher than in the same period of 2009 due to consent solicitation fees recorded during the first quarter of 2010 for the Trust's corporate conversion plans.


Depreciation, Depletion and Accretion Expense

                                     Three Months Ended   Six Months Ended
                                                June 30             June 30
($ millions)                             2010      2009      2010      2009
----------------------------------------------------------------------------

Depreciation and depletion expense     $   87   $    78    $  184   $   180
Accretion expense                           7         3        13         7
----------------------------------------------------------------------------
                                       $   94   $    81    $  197   $   187
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Oil sands assets are depreciated and depleted over their estimated remaining lives, which are reviewed by management on a regular basis. During the first quarter of 2010, management determined that the usage of certain tangible equipment would be most accurately represented by a straight-line calculation on an ongoing basis. Depreciation and depletion of the oil sands assets is now estimated based on a blend of both a unit-of-production and straight-line basis. Depreciation, depletion and accretion expense increased from 2009 to 2010 due to the effect of the change in accounting estimate and lower 2009 production.

The effect of this change in estimate for the three and six months ended June 30, 2010 is that approximately $35 million and $38 million less depreciation and depletion expense, respectively, was recorded using the new estimated remaining lives than would have been recorded using the previous estimates. Beyond 2010, it is not practical to calculate the effect of this change in estimate due to the long-life nature of the assets and the amounts and timing of estimated future development costs.


Foreign Exchange (Gain) Loss

                                     Three Months Ended    Six Months Ended
                                                June 30             June 30
($ millions)                             2010      2009      2010      2009
----------------------------------------------------------------------------

Foreign exchange (gain) loss-long
 term debt                              $  50   $   (83)   $   16   $   (52)
Foreign exchange (gain) loss-other        (12)        6       (11)        4
----------------------------------------------------------------------------
 Total foreign exchange (gain) loss     $  38   $   (77)   $    5   $   (48)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Foreign exchange ("FX") gains/losses are primarily the result of revaluations of our U.S. dollar denominated long-term debt caused by fluctuations in U.S. and Canadian dollar exchange rates.

The FX losses on long-term debt in 2010 were due to a weakening in the value of the Canadian dollar relative to the U.S. dollar to $0.94 U.S./Cdn at June 30, 2010 from $0.98 U.S./Cdn at March 31, 2010 and $0.96 U.S./Cdn at December 31, 2009. The FX gains in 2009 were due to a strengthening of the Canadian dollar relative to the U.S. dollar to $0.86 U.S./Cdn at June 30, 2009 from $0.79 U.S./Cdn at March 31, 2009 and $0.82 U.S./Cdn at December 31, 2008.

Future Income Tax and Other

In the second quarter of 2010, a future income tax recovery of $5 million was recorded versus a recovery of $23 million in the same period of 2009. On a year-to-date basis, a future income tax recovery of $12 million was recorded in 2010 versus a recovery of $113 million in 2009 as a result of decreases in temporary differences between accounting and tax values of Canadian Oil Sands' assets and liabilities in both years. In addition to the future income tax amounts recorded on changes in temporary differences, a future income tax recovery of $63 million was recorded during the first quarter of 2009 on the substantive enactment of tax rate reductions.

CAPITAL EXPENDITURES

In the second quarter of 2010, capital expenditures totaled $114 million compared with expenditures of $139 million in the same quarter of 2009. The Syncrude Emissions Reduction ("SER") project accounted for $27 million and $32 million of the capital spent in the second quarters of 2010 and 2009, respectively, with the remaining second quarter expenditures primarily related to other sustaining capital activities including: mine train replacements and relocations, construction of tailings facilities, pipe replacements and extensions, and other infrastructure projects. Capital expenditures on a per barrel basis were $10.57 and $20.07 in the second quarters of 2010 and 2009, respectively. Capital expenditures on a per barrel basis are affected by the Trust's sales volumes, which were higher in the second quarter of 2010 relative to the second quarter of 2009.

Year-to-date capital expenditures totaled $206 million in 2010 versus $223 million in 2009. The SER project accounted for $54 million and $57 million of the capital spent in 2010 and 2009, respectively, with the remaining expenditures relating to other sustaining capital activities, including mine train replacements and relocations, construction of tailings facilities, pipe replacements and extensions and other infrastructure projects. Capital expenditures on a per barrel basis were approximately $10.46 and $13.78 on a year-to-date basis in 2010 and 2009, respectively. Capital expenditures on a per barrel basis are affected by the Trust's sales volumes, which were higher in 2010 relative to 2009.

Canadian Oil Sands' expansion-related capital expenditures have been relatively low in recent years and capital costs during 2010 and 2009 were mainly related to sustaining capital. Expansion-related capital expenditures are costs incurred to grow the productive capacity of the operation while sustaining capital expenditures are effectively all other capital expenditures. Capital expenditures may fluctuate considerably year-to-year due to the timing of expansions, equipment replacement and other factors.

Syncrude is undertaking the SER project, which commenced in 2006, to retrofit technology into the operation of Syncrude's original two cokers by the end of 2011 in order to reduce total sulphur dioxide and other emissions. The estimate of the total cost of the SER project remains at $1.6 billion ($590 million net to the Trust) and the Trust's share of SER expenditures to date is approximately $350 million.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

Contractual obligations are summarized in the Trust's 2009 annual MD&A and include future cash payments that the Trust is required to make under existing contractual arrangements that it has entered into directly or as a 36.74 per cent owner in Syncrude. During April 2010, an actuarial valuation of the pension obligation as at December 31, 2009 was completed. This resulted in additional funding requirements over the next 24 years of approximately $265 million, with the majority of the funding requirements due within the next five years. With the exception of the Trust's share of new Syncrude capital commitments of approximately $20 million related to purchases of new mining equipment, there have been no other significant new contractual obligations or commitments from our 2009 year-end disclosure.


UNITHOLDER DISTRIBUTIONS

                                     Three Months Ended    Six Months Ended
                                                June 30             June 30
----------------------------------------------------------------------------
($ millions)                             2010      2009      2010      2009
----------------------------------------------------------------------------

Cash from operating activities         $  358  $    (44)   $  667   $     6
Net income                             $  237  $     46    $  404   $    89
Unitholder distributions               $  242  $     73    $  412   $   145
----------------------------------------------------------------------------

Excess (shortfall) of cash from
 operating activities over
 Unitholder distributions              $  116  $   (117)   $  255   $  (139)

Excess (shortfall) of net income
 over Unitholder distributions         $   (5) $    (27)   $   (8)  $   (56)
----------------------------------------------------------------------------

During the first half of 2010, cash from operating activities exceeded Unitholder distributions by $255 million. Cash from operating activities was sufficient to fund the Trust's capital expenditures, reclamation trust fund contributions, and distributions.

Unitholder distributions exceeded net income by $8 million and $56 million in the first half of 2010 and 2009, respectively, primarily as a result of non-cash items included in the calculation of net income such as depletion, depreciation and accretion ("DD&A") and unrealized foreign exchange gains or losses. These non-cash items do not affect the Trust's cash from operating activities or ability to pay distributions over the near term.

The Trust uses debt and equity financing to the extent that cash from operating activities and existing cash balances are insufficient to fund capital expenditures, reclamation trust contributions, debt repayments, acquisitions, distributions and working capital changes from financing and investing activities. For further discussion, see the "Liquidity and Capital Resources" section of this MD&A.

On July 29, 2010 the Trust declared a quarterly distribution of $0.50 per Unit in respect of the third quarter of 2010 for a total distribution of approximately $242 million. The distribution will be paid on August 31, 2010 to Unitholders of record on August 23, 2010. Our quarterly distribution declarations consider the current and expected economic conditions, financing capacity for Canadian Oil Sands' capital requirements and the objective of maintaining an investment grade credit rating.

The $0.50 per Unit third quarter distribution reflects the Trust's objective of increasing tax pools to approximately $2 billion by the end of 2010, which may raise debt levels if achieved. As a result of this strategy, in 2010 the Trust expects distributions to exceed cash from operating activities less its capital expenditures.

Beyond 2010, the Trust will look to avoid significant increases in net debt in advance of a larger sustaining capital program and future expansion plans. As we have done in the past, we will use cash from operating activities as a source of investment financing. Our anticipation of an increase in capital expenditures, therefore, indicates a reduction in distributions in order to reinvest in our business post-2010.

Following the conversion to a corporate structure on or about December 31, 2010, Canadian Oil Sands expects its approach to dividend payments to be very similar to its management of distributions as a Trust. This means dividends will be determined on a quarterly basis in the context of current and expected crude oil prices, economic conditions, Syncrude's operating performance and financing capacity for operating and investing obligations. These factors can change significantly from period to period, causing fluctuations in cash from operating activities and net income. We will strive to reduce the impact of these fluctuations on dividends by taking a longer-term view of the factors influencing our business, and we may distribute more or less in a period than is generated in cash from operating activities or net income. However, the variable nature of cash from operating activities means Canadian Oil Sands' dividend amounts also are likely to be variable, and any expectations regarding the stability or sustainability of distributions/dividends are unwarranted and should not be implied.

In determining the Trust's distributions, Canadian Oil Sands also considers funding for its significant operating obligations, which are included in cash from operating activities. Such obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to $67 million and $42 million in the first half of 2010 and 2009, respectively. We anticipate these funding requirements for 2010 will rise to approximately $120 million from $69 million in 2009. The increase is due to additional reclamation activities, as well as the pension actuarial valuation completed in April 2010.

Debt covenants do not specifically limit the Trust's ability to pay distributions and are not expected to influence the Trust's liquidity in the foreseeable future. Aside from covenants relating to restrictions on Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business, the most restrictive financial covenant limits total debt-to-total capitalization at less than 55 per cent. With a net debt-to-total capitalization of approximately 20 per cent at June 30, 2010, a significant increase in debt or decrease in equity would be required before covenants restrict the Trust's distributions or financial flexibility.


LIQUIDITY AND CAPITAL RESOURCES
                                                     June 30    December 31
($ millions)                                            2010           2009
----------------------------------------------------------------------------

Long-term debt                                     $   1,179      $   1,163
Cash and cash equivalents                               (176)          (122)
----------------------------------------------------------------------------
 Net debt                                          $   1,003      $   1,041
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholders' equity                                $   3,961      $   3,969
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total capitalization (1)                           $   4,964      $   5,010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net debt to total capitalization (%)                      20             21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net debt plus Unitholders' equity. Net debt, total capitalization, as
    well as net debt to total capitalization are non-GAAP measures.

Net debt at June 30, 2010 decreased from December 31, 2009 primarily as a result of cash from operating activities exceeding capital expenditures and Unitholder distributions, partially offset by $16 million in foreign exchange losses on long-term debt.

We believe a slightly higher net debt level may provide a more efficient capital structure and will conserve tax pools prior to trust taxation; however, the Trust must also consider a prudent liquidity position, access to capital markets, and future investing and financing requirements. While we are comfortable in the current business environment paying distributions in excess of cash from operating activities less capital expenditures, future net debt will depend on actual operating results, crude oil prices, economic conditions, foreign exchange rates, and future investing activities, especially as our capital program increases beyond 2010.

In March 2010, the Trust's $70 million line of credit was increased to $100 million and the term on the Trust's $40 million bilateral credit facility was extended to April 21, 2011.

UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY

The Trust's Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $13 billion with 484 million Units outstanding and a closing price of $26.99 per Unit on June 30, 2010.


Canadian Oil Sands Trust - Trading
 Activity                              Second
                                      Quarter      June       May     April
                                         2010      2010      2010      2010
----------------------------------------------------------------------------

Unit price
 High                               $   33.05   $ 29.66   $ 31.30  $  33.05
 Low                                $   25.48   $ 26.55   $ 25.48  $  29.51
 Close                              $   26.99   $ 26.99   $ 28.64  $  30.75

Volume of Trust Units traded
 (millions)                              93.8      30.8      29.8      33.2
Weighted average Trust Units
 outstanding (millions)                 484.4     484.4     484.4     484.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------

FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of May 20, 2010 approximately 73 per cent of our Units were held by Canadian residents with the remaining 27 per cent of Units being held by non-Canadian residents. Canadian Oil Sands' Trust Indenture provides that not more than 49 per cent of its Units can be held by non-Canadian residents.

The Trust regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of August 23, 2010. The Trust posts its foreign ownership levels on its web site at www.cos-trust.com under "Investor/Unit Information". The steps to manage foreign ownership levels are described in the Trust's AIF.

CORPORATE CONVERSION

On January 28, 2010, Canadian Oil Sands' Board approved converting to a corporate structure on or about December 31, 2010. At the Annual and Special Meeting on April 29, 2010, Canadian Oil Sands' Unitholders approved this arrangement and the Court of Queen's Bench of Alberta issued a final order on April 30, 2010. See the "Unitholder Distributions" section of this MD&A for discussion on the dividend approach following conversion.

TAILINGS MANAGEMENT

On April 23, 2010 the Energy Resources Conservation Board ("ERCB") approved, with conditions, Syncrude's revised tailings pond plans submitted in September 2009 under Tailings Directive 074. These plans outline a multi-pronged approach for meeting the long-term intent of Directive 074, and include the implementation of three main tailings technologies: water capping, composite tails and centrifuge technology. Issued by the ERCB in February 2009, Tailings Directive 074 and its Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes requires operators to prepare tailings plans and report on tailings ponds annually, reduce the solids content of fluid tailings through the capture of fine particles from the production process in dedicated disposal areas, and convert fines into trafficable deposits which are ready for reclamation five years after deposits have ceased.

SYNCRUDE WATERFOWL INCIDENT

Syncrude has always acknowledged its moral obligations for the waterfowl incident and has implemented new waterfowl deterrent systems. Syncrude and its owners remain committed to improving their environmental performance. More information on the environmental issues is contained in the Annual Information Form of the Trust dated March 22, 2010.

FINANCIAL RISK MANAGEMENT

The Trust did not have any financial derivatives outstanding at June 30, 2010.

Crude Oil Price Risk

Canadian Oil Sands' revenues are impacted by changes in both the U.S. dollar denominated crude oil prices and U.S./Cdn FX rates. The Trust did not have any crude oil price hedges in place during the first half of 2010 and 2009, and does not currently intend to enter into any crude oil hedge positions. The Trust may hedge this exposure in the future, however, depending on the business environment and our growth opportunities.

Foreign Currency Risk

Canadian Oil Sands' results are affected by fluctuations in the U.S./Cdn currency exchange rates, as revenues generated are based on a U.S. dollar WTI benchmark price while certain obligations are denominated in Canadian dollars. The Trust did not have any foreign currency hedges in place during the first half of 2010 or 2009, and does not currently intend to enter into any new currency hedge positions. The Trust may, however, hedge foreign currency exchange rates in the future, depending on the business environment and growth opportunities.

Interest Rate Risk

Canadian Oil Sands' net income and cash from operating activities are impacted by interest rate changes based on the amount of floating rate debt outstanding or upon the refinancing of maturing long-term debt at prevailing interest rates. As at June 30, 2010 there was no floating interest rate debt outstanding, and the next long-term debt maturity is in 2013.

Liquidity Risk

Liquidity risk is the risk that Canadian Oil Sands will not be able to meet its financial obligations as they fall due. Canadian Oil Sands actively manages its liquidity risk through its cash, debt and equity strategies. The next long-term debt maturity is in 2013, and the $800 million credit facility does not expire until April 27, 2012.

Credit Risk

Canadian Oil Sands is exposed to credit risk primarily through customer accounts receivable balances and financial counterparties with whom the Trust has invested its cash or purchased term deposits from. The maximum exposure to any one customer or financial counterparty is controlled through a credit policy that limits exposure based on credit ratings.

The financial condition of some of our U.S. based refinery customers has continued to come under pressure during 2010, reflecting low refinery margins. Canadian Oil Sands carries credit insurance to help mitigate a portion of the impact should a loss occur and continues to transact primarily with investment grade customers; the vast majority of accounts receivable at June 30, 2010 was due from investment grade energy producers and refinery based customers.

At June 30, 2010, our cash and cash equivalents were invested mainly in term deposits with high-quality senior Canadian banks. As of July 29, 2010, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.

NEW ACCOUNTING PRONOUNCEMENTS

There were no new accounting pronouncements by the CICA during the first half of 2010 that are expected to have a material impact on the Trust.

International Financial Reporting Standards ("IFRS")

IFRS will replace Canadian GAAP for publicly accountable enterprises in Canada in 2011. The Trust will be required to adopt IFRS for interim and annual financial statements beginning on January 1, 2011 including comparative financial statements for 2010.

As part of its IFRS conversion project, the Trust has analyzed IFRS accounting standards and accounting policy alternatives and has prepared draft IFRS financial statements and disclosures.

a) IFRS 1 "First-Time Adoption of International Financial Reporting Standards"

IFRS 1 provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions, in certain areas, to the general requirement for full retrospective application of IFRS. The Trust has analyzed the choices available under IFRS 1 and has made preliminary decisions to utilize exemptions relating to employee future benefits, interest capitalization, asset retirement obligations, business combinations, and leases. Similarly, the Trust has made preliminary decisions to reject exemptions relating to the fair value measurement of property, plant and equipment and long-term debt.

i) Employee future benefits

Utilizing the employee future benefits exemption will result in the recognition of approximately $125 million of previously unrecognized actuarial losses (net of approximately $40 million in future income taxes) through January 1, 2010 retained earnings with a corresponding increase to the employee future benefits liability. The Trust's accounting policy under Canadian GAAP is to recognize these losses over the expected average remaining service life of active employees.

ii) Interest capitalization

By utilizing the interest capitalization exemption, the Trust will be exempted from capitalizing interest on assets already under construction at January 1, 2010. As described in the "Significant Accounting Policy Changes Post Conversion" section below, interest on certain future capital projects will be capitalized.

iii) Asset retirement obligations

The Trust intends to utilize the asset retirement obligation exemption which provides a method for adjusting the asset retirement obligations and the related property, plant and equipment assets to obtaan a January 1, 2010 value. The combined effect of utilizing this exemption and the related accouting policy change contemplated going forward is discussed in the "Significant Accounting Policy Changes Post Conversion" section below.

Current estimates suggest that the other IFRS 1 exemptions applied to the Trust will not materially impact its financial position or financial results at January 1, 2010.

b) Significant Accounting Policy Changes Post Conversion

Based on an analysis of differences between IFRS and Canadian GAAP, the amounts the Trust reports under IFRS may differ significantly from the amounts the Trust reports under Canadian GAAP for asset retirement obligations, future income taxes, employee future benefits, interest capitalization, stock-based compensation, and impairment of property, plant and equipment.

i) Asset retirement obligations

The Trust has made a preliminary decision to discount the estimated fair value of its asset retirement obligations and the related property, plant and equipment assets using a risk-free interest rate. Under Canadian GAAP, the Trust uses a credit-adjusted interest rate. The combined effect of utilizing the IFRS 1 exemption and changing the discount rate will increase the January 1, 2010 asset retirement obligations and the related property, plant and equipment assets by approximately $160 million and $30 million, respectively, with an offsetting $130 million charge to January 1, 2010 retained earnings.

In addition, IFRS requires that asset retirement obligations be re-measured each reporting period for changes in the discount rate with a corresponding adjustment to the cost of the related property, plant and equipment assets; whereas, under Canadian GAAP, changes in discount rates do not result in a re-measurement.

ii) Future income taxes

IFRS requires the Trust to measure future income taxes using the tax rate applicable to earnings not distributed to Unitholders whereas, under Canadian GAAP, future income taxes are measured using the tax rate applicable to distributed earnings. This difference will result in an approximate $300 million increase in the January 1, 2010 future income taxes liability with a corresponding charge to retained earnings. This charge is expected to subsequently reverse as a gain in net income in April 2010 reflecting the Unitholders' approval of the conversion from a trust to a corporation.

iii) Employee future benefits

The Trust has made a preliminary decision to recognize actuarial gains and losses on Syncrude's pension plans in other comprehensive income in the period in which they arise. The Trust's current accounting policy is to defer recognition of these gains and losses and to amortize the excess of any net actuarial gain or loss exceeding 10 per cent of the greater of the benefit obligation or fair value of the plan assets over the expected average remaining service life of active employees (approximately 12 years at December 31, 2009). IFRS currently allows the use of either method. The adoption of the new policy will result in the net pension asset or liability being fully reflected on the balance sheet each period. However, as valuation changes will flow through other comprehensive income, they will not impact net income.

iv) Interest capitalization

IFRS requires that interest costs relating to assets that take a substantial period of time to construct be capitalized and subsequently expensed as depreciation over the assets' expected useful lives. Currently, under Canadian GAAP, the Trust expenses all interest costs. During periods when significant capital expenditures are incurred, the IFRS accounting policy could result in a significant decrease in interest expense with an offsetting increase in depreciation and depletion over subsequent periods.

v) Impairment of property, plant and equipment

Under IFRS, the Trust will be required to recognize an impairment loss if the carrying amount of any property, plant and equipment exceeds its estimated future discounted cash flows. Under Canadian GAAP, estimated future cash flows used to assess impairments are not discounted. As such, impairment losses may be recognized earlier under IFRS than under Canadian GAAP. At January 1, 2010, the Trust is not anticipating any impairment of property, plant and equipment as a result of adopting IFRS.

Other post-conversion accounting policy choices and IFRS-Canadian GAAP differences are not expected to materially impact the financial position or financial results of the Trust. Although IFRS includes more explicit direction for componentization of property, plant and equipment for the purposes of calculating depreciation and depletion than is provided under Canadian GAAP, the Trust does not expect any material changes to the carrying value of its property, plant and equipment nor to its depreciation and depletion expense on adoption of IFRS.

IFRS will likely result in additional disclosures in Canadian Oil Sands' financial statements for items already disclosed in other security documents in Canada. As part of preparing draft IFRS disclosures, the Trust has analyzed and will continue to analyze the additional disclosures to ensure sufficient information is available upon adoption of IFRS.

c) Advisory

The preliminary decisions about IFRS 1 exemptions and accounting policy choices, and the assessments of the differences between IFRS and Canadian GAAP have not been finalized. Users are cautioned that the analysis will not be finalized until 2011 and that the preliminary decisions and estimated impacts of adopting IFRS may change. In addition, other differences may exist between amounts reported by the Trust under Canadian GAAP versus IFRS. New or revised IFRS standards are being developed by the International Accounting Standards Board ("IASB") that may impact the adoption of IFRS by the Trust in 2011 or thereafter. These standards include Joint Ventures, Income Taxes, Financial Instruments, Emissions Trading Schemes, Extractive Industries, Employee Future Benefits, Measurement of Liabilities and the IFRS 1 exemption relating to interest capitalization. The Trust continues to monitor these and other accounting standard developments within IFRS which might impact its IFRS conversion.

d) Conversion Project Update

The Trust's IFRS conversion is overseen by the Audit Committee with quarterly reports by management to that committee on the progress of the plan and any issues that may have arisen. The Trust's IFRS project will continue through 2010 and is on schedule for a January 1, 2011 implementation date.

Specifically, the Trust has completed the analysis of its information technology needs, data systems and internal controls and has concluded that they do not require any significant modification to adopt IFRS. To ensure the appropriate level of IFRS expertise is available through transition, resources have been added to the project team and ongoing education is provided to the project team, accounting staff, investor relations staff, senior management, the Audit Committee and the Board of Directors. The effects of existing IFRS on the Trust's business activities have been reviewed and it is not expected that IFRS will result in any significant changes to the Trust's business activities.


2010 OUTLOOK

(millions of Canadian dollars, except volume         July 29,      April 29,
 and per barrel amounts)                                2010           2010
----------------------------------------------------------------------------

Syncrude production (MMbbls)                             110            115
Canadian Oil Sands sales (MMbbls)                       40.4           42.3
Revenues, net of crude oil purchases and
 transportation                                        3,111          3,320
Operating costs                                        1,503          1,487
Operating costs per barrel                             37.19          35.20
Crown royalties                                          309            376
Capital expenditures                                     544            532
Cash from operating activities                         1,098          1,273

Business environment assumptions
---------------------------------
West Texas Intermediate (US$/bbl)                  $      75      $      80
Premium (Discount) to average C$ WTI prices
 (C$/bbl)                                          $   (2.00)     $   (2.25)
Foreign exchange rate (US$/Cdn$)                   $    0.95      $    0.99
AECO natural gas (Cdn$/GJ)                         $    4.75      $    5.00

For 2010, Canadian Oil Sands is estimating Syncrude production of 110 million barrels with a revised range of 108 million to 113 million barrels. The single point Syncrude production outlook has been decreased by five million barrels to reflect unplanned outages of the vacuum distillation unit and sour water stripper in July following the actual first half results. This estimate also includes the Coker 8-1 turnaround, scheduled to begin in September for a period of 45 days.

The outlook assumes a reduced U.S. $75 per barrel WTI oil price, a weaker $0.95 U.S./Cdn foreign exchange rate, and a SCO discount to Cdn dollar WTI of $2.00 per barrel. These assumptions, combined with the revised production outlook, result in estimated revenues of $3,111 million, or $77 per barrel in 2010.

Operating costs are estimated at $1,503 million with higher production costs partially offset by lower natural gas costs, reflecting a natural gas price assumption of $4.75 per gigajoule. Estimated per barrel operating costs have risen to $37, mainly as a result of the reduced production estimate.

Capital expenditures are estimated at $544 million, including $120 million related to the SER project and $106 million related to mine train replacements and relocations. Lower than forecast actual capital expenditures in the first half of 2010 are anticipated to be offset by higher spending in the second half of the year.

The assumed bitumen value has been reduced to 68 per cent of Cdn dollar WTI from 70 per cent, reflecting actual results to date. Combined with lower revenues, estimated 2010 Crown royalties have fallen to $309 million.

Based on the above assumptions, our revised 2010 outlook for cash from operating activities is $1,098 million, or $2.27 per Unit. After deducting forecasted 2010 capital expenditures of $544 million, we are estimating $554 million of remaining cash from operating activities for the year, or $1.14 per Unit.

Distributions paid in 2010 are expected to be 100 per cent taxable as other income. The actual taxability of 2010 distributions will be determined and reported to Unitholders prior to the end of the first quarter of 2011.

Changes in certain factors and market conditions could potentially impact Canadian Oil Sands' outlook. The following table provides a sensitivity analysis of the key factors affecting the Trust's performance. In addition to the factors described in the table, the supply/demand equation and pipeline access for synthetic crude oil in North American markets could impact the differential for SCO relative to crude benchmarks; however, these factors are difficult to predict.


2010 Outlook Sensitivity Analysis (July 29, 2010)

                                                     Cash from Operating
                                                          Activities
                                                           Increase
                                    Annual
Variable (1)                        Sensitivity     $ millions $/Trust unit
----------------------------------------------------------------------------

Syncrude operating costs decrease   C$1.00/bbl              34         0.07
Syncrude operating costs decrease   C$50 million            15         0.03
WTI crude oil price increase        US$1.00/bbl             32         0.07
Syncrude production increase        2 million bbls          42         0.09
Canadian dollar weakening           US$0.01/C$              24         0.05
AECO natural gas price decrease     C$0.50/GJ               17         0.04

(1) An opposite change in each of these variables will result in the
    opposite cash from operating activities impacts. Canadian Oil Sands may
    become subject to minimum Crown royalties at a rate of one per cent of
    gross bitumen revenue. The sensitivities presented herein assume
    royalties are paid at 25 per cent of net bitumen revenue.


CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(unaudited)
                              Three Months Ended           Six Months Ended
                                         June 30                    June 30
($ millions, except
 per Unit amounts)            2010          2009         2010          2009
----------------------------------------------------------------------------
Revenues                    $  880        $  526      $ 1,779       $ 1,075
----------------------------------------------------------------------------

Expenses:
 Operating                     336           345          690           704
 Non-production                 19            39           55            72
 Crude oil purchases
  and transportation expense    38            59          203            96
 Crown royalties (Note 10)      85            23          163            27
 Administration                  8             6           16            12
 Insurance                       3             2            5             4
 Interest, net (Note 6)         22            25           48            45
 Depreciation, depletion
  and accretion (Note 2)        94            81          197           187
 Loss on disposal of assets      5             -            5             -
 Foreign exchange (gain) loss   38           (77)           5           (48)
----------------------------------------------------------------------------
                               648           503        1,387         1,099
----------------------------------------------------------------------------
Earnings (loss) before taxes   232            23          392           (24)
 Future income tax recovery
  and other                     (5)          (23)         (12)         (113)
----------------------------------------------------------------------------
Net income                     237            46          404            89
Other comprehensive loss,
 net of income taxes
 Reclassification of
  derivative gains to
  net income                     -             -           (1)           (1)
----------------------------------------------------------------------------
Comprehensive income        $  237        $   46      $   403       $    88
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average Trust
 Units (millions)              484           484          484           483
Trust Units, end of period
 (millions)                    484           484          484           484

Net income per Trust Unit:
 Basic and diluted          $ 0.49        $ 0.10      $  0.83       $  0.18

See Notes to Unaudited Consolidated Financial Statements


CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
(unaudited)
                              Three Months Ended           Six Months Ended
                                         June 30                    June 30

($ millions)                  2010          2009         2010          2009
----------------------------------------------------------------------------
Retained earnings
 Balance, beginning of
  period                   $ 1,356       $ 1,333      $ 1,359       $ 1,362
 Net income                    237            46          404            89
 Unitholder distributions
  (Note 8)                    (242)          (73)        (412)         (145)
----------------------------------------------------------------------------
 Balance, end of period      1,351         1,306        1,351         1,306
----------------------------------------------------------------------------
Accumulated other
 comprehensive income
 Balance, beginning of
  period                        17            20           18            21
 Other comprehensive loss        -             -           (1)           (1)
----------------------------------------------------------------------------
 Balance, end of period         17            20           17            20
----------------------------------------------------------------------------
Unitholders' capital
 Balance, beginning of
  period                     2,587         2,557        2,587         2,524
 Issuance of Trust Units         -            30            -            63
----------------------------------------------------------------------------
 Balance, end of period      2,587         2,587        2,587         2,587
----------------------------------------------------------------------------
Contributed surplus
 Balance, beginning of
  period                         6             4            5             3
 Stock-based compensation
  (Note 7)                       -             -            1             1
----------------------------------------------------------------------------
 Balance, end of period          6             4            6             4
----------------------------------------------------------------------------
Total Unitholders' equity  $ 3,961       $ 3,917      $ 3,961       $ 3,917
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements


CANADIAN OIL SANDS TRUST
CONSOLIDATED BALANCE SHEETS
AS AT
(unaudited)
                                                      June 30   December 31
($ millions)                                             2010          2009
----------------------------------------------------------------------------

ASSETS
 Current assets:
  Cash and cash equivalents                         $     176     $     122
  Accounts receivable                                     300           354
  Inventories                                             123           133
  Prepaid expenses                                          4             7
----------------------------------------------------------------------------
                                                          603           616

 Property, plant and equipment, net (Note 2)            6,306         6,289
 Reclamation trust                                         50            48
----------------------------------------------------------------------------
                                                    $   6,959     $   6,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
 Current liabilities:
  Accounts payable and accrued liabilities          $     362     $     284
  Current portion of employee future benefits
   (Note 4)                                                51            17
----------------------------------------------------------------------------
                                                          413           301

 Employee future benefits and other liabilities (Note 4)   65           104
 Long-term debt                                         1,179         1,163
 Asset retirement obligation                              326           389
 Future income taxes                                    1,015         1,027
----------------------------------------------------------------------------
                                                        2,998         2,984

 Unitholders' equity                                    3,961         3,969
----------------------------------------------------------------------------
                                                    $   6,959     $   6,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements


CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
                              Three Months Ended           Six Months Ended
                                         June 30                    June 30

($ millions)                  2010          2009         2010          2009
----------------------------------------------------------------------------

Cash from (used in)
 operating activities
 Net income                 $  237        $   46       $  404        $   89
 Items not requiring
  outlay of cash:
  Depreciation, depletion
   and accretion (Note 2)       94            81          197           187
  Loss on disposal of assets     5             -            5             -
  Foreign exchange (gain)
   loss on long-term debt       50           (83)          16           (52)
  Future income tax recovery    (5)          (23)         (12)         (113)
 Actual reclamation costs       (5)            -          (28)          (22)
 Net change in deferred items
  and other                     (4)            2           (5)            3
----------------------------------------------------------------------------
                               372            23          577            92
 Change in non-cash working
  capital                      (14)          (67)          90           (86)
----------------------------------------------------------------------------
  Cash from (used in)
   operating activities        358           (44)         667             6
----------------------------------------------------------------------------

Cash from (used in)
 financing activities
 Issuance of Senior Notes        -           574            -           574
 Repayment of medium term
  and Senior Notes               -          (200)           -          (200)
 Net drawdown of bank credit
  facilities                     -           (25)           -             -
 Unitholder distributions
  (Note 8)                    (242)          (43)        (412)          (82)
----------------------------------------------------------------------------
  Cash from (used in)
   financing activities       (242)          306         (412)          292
----------------------------------------------------------------------------

Cash from (used in)
 investing activities
 Capital expenditures         (114)         (139)        (206)         (223)
 Reclamation trust funding      (2)           (1)          (3)           (2)
 Change in non-cash working
  capital                        1             3            8            14
----------------------------------------------------------------------------
  Cash used in investing
   activities                 (115)         (137)        (201)         (211)
----------------------------------------------------------------------------

Increase in cash and cash
 equivalents                     1           125           54            87

Cash and cash equivalents
 at beginning of period        175           241          122           279
----------------------------------------------------------------------------

Cash and cash equivalents
 at end of period           $  176        $  366      $  176         $  366
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash and cash equivalents
 consist of:
 Cash                                                 $   28         $    6
 Short-term investments                                  148            360
----------------------------------------------------------------------------
                                                      $  176         $  366
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information (Note 11)


NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2010

(Tabular amounts expressed in millions of Canadian dollars, except where
otherwise noted.)

1) BASIS OF PRESENTATION

The interim consolidated financial statements include the accounts of Canadian Oil Sands Trust and its subsidiaries (collectively, the "Trust" or "Canadian Oil Sands"), and are presented in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2009, except as discussed in Note 2. Certain disclosures that are normally required to be included in the notes to the annual audited consolidated financial statements have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in the Trust's annual report for the year ended December 31, 2009.

2) CHANGE IN ACCOUNTING ESTIMATE

Oil sands assets are depreciated and depleted over their estimated remaining lives, which are reviewed by management on a regular basis. During the three months ended March 31, 2010, management determined that the usage of certain tangible equipment would be most accurately represented by a straight-line calculation on an ongoing basis. Depreciation and depletion of the oil sands assets is now estimated based on a blend of both the unit-of-production and straight-line basis. The effect of this change in estimate for the three and six months ended June 30, 2010 is that approximately $35 million and $38 million less depreciation, respectively, was recorded using the new estimated remaining lives. Beyond 2010, it is not practical to estimate the effect of this change in estimate due to the long-life nature of the assets and the amounts and timing of the estimated future development costs.

3) FUTURE CHANGES IN ACCOUNTING POLICIES

The Trust will be subject to International Financial Reporting Standards ("IFRS") commencing in 2011. The Trust is currently assessing the impact that conversion to IFRS may have on its financial statements.

4) EMPLOYEE FUTURE BENEFITS

Syncrude Canada Ltd. ("Syncrude Canada"), the operator of the Syncrude Joint Venture ("Syncrude"), has a defined benefit and two defined contribution plans providing pension benefits, and other post-employment benefit plans ("OPEB") covering most of its employees. Other post-employment benefits include certain health care and life insurance benefits for retirees, their beneficiaries and covered dependents. The OPEB plan is not funded.

Canadian Oil Sands accrues its obligations as a joint venture owner in respect of Syncrude Canada's employee benefit plans and the related costs, net of plan assets. The cost of employee pension and other retirement benefits is actuarially determined using the projected benefit method based on length of service and reflects Canadian Oil Sands' best estimate of the expected performance of the plan investment, salary escalation factors, retirement ages of employees and future health care costs. The expected return on plan assets is based on the fair value of those assets. Past service costs from plan amendments are amortized on a straight-line basis over the estimated average remaining service life of active employees ("EARSL") at the date of amendment. The excess of any net actuarial gain or loss exceeding 10 per cent of the greater of the benefit obligation and fair value of the plan assets is amortized over the EARSL.

Canadian Oil Sands' share of Syncrude Canada's net defined benefit and contribution plans expense for the three and six months ended June 30, 2010 and 2009 is based on its 36.74 per cent working interest. The costs have been recorded in operating expense as follows:


                                    Three Months Ended     Six Months Ended
                                               June 30              June 30
                                    2010          2009    2010         2009
----------------------------------------------------------------------------
Defined benefit plans:
 Pension benefits                   $ 11          $  9    $ 19    $      17
 Other benefit plans                   -             1       -            3
----------------------------------------------------------------------------
                                    $ 11          $ 10    $ 19    $      20

Defined contribution plans             -             -       1            1
----------------------------------------------------------------------------
Total benefit cost                  $ 11          $ 10    $ 20    $      21
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5) BANK CREDIT FACILITIES

Extendible revolving term facility (a)                            $      40
Line of credit (b)                                                      100
Operating credit facility (c)                                           800
----------------------------------------------------------------------------
                                                                  $     940
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Each of the Trust's credit facilities is unsecured. These credit agreements contain covenants restricting Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business. In addition, Canadian Oil Sands has agreed to maintain its total debt-to-total book capitalization at an amount less than 60 per cent, or 65 per cent in certain circumstances involving acquisitions.

a) The $40 million extendible revolving term facility is a 364-day facility with a one-year term out, expiring April 21, 2011. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at June 30, 2010, no amounts were drawn on this facility ($nil - December 31, 2009).

b) The $100 million line of credit is a one-year revolving letter of credit facility. Letters of credit drawn on the facility mature April 30th each year and are automatically renewed, unless notification to cancel is provided by Canadian Oil Sands or the financial institution providing the facility at least 60 days prior to expiry. Letters of credit on this facility bear interest at a credit spread.

Letters of credit of approximately $75 million were written against the line of credit as at June 30, 2010.

c) The $800 million operating facility is a multi-year facility, expiring April 27, 2012. Amounts borrowed through this facility bear interest at a floating rate based on either prime interest rates or bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at June 30, 2010, no amounts were drawn against this facility ($nil - December 31, 2009).


6) INTEREST, NET
                                      Three Months Ended   Six Months Ended
                                                 June 30            June 30
($ millions)                          2010          2009   2010        2009
----------------------------------------------------------------------------
Interest expense on long-term debt  $   22       $    25 $   48      $   46
Interest income and other                -             -      -          (1)
----------------------------------------------------------------------------
 Interest expense, net              $   22       $    25 $   48      $   45
----------------------------------------------------------------------------
----------------------------------------------------------------------------

7) STOCK BASED COMPENSATION

During the first half of 2010, 385,274 options were issued by the Trust to employees with an average exercise price of $28.22 pursuant to the Trust's Unit Incentive Option Plan. These options had an estimated value of $2 million at the time of issue.

8) UNITHOLDER DISTRIBUTIONS

Pursuant to the Trust Indenture, the Trust distributes all the Distributable Income, as defined by the Trust Indenture, received or receivable by the Trust in a quarter. The Trust's Distributable Income primarily consists of a royalty from its operating subsidiary, Canadian Oil Sands Limited ("COSL"). The royalty is designed to capture the cash generated by COSL, after the deduction of all costs and expenses, including: operating and administrative costs, income taxes, capital expenditures, debt interest and principal repayments, working capital and reserves for future obligations deemed appropriate. The amount of royalty income that the Trust receives in any period has a considerable amount of flexibility through the use of discretionary reserves and debt borrowings or repayments (either intercompany or third party). Quarterly distributions are determined by COSL's Board of Directors after considering the current and expected economic and operating conditions, ensuring financing capacity for Syncrude's expansion projects and/or Canadian Oil Sands acquisitions, and with the objective of maintaining an investment grade credit rating.


                                Three Months Ended         Six Months Ended
                                           June 30                  June 30
                                2010          2009         2010        2009
----------------------------------------------------------------------------
Cash from operating
 activities                   $  358        $  (44)      $  667       $   6
Add (Deduct):
 Capital expenditures           (114)         (139)        (206)       (223)
 Change in non-cash working
  capital (1)                      1             3            8          14
 Reclamation trust funding        (2)           (1)          (3)         (2)
 Change in cash and cash
  equivalents and financing,
  net(2)                          (1)          254          (54)        350
----------------------------------------------------------------------------
Unitholder distributions      $  242        $   73       $  412       $ 145
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholder distributions
 per Trust Unit               $ 0.50        $ 0.15       $ 0.85       $0.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) From investing activities.
(2) Primarily represents the change in cash and cash equivalents and net
    financing to fund the Trust's share of investing activities.

9) COMMITMENTS

During April 2010, an actuarial valuation of the pension obligation as at December 31, 2009 was completed. This resulted in additional funding requirements over the next 24 years of approximately $265 million, with the majority of the funding requirements due within the next five years.

During the first six months of 2010, Syncrude entered into new capital commitments, mainly for mining equipment, the Trust's share of which is approximately $20 million.

10) CONTINGENCY

Crown royalties for 2010 include amounts due under the Syncrude Amended Royalty Agreement with the Alberta government. This agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil price adjusted for reasonable quality, transportation and handling deductions (including diluent costs) to reflect the quality and location differences between Syncrude's bitumen and the reference price of bitumen. The Alberta government, Syncrude, and the Syncrude owners are in discussions to determine the appropriate adjustments for quality, transportation and handling. For estimating and recognizing royalties, the Trust has used a bitumen value based on Syncrude and its owners' interpretation of the Syncrude Amended Royalty Agreement, and their estimates of the appropriate quality, transportation and handling adjustments. These adjustments are different than those provided under the Alberta government's generic bitumen valuation methodology. The royalties recognized for the period from January 1, 2009 to June 30, 2010 are estimated to be approximately $75 million less than the amount calculated under the generic bitumen valuation methodology. The Syncrude owners and the Alberta government continue to discuss the basis for these reasonable adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter.


11) SUPPLEMENTARY INFORMATION

                                     Three Months Ended    Six Months Ended
                                                June 30             June 30
                                     2010          2009    2010        2009
----------------------------------------------------------------------------
Income tax paid                      $  -          $  -       -        $  -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid                        $ 24          $ 10      48        $ 41
----------------------------------------------------------------------------
----------------------------------------------------------------------------

12) PRIOR PERIOD COMPARATIVES

Certain prior period comparative figures have been reclassified to conform to the current period's presentation.

Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Trust
Siren Fisekci
Vice President, Investor & Corporate Relations
(403) 218-6228
www.cos-trust.com

2500 First Canadian Centre
350 - 7 Avenue S.W.
Calgary, Alberta T2P 3N9
(403) 218-6200
(403) 218-6201 (FAX)
investor_relations@cos-trust.com
www.cos-trust.com

Canadian Oil Sands Trust Unitholders Approve Resolutions at Annual and Special Meeting, Including Conversion to Corporation

Fri, 30 Apr 2010 17:29:00 -0400

CALGARY, ALBERTA -- (MARKET WIRE) -- 04/30/10 -- Canadian Oil Sands Trust (the "Trust") (TSX: COS.UN) held its annual and special meeting of Unitholders in Calgary yesterday. A total of approximately 316,803,560 units were represented in person or by proxy.

During business proceedings the Unitholders approved, with 99 per cent of units represented voting in favour, the resolution for the plan of arrangement, with the plan for the Trust to reorganize into a corporation on or about December 31, 2010. The Court of Queen's Bench also issued a final order approving this arrangement today.

All other resolutions presented at the meeting were also approved by the Unitholders. For more information, view the Report of Voting Results available at: http://www.sedar.com.

An archive of the Web cast of the meeting may be accessed from Canadian Oil Sands' Web site at: http://www.cos-trust.com.

Canadian Oil Sands provides a pure investment opportunity in the Syncrude Project through its 36.74 per cent working interest. The Trust is an open-ended investment trust managed by Canadian Oil Sands Limited and has approximately 484.4 million units outstanding, trading on the Toronto Stock Exchange under the symbol COS.UN.

Located near Fort McMurray, Alberta, Syncrude Canada operates large oil-sands mines and an upgrading facility that produces a light, sweet crude oil on behalf of its joint venture owners, which include Canadian Oil Sands Limited, ConocoPhillips Oilsands Partnership II, Imperial Oil Resources, Mocal Energy Limited, Murphy Oil Company Ltd., Nexen Oil Sands Partnership, and Suncor Energy Oil and Gas Partnership.

Canadian Oil Sands Limited

Marcel Coutu

President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Limited
Siren Fisekci
VP, Investor and Corporate Relations:
(403) 218-6228
investor_relations@cos-trust.com
www.cos-trust.com

Canadian Oil Sands Trust Announces 2010 First Quarter Results

Thu, 29 Apr 2010 15:01:00 -0400

CALGARY, ALBERTA -- (MARKET WIRE) -- 04/29/10 -- All financial figures are unaudited and in Canadian dollars unless otherwise noted.

Canadian Oil Sands Trust ("Canadian Oil Sands", the "Trust" or "we") (TSX: COS.UN) today announced first quarter 2010 cash from operating activities of $309 million ($0.64 per Unit) compared with $50 million ($0.10 per Unit) in the same quarter in 2009. The increase in cash from operating activities was mainly due to higher crude oil prices and a decrease in non-cash working capital, partially offset by higher Crown royalties. Net income for the first quarter was $167 million ($0.35 per Unit) compared with $43 million ($0.09 per Unit) for the 2009 first quarter. The increase in net income was mainly due to higher crude oil prices and foreign exchange gains, partially offset by higher Crown royalties. The Trust has declared a distribution of $0.50 per Unit payable on May 31, 2010 to Unitholders of record on May 20, 2010.

"With an improvement in our outlook for crude oil prices, we have increased the distribution to $0.50 per Unit for the second quarter of 2010. The increase also reflects our stated objective of optimizing our tax position at the end of this year. While this level of distributions may be unsustainable, it makes sense in the near term," said Marcel Coutu, President and Chief Executive Officer. "It also returns cash to our investors in the short term without materially changing our estimated year-end net debt level."

During the first quarter of 2010, sales volumes averaged about 99,000 barrels per day compared with 103,000 barrels per day for the first quarter of 2009. The advancement and extension of a turnaround of the LC Finer and associated upgrading units and unplanned maintenance on other units reduced sales volumes in the first quarter of 2010 while first quarter 2009 sales volumes were impacted by constrained bitumen supply and the start of the Coker 8-3 turnaround.

Operating costs in the first quarter of 2010 were $39.59 per barrel compared with $38.78 per barrel in the 2009 period. First quarter 2010 operating costs were impacted by turnaround and unplanned maintenance work, similar to the 2009 first quarter when increased maintenance costs for mining activities and the start of the Coker 8-3 turnaround contributed to higher costs.

Syncrude's total recordable injury rate for the first quarter of 2010 was 0.39 compared with a rate of 0.41 for the same period of 2009.

On April 23, 2010 the ERCB approved, with conditions, Syncrude's revised tailing pond plans submitted in September 2009 under Tailings Directive 074. These plans outline a multi-pronged approach for meeting the long-term intent of Directive 074, and include the development and implementation of three main tailings technologies: water capping, composite tails and centrifuge technology. Issued by the ERCB in February 2009, Tailings Directive 074: Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes requires operators to prepare tailings plans and report on tailings ponds annually, reduce the solids content of fluid tailings through the capture of fine particles from the production process in dedicated disposal areas, and convert fines into trafficable deposits which are ready for reclamation five years after deposits have ceased. The Directive sets out very challenging targets and goals for the oil sands mining industry. Syncrude is the first operating mine to receive such an approval, and assuming the success of its developing technologies, expects to meet and exceed the requirements of the Directive.

The Trust's 2010 outlook estimates Syncrude production of 115 million barrels (42.3 million barrels, net to the Trust), with a revised production range of 110 million to 118 million barrels. Operating costs are estimated at approximately $35 per barrel, with capital expenditures totaling $532 million. Based on the Trust's assumption of WTI crude oil averaging U.S. $80 per barrel in 2010, together with the other assumptions outlined in our outlook, we are estimating cash from operating activities of $1,273 million, or $2.63 per Unit in 2010.

More information on the Trust's outlook is provided in the MD&A section of this report and the April 29, 2010 guidance document, which is available on our web site at www.cos-trust.com under "Investor".

Canadian Oil Sands Trust's Annual and Special Meeting of Unitholders will be held on April 29, 2010 at 2:30 p.m. (Mountain Daylight Time) in The Metropolitan Conference Centre, The Ballroom, 333 Fourth Avenue SW, Calgary, Alberta. A live audio Web cast of the meeting will be available on our web site at http://www.cos-trust.com/investor/EventsAndWebcasts. An archive of the Web cast will be available approximately one hour following the meeting.

At the Annual and Special Meeting of Unitholders, Canadian Oil Sands is seeking Unitholder approval for the Arrangement to convert from a trust structure to a corporation. As part of the Arrangement, Canadian Oil Sands described the dividend policy following its transition to a corporate structure. Based on current conditions, Canadian Oil Sands expects its approach to dividend payments to be very similar to its management of distribution payments as a Trust. Accordingly, dividends that Canadian Oil Sands may pay following its conversion to a corporate structure are expected to vary, reflecting changes in crude oil prices, economic conditions, Syncrude's operating performance and our operating and investing obligations. The taxability of Canadian Oil Sands after conversion also will impact cash from operating activities in future periods.

During 2010 the Trust is expecting to pay distributions in excess of its forecasted cash from operating activities less its capital expenditures in order to optimize the tax pools available to it post conversion; therefore, the current distribution is not sustainable at our current forecast crude oil price and production levels. The Trust may look to reduce net debt in advance of its increasing capital program over the next several years. This would likely require distribution reductions from current levels unless there is a significant increase in cash from operating activities.


CANADIAN OIL SANDS TRUST
Highlights

(millions of Canadian dollars,                           Three Months Ended
except per Trust unit and per                                March 31
barrel volume amounts)                                  2010          2009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income                                        $       167   $        43
Per Trust unit - Basic                           $      0.35   $      0.09

Cash from (used in) Operating Activities          $       309   $        50
Per Trust unit                                   $      0.64   $      0.10

Unitholder Distributions                          $       170   $        72
Per Trust unit                                   $      0.35   $      0.15

Sales Volumes (1)
Total (MMbbls)                                           8.9           9.3
Daily average (bbls)                                  99,286       102,825

Operating Costs ($/bbl)                           $     39.59   $     38.78

Net Realized SCO Selling Price ($/bbl)            $     82.06   $     55.32

West Texas Intermediate (average $US/bbl)(2)      $     78.88   $     43.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The Trust's sales volumes differ from its production volumes due to
changes in inventory, which are primarily in-transit pipeline volumes,
and are net of purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") was prepared as of April 29, 2010 and should be read in conjunction with the unaudited interim consolidated financial statements of Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust") for the three months ended March 31, 2010 and March 31, 2009, and the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2009 and the Trust's Annual Information Form ("AIF") dated March 22, 2010. Additional information on the Trust, including its AIF, is available on SEDAR at www.sedar.com or on the Trust's website at www.cos-trust.com. The Trust's financial results have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and are reported in Canadian dollars, unless stated otherwise.

ADVISORY- in the interest of providing the Trust's Unitholders and potential investors with information regarding the Trust, including management's assessment of the Trust's future production and cost estimates, plans and operations, certain statements throughout this MD&A and the related press release contain "forward-looking statements" under applicable securities law. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to the cost estimate for the Sulphur Emissions Reduction project and the expectation that the Sulphur Emissions Reduction project will significantly reduce total sulphur dioxide and other emissions; the completion date for the Sulphur Emissions Reduction project; future distributions and any increase or decrease from current payment amounts; the Trust's plans with regard to its net debt level by the end of 2010 and beyond; plans regarding crude oil hedges and currency hedges in the future; the expected production, revenues and operating costs for 2010; the expected level of sustaining capital for the next few years and longer term; the expectations regarding capital expenditures and operating costs; the plans regarding conversion to a corporate structure and the timing of seeking Unitholder approval; the plans and expected impact of adopting International Financial Reporting Standards; the expected impact of any current and future environmental legislation, including without limitation, regulations relating to tailings; the expectation that there will be material funding increases relative to Syncrude's future reclamation costs and pension funding for the next year; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2010 for Canadian Oil Sands' product; the potential amount payable in respect of any future income tax liability; the level of energy consumption in 2010 and beyond; capital expenditures for 2010; the level of natural gas consumption in 2010 and beyond; the expected price for crude oil and natural gas in 2010, and the anticipated impact that certain factors such as natural gas and oil prices, foreign exchange and operating costs have on the Trust's cash from operating activities and net income.

You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Trust believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A include, but are not limited to: the impacts of regulatory changes especially as such relate to royalties, taxation, and environmental charges; the impact of technology on operations and processes and how new complex technology may not perform as expected; skilled labour shortages and the productivity achieved from labour in the Fort McMurray area; the supply and demand metrics for oil and natural gas; the impact that pipeline capacity and refinery demand have on prices for our products; the unanimous joint venture owner approval for major expansions; the variances of stock market activities generally; global economic environment/volatility of markets; normal risks associated with litigation, general economic, business and market conditions; the impact of any decisions rendered by a court in relation to litigation including without limitation, any decision relating to the trial against Syncrude Canada Ltd. relating to the 2008 waterfowl incident; regulatory change, and such other risks and uncertainties described from time to time in the Trust's Annual Information Form dated March 22, 2010 and in the reports and filings made with securities regulatory authorities by the Trust as well as those assumptions outlined in the Trust's guidance document being correct. You are cautioned that the foregoing list of important factors is not exhaustive. No assurance can be given that the final legislation implementing the federal tax changes regarding income trusts will not be further changed in a manner which adversely affects the Trust and its Unitholders. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and unless required by law, the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

REVIEW OF SYNCRUDE OPERATIONS

During the first quarter of 2010, crude oil production from the Syncrude Joint Venture ("Syncrude") totaled 24.2 million barrels, or 269,000 barrels per day, compared with 24.6 million barrels, or 274,000 barrels per day, during the same period of 2009. Net to the Trust, production totaled 8.9 million barrels in the first quarter of 2010 compared with 9.0 million barrels in the first quarter of 2009, based on our 36.74 per cent working interest.

Production volumes in the first quarter of 2010 reflect the turnaround advancement and extension on the LC Finer and associated upgrading units and unplanned maintenance on other units. The turnaround work was originally scheduled for the second quarter of 2010. By comparison, production during the first quarter of 2009 was impacted by constrained bitumen production and the start of the Coker 8-3 turnaround.

Canadian Oil Sands' operating costs were $354 million, or $39.59 per barrel, in the first quarter of 2010, compared to $359 million, or $38.78 per barrel, in the same quarter of 2009. (see the "Operating costs" section of this MD&A for further discussion).

Syncrude's facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. The average design capacity is 350,000 barrels per day when allowances for scheduled maintenance and turnaround activities are included. The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes.


SUMMARY OF QUARTERLY RESULTS

($ millions, except per            2010                   2009
Trust Unit and volume amounts)      Q1       Q4       Q3       Q2       Q1
----------------------------------------------------------------------------
Revenues (1)                   $    734  $   863  $   773  $   467  $   512

Net income (loss)              $    167  $    96  $   247  $    46  $    43
Per Trust Unit, Basic
& Diluted                    $   0.35  $  0.20  $  0.51  $  0.10  $  0.09

Cash from operating activities $    309  $   328  $   213  $   (44) $    50
Per Trust Unit (2)            $   0.64  $  0.68  $  0.44  $ (0.09) $  0.10

Unitholder distributions       $    170  $   169  $   121  $    73  $    72
Per Trust Unit                $   0.35  $  0.35  $  0.25  $  0.15  $  0.15

Daily average sales
volumes (bbls) (3)              99,286  119,287  114,544   75,553  102,825

Net realized SCO selling
price ($/bbl) (4)             $  82.06  $ 78.67  $ 73.31  $ 67.92  $ 55.32

Operating costs ($/bbl) (5)    $  39.59  $ 30.18  $ 27.80  $ 50.23  $ 38.78

Purchased natural gas
price ($/GJ)                  $   4.95  $  4.33  $  2.90  $  3.09  $  4.96

West Texas Intermediate
(avg. US$/bbl) (6)            $  78.88  $ 76.13  $ 68.24  $ 59.79  $ 43.31

Foreign exchange rates
(US$/Cdn$):
Average                       $   0.96  $  0.95  $  0.91  $  0.86  $  0.80
Quarter-end                   $   0.98  $  0.96  $  0.93  $  0.86  $  0.79



($ millions, except per                                    2008
Trust Unit and volume amounts)                  Q4          Q3          Q2
----------------------------------------------------------------------------
Revenues (1)                              $     704  $    1,381  $    1,177

Net income (loss)                         $     124  $      604  $      497
Per Trust Unit, Basic & Diluted          $    0.26  $     1.25  $     1.04

Cash from operating activities            $     466  $      921  $      413
Per Trust Unit (2)                       $    0.97  $     1.91  $     0.86

Unitholder distributions                  $     361  $      602  $      481
Per Trust Unit                           $    0.75  $     1.25  $     1.00

Daily average sales volumes (bbls)(3)       110,197     116,656      97,744

Net realized SCO selling price ($/bbl)(4) $   69.40  $   127.55  $   131.32

Operating costs ($/bbl) (5)               $   32.10  $    32.15  $    41.92

Purchased natural gas price ($/GJ)        $    6.41  $     7.86  $     9.38

West Texas Intermediate (avg. US$/bbl)(6) $   59.08  $   118.22  $   123.80

Foreign exchange rates (US$/Cdn$):
Average                                  $    0.83  $     0.96  $     0.99
Quarter-end                              $    0.82  $     0.94  $     0.98


(1) Revenues after crude oil purchases and transportation expense.
(2) Cash from operating activities per Trust Unit is a non-GAAP measure
that is derived from cash from operating activities reported on the
Trust's Consolidated Statements of Cash Flows divided by the
weighted-average number of Trust Units outstanding in the period, as
used in the Trust's net income per Unit calculations.
(3) Daily average sales volumes after crude oil purchases.
(4) Net realized SCO selling price after foreign currency hedging.
(5) Derived from operating costs, as reported on the Trust's Consolidated
Statements of Income and Comprehensive Income, divided by the sales
volumes during the period.
(6) Pricing obtained from Bloomberg.

During the last eight quarters, the following items have had a significant impact on the Trust's financial results:

- Fluctuations in U.S. dollar WTI oil prices have impacted the Trust's revenues, Crown royalties, net income and cash from operating activities;

- Net income was reduced in the fourth quarter of 2009 by $148 million due to an impairment charge and goodwill write-down on the Arctic natural gas assets;

- Planned and unplanned maintenance activities as well as turnarounds have impacted quarterly production volumes, sales revenues and operating costs;

- U.S. to Canadian dollar exchange rate fluctuations have resulted in foreign exchange gains and losses on the revaluation of U.S. dollar denominated debt and have impacted commodity pricing; and

- Tax rate reductions substantively enacted in the first quarter of 2009 resulted in additional future income tax recoveries of $63 million.

REVIEW OF FINANCIAL RESULTS

In the first quarter of 2010, the Trust reported net income of $167 million, or $0.35 per Unit, compared with $43 million, or $0.09 per Unit, recorded in the first quarter of 2009. The increase in net income reflects higher revenues and foreign exchange gains, partially offset by higher Crown royalties and lower future income tax recoveries.

Revenues after crude oil purchases and transportation costs totaled $734 million in the first quarter of 2010 versus $512 million in the first quarter of 2009. The increase in revenues was due mainly to higher crude oil prices during the first quarter of 2010 (see the "Revenues after Crude Oil Purchases and Transportation Expense" section of this MD&A for further discussion).

Cash from operating activities was $309 million, or $0.64 per Unit, for the first quarter of 2010 versus $50 million, or $0.10 per Unit, for the first quarter of 2009. The increase in quarter-over-quarter cash from operating activities was due to higher revenues and a decrease in non-cash working capital, partially offset by higher Crown royalties.

Non-cash working capital increased cash from operating activities by $104 million in the first quarter of 2010, primarily as a result of higher accounts payable, reflecting increased maintenance costs incurred during the quarter. In the first quarter of 2009, non-cash working capital decreased cash from operating activities by $19 million, primarily as a result of higher accounts receivable at March 31, 2009 relative to December 31, 2008.

Non-GAAP Financial Measures

In this MD&A we refer to financial measures that do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). These non-GAAP financial measures include cash from operating activities on a per Unit basis, net debt, total capitalization, net debt to total capitalization, and certain per barrel measures. Cash from operating activities per Unit is calculated as cash from operating activities as reported on the Trust's Consolidated Statement of Cash Flows divided by the weighted-average number of Units outstanding in the period. This measure is an indicator of the Trust's capacity to fund capital expenditures, distributions, and other investing activities without incremental financing. In addition, the Trust refers to various per barrel figures, such as net realized selling prices, operating costs and Crown royalties, which also are considered non-GAAP measures, but provide meaningful information on the performance of the Trust. We derive per barrel figures by dividing the relevant revenue or cost figure by our sales volumes, which are net of purchased crude oil volumes in a period.


Net Income per Barrel

Three Months Ended
March 31
($ per bbl) (1)                               2010        2009     Variance
----------------------------------------------------------------------------

Revenues after crude oil purchases
and transportation expense                  82.10       55.32        26.78
Operating costs                             (39.59)     (38.78)       (0.81)
Crown royalties                              (8.74)      (0.48)       (8.26)
----------------------------------------------------------------------------
33.77       16.06        17.71
----------------------------------------------------------------------------

Non-production costs                         (4.04)      (3.57)       (0.47)
Administration and insurance                 (1.15)      (0.82)       (0.33)
Interest, net                                (2.96)      (2.14)       (0.82)
Depreciation, depletion and accretion       (11.49)     (11.43)       (0.06)
Foreign exchange gain (loss)                  3.72       (3.18)        6.90
Future income tax recovery and other          0.76        9.68        (8.92)
----------------------------------------------------------------------------
(15.16)     (11.46)       (3.70)
----------------------------------------------------------------------------
Net income per barrel                        18.61        4.60        14.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Sales volumes (MMbbls) (2)                     8.9         9.3         (0.4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Unless otherwise specified, net income and other per barrel measures in
this MD&A have been derived by dividing the relevant revenue or cost
item by the sales volumes in the period.
(2) Sales volumes, net of purchased crude oil volumes.



Revenues after Crude Oil Purchases and Transportation Expense

Three Months Ended
March 31
($ millions)                                  2010        2009     Variance
----------------------------------------------------------------------------

Sales revenue (1)                        $     898   $     548    $     350
Crude oil purchases                           (159)        (29)        (130)
Transportation expense                          (6)         (8)           2
----------------------------------------------------------------------------
733         511          222

Currency hedging gains (1)                       1           1            -
----------------------------------------------------------------------------
$     734   $     512    $     222
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Sales volumes (MMbbls) (2)                     8.9         9.3         (0.4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The sum of sales revenue and currency hedging gains equals Revenues on
the Trust's Consolidated Statements of Income and Comprehensive Income.
Sales revenue includes revenue from the sale of purchased crude oil and
sulphur revenue.
(2) Sales volumes, net of purchased crude oil volumes.



($ per barrel)
----------------------------------------------------------------------------
Realized SCO selling price
before hedging (3)                      $   81.96   $   55.22    $   26.74
Currency hedging gains                        0.10        0.10            -
----------------------------------------------------------------------------
Net realized SCO selling price           $   82.06   $   55.32    $   26.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(3) SCO sales revenue after crude oil purchases and transportation expense
divided by sales volumes, net of purchased crude oil volumes.

The increase in sales revenue after crude oil purchases and transportation expense in the first quarter of 2010 versus 2009 primarily reflects a higher realized selling price for our synthetic crude oil ("SCO"). During the first quarter of 2010, WTI averaged U.S. $79 per barrel compared to U.S. $43 per barrel in the first quarter of 2009. The impact of the higher U.S. dollar WTI price in the first quarter of 2010 was offset somewhat by a stronger Canadian dollar, which averaged $0.96 U.S./Cdn for the first quarter of 2010 versus $0.80 U.S./Cdn for the first quarter of 2009.

The Trust's SCO price is also affected by the premium or discount realized relative to Canadian dollar WTI (the "differential"). In the first quarter of 2010, the Trust realized a weighted-average SCO discount of $0.05 per barrel versus a premium of $1.43 per barrel for the same period of 2009. The differential is dependent upon the supply and demand for SCO and, accordingly, can change quickly depending upon the short-term supply and demand dynamics in the market and pipeline availability for transporting crude oil.

The Trust's first quarter sales volumes averaged 99,000 barrels per day and 103,000 barrels per day in 2010 and 2009, respectively. Sales volumes for the first quarter of 2010 reflect the turnaround advancement and extension on the LC Finer and a number of hydroprocessing units. Sales volumes during the first quarter of 2009 were impacted by constrained bitumen production and the start of the Coker 8-3 turnaround.

The Trust purchases crude oil from third parties to fulfill sales commitments with customers when there are shortfalls in Syncrude's production and to facilitate certain transportation and tankage arrangements and operations. Sales revenue includes revenue from the sale of purchased crude oil. Increased crude oil purchases during the first quarter of 2010 reflect additional activities to support production shortfalls and incremental purchases associated with tankage arrangements, as well as higher crude oil prices as compared to the first quarter of 2009.

Operating Costs


Three Months Ended
March 31
2010                    2009
----------------------------------------------------------------------------
$/bbl     $/bbl         $/bbl     $/bbl
Bitumen       SCO       Bitumen       SCO
----------------------------------------------------------------------------
Bitumen production           $    22.10  $  27.53    $    21.37  $  26.28
Internal fuel allocation (2)       3.27      4.07          2.32      2.85
----------------------------------------------------------------------------
Total produced bitumen costs      25.37     31.60         23.69     29.13

Upgrading costs (1)                         14.28                   14.55
Less: Internal fuel
allocation to bitumen (2)                  (4.07)                  (2.85)
Bitumen purchases                               -                    0.28
----------------------------------------------------------------------------
Total Syncrude operating
costs                                      41.81                   41.11
Canadian Oil Sands'
adjustments (3)                            (2.22)                  (2.33)
----------------------------------------------------------------------------

Total operating costs                         39.59                   38.78
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(thousands of barrels per day)    Bitumen       SCO       Bitumen       SCO
----------------------------------------------------------------------------
Syncrude production volumes (4)       336       269           337       274
----------------------------------------------------------------------------

(1) Upgrading costs include the production and ongoing maintenance costs
associated with processing and upgrading of bitumen to SCO. It also
includes the costs of major upgrading equipment turnarounds and
catalyst replacement, all of which are expensed as incurred.
(2) Natural gas prices averaged $4.95 per GJ and $4.96 per GJ in the first
quarter of 2010 and 2009, respectively.
(3) Canadian Oil Sands' adjustments mainly pertain to actual reclamation
costs, Syncrude-related pension costs, as well as the inventory impact
of moving from production to sales as Syncrude reports per barrel
costs based on production volumes and the Trust reports based on
sales volumes.
(4) Syncrude SCO production volumes include the impact of processed
purchased bitumen volumes.



Three Months Ended
March 31
($/bbl of SCO)                                           2010          2009
----------------------------------------------------------------------------

Production costs                                   $    34.36    $    33.12
Purchased energy                                         5.23          5.66
----------------------------------------------------------------------------
Total operating costs                            $    39.59    $    38.78
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(GJs/bbl of SCO)
----------------------------------------------------------------------------
Purchased energy consumption                             1.06          1.14
----------------------------------------------------------------------------

In the first quarter of 2010, operating costs were $354 million, averaging $39.59 per barrel, compared to $359 million, or $38.78 per barrel in the first quarter 2009.

Operating costs in the first quarter of 2010 reflect the turnaround advancement and extension on the LC Finer and associated upgrading units and unplanned maintenance. By comparison, operating costs in the first quarter of 2009 reflect maintenance costs in respect of mining activities, and the start of the Coker 8-3 turnaround that began in March 2009. Purchased energy consumption was also higher in the first quarter of 2009 due to the coker turnaround.

Non-Production Costs

Non-production costs totaled $36 million and $33 million in the first quarters of 2010 and 2009, respectively. Non-production costs consist primarily of development expenditures relating to capital programs, such as pre-feasibility engineering, technical and support services, research and development, and regulatory and stakeholder consultation expenditures. Non-production costs can vary on a periodic basis depending on the number of projects underway and the status of the projects.

Crown Royalties

In the first quarter of 2010, Crown royalties increased to $78 million, or $8.74 per barrel, from $4 million, or $0.48 per barrel, in the comparable 2009 quarter. Crown royalties in the first quarter of 2009 were paid at the minimum one per cent bitumen royalty rate, while first quarter 2010 Crown royalties were accrued at 25 per cent of net revenues and reflect higher deemed bitumen revenues. First quarter 2010 Crown royalties also reflect the additional royalty expense under the transition agreement with the Alberta government, which did not apply until January 1, 2010.

The Syncrude Amended Royalty Agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil price adjusted for reasonable quality, transportation and handling deductions (including diluent costs) to reflect the quality and location differences between Syncrude's bitumen and the reference price of bitumen. The Alberta government, Syncrude, and the Syncrude owners are in discussions to determine the appropriate adjustments for quality, transportation and handling. For estimating and paying royalties, Syncrude has used a bitumen value based on Syncrude and its owners' interpretation of the Syncrude Amended Royalty Agreement, and their estimates of the appropriate quality, transportation and handling adjustments. These adjustments are different than those provided under the Alberta government's generic bitumen valuation methodology. The Syncrude owners and the Alberta government continue to discuss the basis for these reasonable adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter.


Interest Expense, Net

Three Months Ended
March 31
($ millions)                                             2010          2009
----------------------------------------------------------------------------

Interest expense on long-term debt                  $      26     $      21
Interest income and other                                   -            (1)
----------------------------------------------------------------------------
Interest expense, net                             $      26     $      20
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The increase in interest expense on long-term debt was mainly due to consent solicitation fees paid for the Trust's corporate conversion plans. Interest expense in the first quarter of 2010 also reflects the refinancing of 2009 debt maturities with a higher coupon interest rate of 7.75 per cent on the U.S. $500 million senior note issue in the second quarter of 2009.


Depreciation, Depletion and Accretion Expense

Three Months Ended
March 31
($ millions)                                             2010          2009
----------------------------------------------------------------------------

Depreciation and depletion expense                  $      97     $     102
Accretion expense                                           6             4
----------------------------------------------------------------------------
$     103     $     106
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Oil sands assets are depreciated and depleted over their estimated remaining lives, which are reviewed by management on a regular basis. During the period, management determined that the usage of certain tangible equipment would be most accurately represented by a straight-line calculation on an ongoing basis. Depreciation and depletion of the oil sands assets is now estimated based on a blend of both a unit-of-production and straight-line basis. The effect of this change in estimate for the three months ending March 31, 2010 is that approximately $3 million less depreciation was recorded using the new estimated remaining lives. Beyond 2010, it is not practical to estimate the effect of this change in estimated useful lives due to the long-life nature of the assets and the magnitude and timing of estimated future development costs.


Foreign Exchange (Gain) Loss

Three Months Ended
March 31
($ millions)                                             2010          2009
----------------------------------------------------------------------------

Foreign exchange (gain) loss-long term debt         $     (34)    $      31
Foreign exchange (gain) loss-other                          1            (2)
----------------------------------------------------------------------------
Total foreign exchange (gain) loss                $     (33)    $      29
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Foreign exchange ("FX") gains/losses are primarily the result of revaluations of our U.S. dollar denominated long-term debt caused by fluctuations in U.S. and Canadian dollar exchange rates.

The FX gains on long-term debt in the first quarter of 2010 were due to a strengthening in the value of the Canadian dollar relative to the U.S. dollar to $0.98 U.S./Cdn at March 31, 2010 from $0.96 U.S./Cdn at December 31, 2009. The FX losses in the first quarter of 2009 were due to the weakening of the Canadian dollar relative to the U.S. dollar to $0.79 U.S./Cdn at March 31, 2009 from $0.82 U.S./Cdn at December 31, 2008.

Future Income Tax and Other

In the first quarter of 2010, a future income tax recovery of $7 million was recorded versus a future income tax recovery of $90 million in the same period of 2009. In addition to the future income tax amounts recorded on changes in temporary differences between accounting and tax values of Canadian Oil Sands' assets and liabilities, a future income tax recovery of $63 million was recorded during the first quarter of 2009 on the substantive enactment of tax rate reductions.

With the taxation of income trusts effective January 1, 2011, Canadian Oil Sands has implemented a plan to convert to a corporation on or around December 31, 2010. Further information is provided in the "Corporate Conversion" section of this MD&A.

CAPITAL EXPENDITURES

In the first quarter of 2010, capital expenditures totaled $92 million compared with expenditures of $84 million in the same quarter of 2009. The Syncrude Emissions Reduction ("SER") project accounted for $27 million and $25 million of the capital spent in the first quarters of 2010 and 2009, respectively, with the remaining first quarter expenditures primarily related to other sustaining capital activities. Capital expenditures on a per barrel basis were $10.33 and $9.10 in each of the first quarters of 2010 and 2009, respectively.

Canadian Oil Sands' expansion-related capital expenditures have been relatively low in recent years and capital costs during the first quarters of 2010 and 2009 were mainly related to sustaining capital. Expansion-related capital are costs incurred to grow the productive capacity of the operation while sustaining capital is effectively all other capital. Capital expenditures may fluctuate considerably year-to-year due to the timing of expansions, equipment replacement and other factors.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS


UNITHOLDER DISTRIBUTIONS

Three Months Ended
March 31
----------------------------------------------------------------------------
($ millions)                                             2010          2009
----------------------------------------------------------------------------

Cash from operating activities                       $    309     $      50

Net income                                           $    167     $      43

Unitholder distributions                             $    170     $      72
----------------------------------------------------------------------------

Excess (shortfall) of cash from operating
activities over Unitholder distributions            $    139     $     (22)

Excess (shortfall) of net income over Unitholder
distributions                                       $     (3)    $     (29)
----------------------------------------------------------------------------

In the first quarter of 2010, cash from operating activities exceeded Unitholder distributions by $139 million. Cash from operating activities was sufficient to fund the Trust's capital expenditures, reclamation trust fund contributions, and distributions.

Unitholder distributions exceeded net income by $3 million and $29 million in the first quarter of 2010 and 2009, respectively, primarily as a result of non-cash items included in the calculation of net income such as depletion, depreciation and accretion ("DD&A") and unrealized foreign exchange gains or losses. These non-cash items do not affect the Trust's cash from operating activities or ability to pay distributions over the near term.

On April 29, 2010 the Trust declared a quarterly distribution of $0.50 per Unit in respect of the second quarter of 2010 for a total distribution of $242 million. The distribution will be paid on May 31, 2010 to Unitholders of record on May 20, 2010. Quarterly distributions are approved by our Board of Directors after considering the current and expected economic conditions, ensuring financing capacity for Canadian Oil Sands' capital requirements and with the objective of maintaining an investment grade credit rating.

The $0.15 per Unit distribution increase over the prior quarter reflects actual first quarter 2010 results and higher forecast oil prices for the remainder of 2010. The Trust maintains its objective of increasing tax pools to approximately $2 billion by the end of 2010, which may slightly raise leverage levels if achieved. As a result, the Trust is currently paying distributions in excess of its forecasted cash from operating activities less its capital expenditures. The current distribution is therefore not sustainable at our current forecast oil price and production levels. The Trust may look to reduce net debt in advance of its increasing capital program over the next several years. This would likely require distribution reductions from current levels unless there is a significant increase in cash from operating activities. Further, the taxation of Canadian Oil Sands beyond January 1, 2011 will likely reduce future cash from operating activities.

Cash from operating activities and net income can fluctuate from period to period due to Syncrude's operating performance, WTI pricing, SCO differentials to WTI, FX rates and other factors. The Trust strives to reduce the impact of these fluctuations on distributions by taking a longer-term view of the operating and business environment, our net debt level, and our capital expenditure and other commitments. In that regard, the Trust may distribute more or less in a period than is generated in cash from operating activities or net income. The variable nature of cash from operating activities introduces risk in the ability to sustain or provide stability in distributions. As such, any expectations regarding the stability or sustainability of distributions are unwarranted and should not be implied.

In determining the Trust's distributions, Canadian Oil Sands also considers funding for its significant operating obligations, which are included in cash from operating activities. Such obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to $34 million and $33 million in the first quarters of 2010 and 2009, respectively. We anticipate these funding requirements to approximately double in 2010 from our 2009 funding requirements of $69 million. The anticipated increases in funding requirements are due to increased reclamation activities, as well as pension funding increases as a result of the next pension actuarial valuation, which will be completed in the second quarter of 2010.

Debt covenants do not specifically limit the Trust's ability to pay distributions and are not expected to influence the Trust's liquidity in the foreseeable future. Aside from covenants relating to restrictions on Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business, the most restrictive financial covenant limits total debt-to-total capitalization at less than 55 per cent. With a net debt-to-total capitalization of approximately 19 per cent at March 31, 2010, a significant increase in debt or decrease in equity would be required to restrict the Trust's financial flexibility.


LIQUIDITY AND CAPITAL RESOURCES

March 31    December 31
($ millions)                                            2010           2009
----------------------------------------------------------------------------

Long-term debt                                         1,129          1,163
Cash and cash equivalents                               (175)          (122)
----------------------------------------------------------------------------
Net debt                                         $      954    $     1,041
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholders' equity                               $    3,966    $     3,969
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total capitalization (1)                          $    4,920    $     5,010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net debt to total capitalization (%)                      19             21
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Net debt plus Unitholders' equity. Net debt, total capitalization, as
well as net debt to total capitalization are non-GAAP measures.

Net debt at March 31, 2010 decreased from December 31, 2009 mainly as a result of cash from operating activities exceeding capital expenditures and Unitholder distributions in the first quarter of 2010. In addition, the Trust realized $34 million in foreign exchange gains on long-term debt as a result of a stronger Canadian dollar.

During the first quarter of 2010, the Trust's $70 million line of credit was increased to $100 million and the term on the Trust's $40 million bilateral credit facility was extended to April 21, 2011.

UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY

The Trust's Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $15 billion with 484 million Units outstanding and a closing price of $30.45 per Unit on March 31, 2010.


Canadian Oil Sands Trust - Trading Activity

First
Quarter      March   February    January
2010       2010       2010       2010
----------------------------------------------------------------------------

Unit price
High                             $  30.98   $  30.98   $  29.94   $  30.67
Low                              $  27.35   $  27.55   $  27.63   $  27.35
Close                            $  30.45   $  30.45   $  27.95   $  27.74

Volume of Trust units traded
(millions)                           76.3       28.0       22.4       25.9
Weighted average Trust units
outstanding (millions)              484.4      484.4      484.4      484.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------

FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of February 18, 2010 approximately 73 per cent of our Units were held by Canadian residents with the remaining 27 per cent of Units being held by non-Canadian residents. Canadian Oil Sands' Trust Indenture provides that not more than 49 per cent of its Units can be held by non-Canadian residents.

The Trust regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of May 20, 2010. The Trust posts its foreign ownership levels on its web site at www.cos-trust.com under "Investor/Unit Information". The steps to manage foreign ownership levels are described in the Trust's AIF.

CORPORATE CONVERSION

In 2009, legislation for the conversion of income and royalty trusts into corporations was enacted. This legislation is designed to permit income and royalty trusts to convert into public corporations without triggering adverse Canadian tax consequences to the trusts or their unitholders. A number of income and royalty trusts in Canada have either converted or announced their intention to convert to a corporate structure.

On January 28, 2010, Canadian Oil Sands' Board approved converting to a corporate structure on or about December 31, 2010. Canadian Oil Sands' conversion plan is being put forward for Unitholder approval at the Annual and Special Meeting to be held April 29, 2010. Canadian Oil Sands expects its approach to dividend payments to be very similar to its management of distribution payments as a Trust. See the "Unitholder Distributions" section for more details on the distribution/dividend approach.

SUSTAINABLE DEVELOPMENT

FINANCIAL RISK MANAGEMENT

The Trust did not have any financial derivatives outstanding at March 31, 2010.

Crude Oil Price Risk

Canadian Oil Sands' revenues are impacted by changes in both the U.S. dollar denominated crude oil prices and U.S./Cdn FX rates. The Trust did not have any crude oil price hedges in place during the first quarter of 2010 and 2009, and does not currently intend to enter into any crude oil hedge positions. The Trust may hedge this exposure in the future, however, depending on the business environment and our growth opportunities.

Foreign Currency Risk

Canadian Oil Sands' results are affected by fluctuations in the U.S./Cdn currency exchange rates, as revenues generated are based on a U.S. dollar WTI benchmark price while certain obligations are denominated in Canadian dollars. The Trust did not have any foreign currency hedges in place during the first quarter 2010 or 2009, and does not currently intend to enter into any new currency hedge positions. The Trust may, however, hedge foreign currency exchange rates in the future, depending on the business environment and growth opportunities.

Interest Rate Risk

Canadian Oil Sands' net income and cash from operating activities are impacted by interest rate changes based on the amount of floating rate debt outstanding or upon the refinancing of maturing long-term debt at prevailing interest rates. As at March 31, 2010 there was no floating interest rate debt outstanding, and the next long-term debt maturity is in 2013.

Liquidity Risk

Liquidity risk is the risk that Canadian Oil Sands will not be able to meet its financial obligations as they fall due. Canadian Oil Sands actively manages its liquidity risk through its cash, debt and equity strategies. The next long-term debt maturity is in 2013, and the $800 million credit facility does not expire until April 27, 2012.

Credit Risk

The financial condition of some of our U.S. based refinery customers has continued to come under pressure during 2010, reflecting low refinery margins. Canadian Oil Sands carries credit insurance to help mitigate a portion of the impact should a loss occur and continues to transact primarily with investment grade customers, with the vast majority of accounts receivable at March 31, 2010 being due from investment grade energy producers and refinery based customers.

At March 31, 2010, our cash and cash equivalents were held in either cash or term deposits with high-quality senior Canadian banks. As of April 29, 2010, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.

NEW ACCOUNTING PRONOUNCEMENTS

There were no new accounting pronouncements by the CICA during the first quarter of 2010 that are expected to have a material impact on the Trust.

International Financial Reporting Standards ("IFRS") will replace Canadian GAAP for publicly accountable enterprises in Canada in 2011. Canadian Oil Sands will be required to adopt IFRS for interim and annual financial statements beginning on January 1, 2011 including comparative financial statements for 2010.

As part of its IFRS conversion project, the Trust has analyzed IFRS accounting standards, accounting policy alternatives, accounting system requirements and has prepared draft IFRS disclosures. The Trust's IFRS conversion is overseen by the Audit Committee with quarterly reports by management to that committee on the progress of the plan and any issues that may have arisen. The Trust's IFRS project will continue through 2010 and is on schedule for a January 1, 2011 implementation date. The impacts to the Trust's Consolidated Financial Statements on the adoption of IFRS are not finalized and will depend on IFRS standards existing as at January 1, 2011 and accounting policy choices made by Canadian Oil Sands.

IFRS 1 "First-Time Adoption of International Financial Reporting Standards" provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions, in certain areas, to the general requirement for full retrospective application of IFRS. The Trust is currently analyzing the accounting policy choices available under IFRS 1 and has not yet finalized which exemptions will be utilized. As such, the impact of adopting IFRS 1 on the financial statements cannot be quantified at this time.

Based on an analysis of differences between IFRS and Canadian GAAP, the amounts reported under IFRS that may differ from Canadian GAAP include asset retirement obligations, employee future benefits, Unitholders' equity, stock-based compensation and property, plant and equipment. The impacts of these differences, if any, have not been finalized at this time. Users are cautioned that the analysis will not be finalized until 2011 and that other differences may exist between amounts reported by the Trust under Canadian GAAP versus IFRS.

In addition to existing IFRS standards, new or revised IFRS standards are being developed by the International Accounting Standards Board ("IASB") that may impact the adoption of IFRS by the Trust in 2011 or thereafter. These standards include Joint Ventures, Income Taxes, Financial Instruments, Emissions Trading Schemes, Extractive Industries, Employee Future Benefits, and Measurement of Liabilities. The Trust continues to monitor these and other accounting standard developments within IFRS which might impact its IFRS conversion.

IFRS will likely result in additional disclosures in Canadian Oil Sands' financial statements of items already disclosed in other security documents in Canada. As part of preparing draft IFRS disclosures, the Trust has analyzed and will continue to analyze the additional disclosures to ensure sufficient information is available upon adoption of IFRS.

The Trust has analyzed its accounting systems in conjunction with its IFRS project and has concluded that they do not require any significant modification to adopt IFRS.

The effects of existing IFRS on the Trust's business activities have been reviewed and it is not expected that IFRS will result in any significant changes to the Trust's business activities.

The adoption of IFRS also impacts Syncrude's reporting of results to the Trust. Syncrude has an implementation project to manage its own transition to IFRS. Canadian Oil Sands and the other Syncrude owners are stewarding Syncrude's IFRS implementation to help ensure that information provided by Syncrude meets the owners' needs. Areas of impact that have been identified for Syncrude on the adoption of IFRS include the accounting and reporting of property, plant and equipment held on behalf of the joint venture participants, pensions and stock-based compensation. The financial impact of adopting IFRS on Syncrude has not been quantified at this time. Syncrude is not currently anticipating any significant modifications to its accounting systems or business activities as a result of adopting IFRS.


2010 OUTLOOK

(millions of Canadian dollars,
except volume and per barrel amounts)    April 29, 2010   January 28, 2010
----------------------------------------------------------------------------

Syncrude production (MMbbls)                         115                115
Canadian Oil Sands sales (MMbbls)                   42.3               42.3
Revenues, net of crude oil
purchases and transportation                      3,320              3,029
Operating costs                                    1,487              1,480
Operating costs per barrel                         35.20              35.04
Crown royalties                                      376                317
Capital expenditures                                 532                541
Cash from operating activities                     1,273              1,013

Business environment assumptions
---------------------------------
West Texas Intermediate (US$/bbl)               $     80           $     70
Premium (Discount) to average C$
WTI prices (C$/bbl)                            $  (2.25)          $  (2.00)
Foreign exchange rate (US$/Cdn$)                $   0.99           $   0.95
AECO natural gas (Cdn$/GJ)                      $   5.00           $   6.00

Canadian Oil Sands is estimating 2010 Syncrude production of 115 million barrels with a revised range of 110 million to 118 million barrels. This estimate incorporates actual first quarter results, including the already completed planned LC Finer turnaround, and the Coker 8-1 turnaround scheduled for the second half of the year.

Operating costs are estimated at $1,487 million, or $35 per barrel, with capital expenditures of $532 million, including $124 million for the Syncrude Emissions Reduction project.

The outlook incorporates a U.S. $80 per barrel WTI oil price, a $0.99 U.S./Cdn foreign exchange rate, and a SCO discount to Cdn dollar WTI of $2.25 per barrel. These assumptions result in estimated revenues of $3,320 million, or $79 per barrel in 2010.

We continue to estimate bitumen values at 70 per cent of Canadian dollar WTI, resulting in higher deemed bitumen revenues at our U.S. $80 per barrel WTI price assumption and $0.99 US/Cdn foreign exchange rate. This estimated increase in bitumen revenues is partially offset by an increase in the assumed bitumen cost deductions, resulting in estimated Crown royalties of $376 million, or $8.91 per barrel.

Working capital is also estimated to decrease by $137 million based on actual March 31 balances and an estimated accounts receivable decrease on December 31, 2010.

Based on the above assumptions, our 2010 outlook for cash from operating activities is $1,273 million, or $2.63 per Unit. After deducting forecasted 2010 capital expenditures of $532 million, we are estimating $741 million of remaining cash from operating activities, or $1.53 per Unit.


2010 Outlook Sensitivity Analysis (April 29, 2010)

Cash from
Operating Activities
Increase
Annual
Variable (1)                        Sensitivity   $ millions   $/Trust unit
----------------------------------------------------------------------------

Syncrude operating costs decrease    C$1.00/bbl           35           0.07
Syncrude operating costs decrease  C$50 million           15           0.03
WTI crude oil price increase        US$1.00/bbl           31           0.06
Syncrude production increase     2 million bbls           42           0.09
Canadian dollar weakening            US$0.01/C$           25           0.05
AECO natural gas price decrease       C$0.50/GJ           18           0.04


(1) An opposite change in each of these variables will result in the
opposite cash from operating activities impacts.
Canadian Oil Sands may become subject to minimum Crown royalties at a
rate of one per cent of gross bitumen revenue. The sensitivities
presented herein assume royalties are paid at 25 per cent of net
bitumen revenue.



CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(unaudited)

Three Months Ended
March 31
($ millions, except per Unit amounts)                   2010           2009
----------------------------------------------------------------------------
Revenues                                            $    899       $    549
----------------------------------------------------------------------------

Expenses:
Operating                                               354            359
Non-production                                           36             33
Crude oil purchases and transportation expense          165             37
Crown royalties                                          78              4
Administration                                            8              6
Insurance                                                 2              2
Interest, net (Note 6)                                   26             20
Depreciation, depletion and accretion (Note 2)          103            106
Foreign exchange (gain) loss                            (33)            29
----------------------------------------------------------------------------
739            596
----------------------------------------------------------------------------
Earnings (loss) before taxes                             160            (47)
Future income tax recovery and other                     (7)           (90)
----------------------------------------------------------------------------
Net income                                               167             43
Other comprehensive loss, net of income taxes
Reclassification of derivative gains to net
income                                                  (1)            (1)
----------------------------------------------------------------------------
Comprehensive income                                $    166       $     42
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average Trust Units (millions)                  484            482
Trust Units, end of period (millions)                    484            483

Net income per Trust Unit:
Basic and diluted                                  $   0.35       $   0.09

See Notes to Unaudited Consolidated Financial Statements


CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
(unaudited)

Three Months Ended
March 31
($ millions)                                            2010           2009
----------------------------------------------------------------------------
Retained earnings
Balance, beginning of period                       $  1,359       $  1,362
Net income                                              167             43
Unitholder distributions (Note 8)                      (170)           (72)
----------------------------------------------------------------------------
Balance, end of period                                1,356          1,333
----------------------------------------------------------------------------
Accumulated other comprehensive income
Balance, beginning of period                             18             21
Other comprehensive loss                                 (1)            (1)
----------------------------------------------------------------------------
Balance, end of period                                   17             20
----------------------------------------------------------------------------
Unitholders' capital
Balance, beginning of period                          2,587          2,524
Issuance of Trust Units                                   -             33
----------------------------------------------------------------------------
Balance, end of period                                2,587          2,557
----------------------------------------------------------------------------
Contributed surplus
Balance, beginning of period                              5              3
Stock-based compensation (Note 7)                         1              1
----------------------------------------------------------------------------
Balance, end of period                                    6              4
----------------------------------------------------------------------------
Total Unitholders' equity                           $  3,966       $  3,914
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements


CANADIAN OIL SANDS TRUST
CONSOLIDATED BALANCE SHEETS
AS AT
(unaudited)

March 31    December 31
($ millions)                                            2010           2009
----------------------------------------------------------------------------

ASSETS
Current assets:
Cash and cash equivalents                         $    175       $    122
Accounts receivable                                    330            354
Inventories                                            139            133
Prepaid expenses                                         6              7
----------------------------------------------------------------------------
650            616

Property, plant and equipment, net (Note 2)           6,284          6,289
Reclamation trust                                        49             48
----------------------------------------------------------------------------
$  6,983       $  6,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities          $    376       $    284
Current portion of employee future benefits
(Note 4)                                               17             17
----------------------------------------------------------------------------
393            301

Employee future benefits and other
liabilities (Note 4)                                   103            104
Long-term debt                                        1,129          1,163
Asset retirement obligation                             372            389
Future income taxes                                   1,020          1,027
----------------------------------------------------------------------------
3,017          2,984

Unitholders' equity                                   3,966          3,969
----------------------------------------------------------------------------

$  6,983       $  6,953
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements


CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)

Three Months Ended
March 31
($ millions)                                            2010           2009
----------------------------------------------------------------------------

Cash from (used in) operating activities
Net income                                         $    167       $     43
Items not requiring outlay of cash:
Depreciation, depletion and accretion (Note 2)         103            106
Foreign exchange (gain) loss on long-term debt         (34)            31
Future income tax recovery                              (7)           (90)
Net change in deferred items and other                  (24)           (21)
----------------------------------------------------------------------------
205             69
Change in non-cash working capital                      104            (19)
----------------------------------------------------------------------------
Cash from operating activities                         309             50
----------------------------------------------------------------------------

Cash from (used in) financing activities
Net drawdown of bank credit facilities                    -             25
Unitholder distributions (Note 8)                      (170)           (39)
----------------------------------------------------------------------------
Cash used in financing activities                     (170)           (14)
----------------------------------------------------------------------------

Cash from (used in) investing activities
Capital expenditures                                    (92)           (84)
Reclamation trust funding                                (1)            (1)
Change in non-cash working capital                        7             11
----------------------------------------------------------------------------
Cash used in investing activities                      (86)           (74)
----------------------------------------------------------------------------

Increase (decrease) in cash and cash equivalents          53            (38)

Cash and cash equivalents at beginning of period         122            279
----------------------------------------------------------------------------

Cash and cash equivalents at end of period          $    175       $    241
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash and cash equivalents consist of:
Cash                                                $    16       $     12
Short-term investments                                  159            229
----------------------------------------------------------------------------
$   175       $    241
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information (Note 10)

See Notes to Unaudited Consolidated Financial Statements

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2010

(Tabular amounts expressed in millions of Canadian dollars, except where otherwise noted.)

1) BASIS OF PRESENTATION

2) CHANGE IN ACCOUNTING ESTIMATE

Oil sands assets are depreciated and depleted over their estimated remaining lives, which are reviewed by management on a regular basis. During the period, management determined that the usage of certain tangible equipment would be most accurately represented by a straight-line calculation on an ongoing basis. Depreciation and depletion of the oil sands assets is now estimated based on a blend of both the unit-of-production and straight-line basis. The effect of this change in estimate for the three months ending March 31, 2010 is that approximately $3 million less depreciation was recorded using the new estimated remaining lives. Beyond 2010, it is not practical to estimate the effect of this change in estimated useful lives due to the long-life nature of the assets and the magnitude and timing of the budgeted future development costs.

3) FUTURE CHANGES IN ACCOUNTING POLICIES

4) EMPLOYEE FUTURE BENEFITS

Syncrude Canada Ltd. ("Syncrude Canada"), the operator of the Syncrude Joint Venture, has a defined benefit and two defined contribution plans providing pension benefits, and other post-employment benefit plans ("OPEB") covering most of its employees. Other post-employment benefits include certain health care and life insurance benefits for retirees, their beneficiaries and covered dependents. The OPEB plan is not funded.

Canadian Oil Sands' share of Syncrude Canada's net defined benefit and contribution plans expense for the three months ended March 31, 2010 and 2009 is based on its 36.74 per cent working interest. The costs have been recorded in operating expense as follows:


Three Months Ended
March 31
2010           2009
----------------------------------------------------------------------------

Defined benefit plans:
Pension benefits                                     $    9         $    8
Other benefit plans                                       1              2
----------------------------------------------------------------------------
$   10         $   10

Defined contribution plans                                 1              1
----------------------------------------------------------------------------
Total benefit cost                                   $   11         $   11
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5) BANK CREDIT FACILITIES

Extendible revolving term facility (a)                               $   40
Line of credit (b)                                                      100
Operating credit facility (c)                                           800
----------------------------------------------------------------------------
$  940
----------------------------------------------------------------------------
----------------------------------------------------------------------------

a) The $40 million extendible revolving term facility is a 364-day facility with a one-year term out, expiring April 21, 2011. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at March 31, 2010, no amounts were drawn on this facility ($Nil - March 31, 2009).

Letters of credit of approximately $70 million were written against the line of credit as at March 31, 2010.

c) The $800 million operating facility is a multi-year facility, expiring April 27, 2012. Amounts borrowed through this facility bear interest at a floating rate based on either prime interest rates or bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at March 31, 2010, no amounts were drawn against this facility ($25 million - March 31, 2009).


6) INTEREST, NET

Three Months Ended
March 31
($ millions)                                            2010           2009
----------------------------------------------------------------------------
Interest expense on long-term debt                    $   26         $   21
Interest income and other                                  -             (1)
----------------------------------------------------------------------------
Interest expense, net                                $   26         $   20
----------------------------------------------------------------------------
----------------------------------------------------------------------------

7) STOCK BASED COMPENSATION

During the first quarter of 2010, 363,347 options were issued by the Trust to employees with an average exercise price of $28.19 pursuant to the Trust's Unit Incentive Option Plan. The options have an estimated value of $2 million.

8) UNITHOLDER DISTRIBUTIONS

Pursuant to the Trust Indenture, the Trust distributes all the Distributable Income, as defined by the Trust Indenture, received or receivable by the Trust in a quarter. The Trust's Distributable Income primarily consists of a royalty from its operating subsidiary, Canadian Oil Sands Limited ("COSL"). The royalty is designed to capture the cash generated by COSL, after the deduction of all costs and expenses including operating and administrative costs, income taxes, capital expenditures, debt interest and principal repayments, working capital and reserves for future obligations deemed appropriate. The amount of royalty income that the Trust receives in any period has a considerable amount of flexibility through the use of discretionary reserves and debt borrowings or repayments (either intercompany or third party). Quarterly distributions are determined by COSL's Board of Directors after considering the current and expected economic and operating conditions, ensuring financing capacity for Syncrude's expansion projects and/or Canadian Oil Sands acquisitions, and with the objective of maintaining an investment grade credit rating.


Three Months Ended
March 31
2010           2009
----------------------------------------------------------------------------
Cash from operating activities                        $  309         $   50
Add (Deduct):
Capital expenditures                                    (92)           (84)
Change in non-cash working capital (1)                    7             11
Reclamation trust funding                                (1)            (1)
Change in cash and cash equivalents and
financing, net (2)                                     (53)            96
----------------------------------------------------------------------------
Unitholder distributions                              $  170         $   72
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholder distributions per Trust Unit               $ 0.35         $ 0.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) From investing activities.
(2) Primarily represents the change in cash and cash equivalents and net
financing to fund the Trust's share of investing activities.

9) COMMITMENTS

During the first quarter of 2010, Syncrude entered into new capital commitments, mainly for mining equipment, the Trust's share of which is approximately $20 million.


10) SUPPLEMENTARY INFORMATION

Three Months Ended
March 31
2010           2009
----------------------------------------------------------------------------

Income tax paid                                            -         $    -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid                                             24         $   31
----------------------------------------------------------------------------

Canadian Oil Sands Limited

Marcel Coutu

President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Trust
Siren Fisekci
Vice President, Investor & Corporate Relations
(403) 218-6228
investor_relations@cos-trust.com
www.cos-trust.com

Canadian Oil Sands Trust Annual and Special Meeting

Mon, 26 Apr 2010 12:29:00 -0400

CALGARY, ALBERTA -- (MARKET WIRE) -- 04/26/10 -- Canadian Oil Sands Trust (TSX: COS.UN) plans to release its first quarter 2010 results and hold its annual and special meeting of Unitholders on Thursday, April 29, 2010 at 2:30 p.m. (mountain standard time) in the Ballroom of the Metropolitan Conference Centre, located at 333 Fourth Avenue SW, Calgary, Alberta.

A live audio Web cast of the meeting can be accessed from Canadian Oil Sands' Web site at: http://www.cos-trust.com. An archived version of the Web cast and presentation material also will be available shortly after the live Web cast from the Web site.

The close of business on March 12, 2010 was fixed as the record date for determination of those Unitholders entitled to receive notice and to vote at the meeting. All proxies must be received by Computershare Trust Company no later than 2:30 p.m. (mountain standard time) on Wednesday, April 28, 2010.

Canadian Oil Sands Limited

Marcel Coutu

President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Trust
Siren Fisekci
VP, Investor and Corporate Relations
(403) 218-6228
investor_relations@cos-trust.com
www.cos-trust.com

Canadian Oil Sands Trust Amends Terms Related to Its Conversion to a Corporation

Fri, 16 Apr 2010 17:45:00 -0400

CALGARY, ALBERTA -- (MARKET WIRE) -- 04/16/10 -- Canadian Oil Sands Trust (the "Trust" or "Canadian Oil Sands") (TSX: COS.UN) today revised certain terms related to its Plan of Arrangement for conversion to a corporation, as described in Canadian Oil Sands' Management Proxy Circular dated March 15, 2010. Having considered requests from RiskMetrics Group, ISS Governance Services for Canadian Oil Sands to make clarifications and non-consequential changes to its post conversion structure, Canadian Oil Sands has agreed to:


--  Limit the number of preferred shares that New COSL, as defined in the
Management Proxy Circular, could issue to a maximum of 10 million and
that management has confirmed that such preferred shares are not
intended to be used to block any takeover. Prior to this amendment, the
number of preferred shares New COSL could issue was unlimited; and

--  Specify that the quorum requirements for meeting of shareholders for New
COSL will be at least two holders present in person and/or by proxy who
together hold at least 25 per cent of the issued and outstanding number
of Common Shares of New COSL. Prior to this clarification, the
Management Proxy Circular had been silent on this issue.

With these amendments, RiskMetrics has confirmed that they will issue an updated alert whereby they will recommend voting FOR all resolutions at the Trust's unitholder meeting being held on April 29, 2010, including voting FOR the conversion from a trust to a corporation (item 1) and FOR the amendment to Section 5.1 of the Trust Indenture (Item 8).

Canadian Oil Sands Trust provides a pure investment opportunity in the Syncrude Project through its 36.74 per cent working interest. Located near Fort McMurray, Alberta, Syncrude operates large oil-sands mines and an upgrading facility that produces a high-quality, sweet crude oil. The Trust is an open-ended investment trust managed by Canadian Oil Sands Limited and has approximately 484.4 million units outstanding, trading on the Toronto Stock Exchange under the symbol COS.UN.

Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Trust
Trudy Curran
General Counsel and Corporate Secretary
(403) 218-6240
investor_relations@cos-trust.com
www.cos-trust.com

Canadian Oil Sands Files Syncrude Reserves and Resources

Fri, 26 Mar 2010 14:15:00 -0400

CALGARY, ALBERTA -- (MARKET WIRE) -- 03/26/10 -- Canadian Oil Sands Trust (TSX: COS.UN) ("Canadian Oil Sands") today announced that it has filed the results of the independent evaluation of its reserves and a review of its resources for the Syncrude Project leases at December 31, 2009 with the Canadian securities administrators on the SEDAR web site. This information also is available in Canadian Oil Sands' Annual Information Form dated March 22, 2010 and posted on our web site at:

http://www.cos-trust.com/investor/Financials/default.aspx under 2009 Supplemental Information.

Based on an independent engineering evaluation conducted by GLJ Petroleum Consultants Ltd. ("GLJ") effective December 31, 2009 and prepared in accordance with National Instrument 51-101, Canadian Oil Sands had proved plus probable reserves of 1.9 billion barrels. All reserve information in this press release is based on Canadian Oil Sands' working interest of 36.74 per cent in the Syncrude Joint Venture as at December 31, 2009. Proved developed producing reserves represent 52 per cent of proved plus probable reserves. Proved non-producing reserves have not been assigned. Canadian Oil Sands currently produces only one product type, namely synthetic crude oil, which is a high-quality light, sweet crude oil.


---------------------------------------------------------------------------

Reserves and Resources (1)(Billions of barrels of    Syncrude Canadian Oil
synthetic crude oil)                                  Project      Sands(2)
---------------------------------------------------------------------------
Proved plus Probable Reserves                             5.1          1.9
Contingent Resources - best estimate                      4.8          1.8
Prospective Resources - best estimate                     2.0          0.7
---------------------------------------------------------------------------

(1) Based on independent reserves and resources estimates by GLJ Petroleum
    Consultants Ltd. as of December 31, 2009. See reserves and resources
    cautionary advisory in Canadian Oil Sands' Annual Information Form
    dated March 22, 2010 and the definitions provided later in this
    release.
(2) The Trust, through its operating subsidiary, holds a 36.74 per cent
    interest in the Syncrude Project.

Reserves and Resources Definitions:

Proved Reserves are reserves that can be estimated with a high degree of certainty to be recoverable. NI 51-101 further identifies the certainty level for proved reserves as "at least a 90 per cent probability that the quantities actually recovered will equal or exceed the estimated proved reserves".

Proved plus Probable Reserves are additional reserves that are less certain to be recovered than proved reserves. NI 51-101 defines the certainty level as "at least a 50 per cent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves". Therefore, under NI 51-101, the proved plus probable reserves represent a "best estimate" or "expected reserves".

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.

Best Estimate is a term used to describe an uncertainty category for resources estimates referring to the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the "best estimate". The best estimate of the Contingent and Prospective Resources is prepared independent of the risks associated with achieving commercial production.

Advisory: in the interest of providing Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust") unitholders and potential investors with information regarding the Trust, including management's assessment of the Trust's future plans and operations, certain statements throughout this release contain "forward-looking statements" under applicable securities law. Forward-looking statements in this release include, but are not limited to, statements with respect to: the expected extension of the resource life and the potential to have higher production levels as a result of the new resource information; the expected amount to be recoverable from resources and reserves and any approval by the Syncrude owners of further expansion plans. You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Trust believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this release include, but are not limited to: the lack of precision around estimates of resources and reserves; the requirement for all Syncrude owners to approve major capital expansion plans under the Syncrude joint venture agreement and such other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by the Trust. You are cautioned that the foregoing list of important factors is not exhaustive. Furthermore, the forward-looking statements contained in this release are made as of the date of this release, and the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. In any reference to resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. The forward-looking statements contained in this release are expressly qualified by this cautionary statement.

Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Trust
Siren Fisekci
VP, Investor and Corporate Relations
(403) 218-6228
investor_relations@cos-trust.com
www.cos-trust.com

Canadian Oil Sands Trust Files Its Year End Continuous Disclosure Documents

Fri, 26 Mar 2010 14:13:00 -0400

CALGARY, ALBERTA -- (MARKET WIRE) -- 03/26/10 -- Canadian Oil Sands Trust (TSX: COS.UN) (the "Trust") today filed with Canadian securities authorities the Trust's Annual Information Form for the year ended December 31, 2009, including disclosure and reports relating to reserves data and other oil and gas information pursuant to National Instrument 51-101. The Trust previously filed its audited consolidated annual financial statements and related disclosure documents on March 15, 2010. Copies of these filed documents may be obtained through www.sedar.com, the Trust's website at www.cos-trust.com, or by emailing the Trust at investor_relations@cos-trust.com.

Canadian Oil Sands Trust is an open-ended investment trust that generates income from its indirect 36.74 per cent working interest in the Syncrude Joint Venture. The Trust currently has approximately 484.4 million units outstanding, which trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust is managed by Canadian Oil Sands Limited.

Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Trust
Siren Fisekci
VP, Investor and Corporate Relations
(403) 218-6228
investor_relations@cos-trust.com
www.cos-trust.com

Canadian Oil Sands Provides Update of Syncrude Expansion Plans

Wed, 24 Feb 2010 08:00:00 -0500

CALGARY, ALBERTA -- (MARKET WIRE) -- 02/24/10 -- Canadian Oil Sands Trust (TSX: COS.UN) (the "Trust" or "Canadian Oil Sands" or "we") today provided an update to the growth plans for our Syncrude project. Based on preliminary scoping and design work being done by Syncrude and ExxonMobil, Syncrude's view now is that their existing Mildred Lake upgrading facility has latent capacity that can be unlocked through a series of debottleneck projects. This should allow synthetic crude oil production to grow to approximately 425,000 barrels per day by the end of this decade. These debottleneck projects involve accessing the excess coking capacity that was constructed during Syncrude's last expansion, making modifications to other facilities, and potentially adding new ancillary units.

The expanded upgrader capacity would be supplied by bitumen from the undeveloped Aurora South mine. In December 2009, Syncrude submitted an update report to the regulators further to the conditions for approval received for Aurora South in 1998. Syncrude plans to begin constructing a mining train on Aurora South around 2012 with production expected by the end of 2016. Construction on a second mining train is planned to begin around 2014 with production commencing towards the end of the decade. Each mine train is designed for capacity of about 100,000 barrels of bitumen per day, resulting in total bitumen productive capacity of 600,000 barrels per day by 2020 at Syncrude. This volume exceeds the upgrader's processing capacity, resulting in roughly 115,000 barrels of excess bitumen supply. Syncrude is considering incorporating new technology in the construction of the Aurora South mine trains aimed at improving bitumen recovery levels, energy efficiency and product quality. The improvement in product quality would also allow for pipeline transportation and sales of surplus bitumen volumes.

These growth plans would result in Syncrude broadening its production from the current light, sweet synthetic blend to a slate including heavy and sour blends. Decisions regarding further upgrading capacity will be considered in the future in the context of evolving heavy/light crude oil price spreads.

"Under today's economic conditions, we believe these expansion plans have the advantage of bringing on production growth with less project execution risk and better economics than constructing greenfield upgrading facilities," said Marcel Coutu, Canadian Oil Sands' President and Chief Executive Officer. "I believe that, given the size of Syncrude's resource base, we still have the ability to grow beyond this expanded 600,000 barrel per day productive capacity level."

Cost estimates for these expansion plans are not yet available. The plans are subject to regulatory approval. As well, approvals from Syncrude's joint venture owners and Canadian Oil Sands' Board of Directors are required to move from scoping to detailed engineering work and then construction. ExxonMobil, majority owner of Imperial Oil, is providing the project management expertise under the Management Services Agreement between Syncrude Canada Ltd. and Imperial Oil.

Located near Fort McMurray, Alberta, Syncrude operates large oil-sands mines and an upgrading facility that produces a light, sweet crude oil on behalf of its joint venture owners, which include Canadian Oil Sands Limited, ConocoPhillips Oilsands Partnership II, Imperial Oil Resources, Mocal Energy Limited, Murphy Oil Company Ltd., Nexen Oil Sands Partnership, and Petro-Canada Oil and Gas (Suncor). Canadian Oil Sands provides a pure investment opportunity in the Syncrude project through its 36.74 per cent working interest. The Trust is managed by Canadian Oil Sands Limited and has approximately 484.4 million units outstanding, trading on the Toronto Stock Exchange under the symbol COS.UN.

Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Limited
Siren Fisekci
VP, Investor and Corporate Relations
(403) 218-6228
investor_relations@cos-trust.comwww.cos-trust.com

Canadian Oil Sands Trust Provides Tax Information for 2009 Distributions

Mon, 22 Feb 2010 17:42:00 -0500

CALGARY, ALBERTA -- (MARKET WIRE) -- 02/22/10 -- Canadian Oil Sands Trust (the "Trust") (TSX: COS.UN) today reported the tax information for the cash distributions declared and paid in 2009 to Unitholders resident in Canada and the United States ("U.S.").

The following information is provided for general information only and should not be considered tax or legal advice to any particular existing or potential holder of Trust units. Unitholders are strongly encouraged to consult their tax advisors with respect to their particular circumstances.

Tax information for Unitholders resident in Canada

The following information is based on the Trust's understanding of the Income Tax Act (Canada) and regulations thereunder.

No amounts are required to be reported for tax purposes in respect of cash distributions on the Trust's Units received in 2009 by a Registered Retirement Savings Plan, Registered Pension Plan, Registered Retirement Income Fund or Deferred Profit Sharing Plan or any other such registered plans ("Deferred Plans"). For cash distributions received by a Canadian resident individual outside of a Deferred Plan, 99.991 per cent of the payments are taxable as income.

The following table outlines the breakdown of cash distributions per Unit paid by the Trust with respect to record dates for the year ended December 31, 2009.


----------------------------------------------------------------------------
                                                    Cdn$
                                                 Taxable
                                  Cdn$ Total  Amount Per  Cdn$ Tax Deferred
                                        Cash        Unit    Amount Per Unit
                                Distribution     (99.991             (0.009
Record Date      Payment Date       Per Unit    per cent)          per cent)
----------------------------------------------------------------------------
Feb. 9, 2009    Feb. 27, 2009           0.15     0.14999            0.00001
May 11, 2009     May 29, 2009           0.15     0.14999            0.00001
Aug. 17, 2009   Aug. 28, 2009           0.25     0.24998            0.00002
Nov. 20, 2009   Nov. 30, 2009           0.35     0.34997            0.00003
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total                                   0.90     0.89993            0.00007
----------------------------------------------------------------------------

T3 Statement of Trust Income Allocations and Designations forms are expected to be mailed to the Trust's Unitholders on or before March 31, 2010 by your financial institution if the Units are held in non-registered or nominee form, or by Computershare if the Units are held in registered form.

Tax information for Unitholders resident in the U.S.

Canadian Oil Sands believes that the distributions paid in the 2009 calendar year are considered foreign-source dividend income under U.S. federal income tax principles. Providing that applicable holder-level requirements are met, these distributions are "qualified dividends" eligible for taxation at reduced rates under U.S. federal income tax legislation; however, Canadian Oil Sands has not received an IRS letter ruling or tax opinion from its tax advisors on these matters, and the individual taxpayer's situation must be considered before making this determination.

Generally, distributions payable to non-residents of Canada are normally subject to a withholding tax of 25 per cent as prescribed by the Income Tax Act (Canada); however, the withholding tax for residents of the U.S. is prescribed at 15 per cent in accordance with a reciprocal tax treaty between the U.S. and Canada. U.S. taxpayers may be eligible for a foreign tax credit with respect to the Canadian withholding taxes paid. Other jurisdictions may also have reciprocal tax treaties that would reduce the withholding tax rate.

A Canadian NR4 (non-resident) supplemental form detailing the Canadian tax withheld and remitted to the Canadian government will be mailed to the Trust's non-resident Unitholders by your financial institution if the Units are held in non-registered or nominee form, or by Computershare if the Units are held in registered form.

The following table provides the breakdown of the amount of cash distribution, prior to the Canadian withholding tax, paid by the Trust in 2009.


----------------------------------------------------------------------------
                               US$/Cdn$                         Per cent of
                              Currency                         Distribution
                              Exchange          US$               Return of
                         Cdn$  Rate on   Equivalent  Per cent of    Capital/
Record   Payment Distribution  Payment Distribution Distribution    Capital
Date        Date     Per Unit     Date     Per Unit      Taxable       Gain
----------------------------------------------------------------------------
Feb. 9,  Feb. 27,
 2009       2009         0.15   0.7870      0.11805        89.42      10.58
May 11,   May 29,
 2009       2009         0.15   0.9123      0.13685        89.42      10.58
Aug. 17, Aug. 28,
 2009       2009         0.25   0.9192      0.22980        89.42      10.58
Nov. 20, Nov. 30,
 2009       2009         0.35   0.9457      0.33100        89.42      10.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total                    0.90               0.81570        89.42      10.58
----------------------------------------------------------------------------

It is possible that the U.S. dollar amount was different for non-registered, or beneficial Unitholders receiving their payment from an intermediary or brokerage firm using different exchange rates.

For any questions regarding the supplemental tax forms, please contact your financial institution if your Units are held in non-registered form. If your Units are held in registered form, contact the Trustee and Transfer Agent, Computershare Trust Company of Canada, at 1-800-564-6253. For all other inquiries, please contact the Trust.

Further information on distributions paid by the Trust, including a tax summary of distributions paid since inception, is available on the Trust's Web site at www.cos-trust.com under Investor/Distributions.

Canadian Oil Sands Limited

Marcel Coutu

President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Limited
Siren Fisekci
VP, Investor and Corporate Relations
(403) 218-6228
investor_relations@cos-trust.comwww.cos-trust.com

Canadian Oil Sands Trust Announces 2009 Fourth Quarter Results

Thu, 28 Jan 2010 17:15:00 -0500

CALGARY, ALBERTA -- (MARKET WIRE) -- 01/28/10 -- Canadian Oil Sands Trust ("Canadian Oil Sands", the "Trust" or "we") (TSX: COS.UN) today announced cash from operating activities of $328 million ($0.68 per Trust Unit ("Unit")) for the fourth quarter of 2009 compared with cash from operating activities of $466 million ($0.97 per Unit) for the same period last year. The decrease reflects increases in non-cash working capital and higher Crown royalties, partially offset by higher revenues.

For the year ended December 31, 2009 cash from operating activities decreased to $547 million ($1.13 per Unit) from $2,241 million ($4.66 per Unit) in 2008. The decrease reflects the significant decline in crude oil prices in 2009 versus 2008, as well as lower production and increases in non-cash working capital, partially offset by lower Crown royalties.

In the fourth quarter of 2009, the Trust reported net income of $96 million ($0.20 per Unit) compared with net income of $124 million ($0.26 per Unit) recorded in the same period of 2008. Excluding impairment charges on the Trust's Arctic assets, net income in the fourth quarter of 2009 was $244 million ($0.50 per Unit), reflecting higher sales volumes, oil prices and foreign exchange gains, partially offset by higher Crown royalties. On an annual basis, net income totaled $432 million ($0.89 per Unit) in 2009, down from $1,523 million ($3.17 per Unit) in 2008. The decline primarily reflects lower crude oil prices and production, partially offset by lower Crown royalties.

The Trust has declared a quarterly distribution amount of $0.35 per Unit for Unitholders of record on February 18, 2010, payable on February 26, 2010.

Net debt at the end of 2009 was $1,041 million, similar to net debt of $979 million at the end of 2008. The Trust continues to maintain a strong financial position with net debt to total capitalization of 21 per cent.

"Unplanned downtime and maintenance exceeded our budgeted allowance during 2009, impacting both production and costs," said Marcel Coutu, President and Chief Executive Officer. "Although 2009 production was 12 per cent below our budget, we once again demonstrated that the plant can run at robust rates with December production running at 360,000 barrels per day. Syncrude's priority is to improve operational reliability to achieve design capacity rates more consistently."

Sales volumes in 2009 averaged 103,000 barrels per day compared with 106,000 barrels per day in 2008. Production in 2009 was impacted by: turnaround and modification work on Syncrude's Coker 8-3 complex; bitumen constraints; and reliability issues in the mining and upgrading processes, including circulation issues with Coker 8-1 and unplanned repairs to the vacuum distillation unit. Production in 2008 was impacted by planned turnarounds of Cokers 8-2 and 8-1, bitumen production constraints and a disruption in operations during the first quarter.

Following repairs to the vacuum distillation unit during November 2009, production ramped up significantly, resulting in fourth quarter 2009 sales volumes averaging 119,000 barrels per day. By comparison, sales volumes in 2008 averaged 110,000 barrels per day during the fourth quarter.

Operating costs in 2009 were $35.29 per barrel, virtually the same as 2008 costs of $35.26 per barrel. Operating costs in both years reflect coker turnarounds and unplanned maintenance.

Capital expenditures in 2009 were $409 million compared with $281 million in 2008. Expenditures in both years relate mainly to sustaining capital, as Syncrude currently is not incurring meaningful expansion-related capital to grow productive capacity. In 2009, the expenditures related to the Syncrude Emissions Reduction project, equipment purchases to improve bitumen production, modifications to the Coker 8-3 complex, construction of tailings facilities, and other infrastructure projects.

Syncrude's total recordable injury rate for 2009 was 0.36 compared with a rate of 0.59 for 2008. While the recordable injury rate declined, the fatality that occurred in November 2009 marred the improvement in our overall safety performance. An investigation into the fatality is underway to determine what occurred and to prevent a similar tragedy in the future. Syncrude is committed to protecting and promoting the safety and well being of its employees and contractors. Investment in training, awareness activities, and other initiatives is continuing in order to foster further improvements in workplace safety.

CANADIAN OIL SANDS TRUST
Highlights

                                     Three Months Ended  Twelve Months Ended
                                            December 31          December 31
(millions of Canadian dollars,
 except per Trust unit and per
 barrel volume amounts)                  2009      2008      2009      2008
----------------------------------------------------------------------------

Net Income                            $    96   $   124   $   432  $  1,523
 Per Trust unit- Basic                $  0.20   $  0.26   $  0.89  $   3.17
 Per Trust unit- Diluted              $  0.20   $  0.26   $  0.89  $   3.16

Cash from (used in) Operating
 Activities                           $   328   $   466   $   547  $  2,241
 Per Trust unit                       $  0.68   $  0.97   $  1.13  $   4.66

Unitholder Distributions              $   169   $   361   $   435  $  1,804
 Per Trust unit                       $  0.35   $  0.75   $  0.90  $   3.75

Sales Volumes (1)
 Total (MMbbls)                          10.9      10.1      37.6      38.8
 Daily average (bbls)                 119,287   110,197   103,129   105,986

Operating Costs ($/bbl)               $ 30.18   $ 32.10   $ 35.29  $  35.26

Net Realized SCO Selling Price
 ($/bbl)                              $ 78.67   $ 69.40   $ 69.47  $ 106.91

West Texas Intermediate (average
 $US/bbl) (2)                         $ 76.13   $ 59.08   $ 62.09  $  99.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The Trust's sales volumes differ from its production volumes due to
    changes in inventory, which are primarily in-transit pipeline volumes,
    and are net of purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.

2010 Outlook

Canadian Oil Sands is estimating Syncrude production of 115 million barrels with a range of 110 to 120 million barrels for 2010. While our annual production estimate remains unchanged from the Outlook provided on October 28, 2009, we expect first quarter production will be impacted by unplanned outages in the upgrader during January and an advancement of the planned LC finer turnaround into the first quarter. We expect this lost production will be recaptured later in the year, as outages were factored into our annual production estimate.

Canadian Oil Sands' operating costs are estimated at $1,480 million, or $35 per barrel, with capital expenditures of $541 million, mainly related to sustaining the Syncrude operation.

We are estimating 2010 cash from operating activities of $1,013 million, or $2.09 per Unit. After deducting capital expenditures, we are estimating $472 million of remaining cash from operating activities, or $0.97 per Unit.

More information on the Trust's outlook is provided in the Management's Discussion and Analysis section of this report and the January 28, 2010 guidance document, which is available on the Trust's web site at www.cos-trust.com under "Investor".

Canadian Oil Sands speaks with Canadians about the oil sands

Marcel Coutu, President and Chief Executive Officer of Canadian Oil Sands, was in Halifax, Nova Scotia and St. John's, Newfoundland on January 13th and 14th to speak with Canadians about the oil sands. Mr. Coutu provided frank insights into how the oil sands are meeting the challenge of improving their environmental performance, the impact of the oil sands on the economy of Canada and local communities, and what all this means to Canadians. To read a copy of his speech and view video clips, please visit www.OilSandsNow.ca.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") was prepared as of January 28, 2010 and should be read in conjunction with the unaudited interim consolidated financial statements of Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust") for the three and twelve months ended December 31, 2009 and December 31, 2008, and the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2008 and the Trust's Annual Information Form ("AIF") dated March 13, 2009. Additional information on the Trust, including its AIF, is available on SEDAR at www.sedar.com or on the Trust's website at www.cos-trust.com.

ADVISORY- in the interest of providing the Trust's Unitholders and potential investors with information regarding the Trust, including management's assessment of the Trust's future production and cost estimates, plans and operations, certain statements throughout this MD&A and the related press release contain "forward-looking statements" under applicable securities law. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to expectations regarding the impact on future costs as a result of the economic downturn; the cost estimate for the Sulphur Emissions Reduction project and the expectation that the Sulphur Emissions Reduction project will significantly reduce total sulphur dioxide and other emissions; the completion date for the Sulphur Emissions Reduction project; future distributions and any increase or decrease from current payment amounts; the Trust's plans with regard to its net debt level by the end of 2010; plans regarding crude oil hedges and currency hedges in the future; the expected production, revenues and operating costs for 2010; the belief that operational reliability will improve over time and with that improvement that operating costs will be reduced; the expected level of sustaining capital for the next few years and longer term; the expectations regarding capital expenditures and operating costs; the plans regarding conversion to a corporate structure and the timing of seeking Unitholder approval; the plans and expected impact of adopting International Financial Reporting Standards; the expected impact of any current and future environmental legislation, including without limitation, regulations relating to tailings; the expectation that there will not be any material funding increases relative to Syncrude's future reclamation costs or pension funding for the next year; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2010 for Canadian Oil Sands' product; the potential amount payable in respect of any future income tax liability; the plans regarding future expansions of the Syncrude project and in particular all plans regarding future development; the level of energy consumption in 2010 and beyond; capital expenditures for 2010; the level of natural gas consumption in 2010 and beyond; the expected price for crude oil and natural gas in 2010, and the anticipated impact that certain factors such as natural gas and oil prices, foreign exchange and operating costs have on the Trust's cash from operating activities and net income.

You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Trust believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A include, but are not limited to: the impacts of regulatory changes especially as such relate to royalties, taxation, and environmental charges; the impact of technology on operations and processes and how new complex technology may not perform as expected; skilled labour shortages and the productivity achieved from labour in the Fort McMurray area; the supply and demand metrics for oil and natural gas; the impact that pipeline capacity and refinery demand have on prices for our products; the unanimous joint venture owner approval for major expansions; the variances of stock market activities generally; global economic environment/volatility of markets; normal risks associated with litigation, general economic, business and market conditions; regulatory change, and such other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by the Trust. You are cautioned that the foregoing list of important factors is not exhaustive. No assurance can be given that the final legislation implementing the federal tax changes regarding income trusts will not be further changed in a manner which adversely affects the Trust and its Unitholders. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and unless required by law, the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.

REVIEW OF SYNCRUDE OPERATIONS

During the fourth quarter of 2009, crude oil production from the Syncrude Joint Venture ("Syncrude") totaled 30.1 million barrels, or 327,000 barrels per day, compared with 28.4 million barrels, or 308,000 barrels per day, during the same period of 2008. Net to the Trust, production totaled 11.1 million barrels in the fourth quarter of 2009 compared with 10.4 million barrels in 2008, based on our 36.74 per cent working interest.

Production volumes in the fourth quarter of 2009 were impacted by unplanned maintenance in Syncrude's vacuum distillation unit. By comparison, production during the fourth quarter of 2008 was impacted by a planned turnaround of Coker 8-2, which commenced in September 2008 and was completed in the first week of November 2008.

In 2009, Syncrude produced 102.2 million barrels, or 280,000 barrels per day, compared with 105.8 million barrels, or 289,000 barrels per day in 2008. Net to the Trust, production totaled 37.5 million barrels in 2009 compared with 38.9 million barrels in 2008. Syncrude's 2009 production was negatively affected by an extended turnaround and modification work on Coker 8-3 and related units, which began in mid-March and was completed in early June. As well, unplanned outages in the mining operations, coke circulation difficulties in Coker 8-1, maintenance on the vacuum distillation unit, and first quarter bitumen constraints reduced 2009 production. By comparison, production in 2008 was impacted by the planned turnarounds of Coker 8-2 and Coker 8-1, bitumen production constraints and a disruption in several operating units during the first quarter.

Syncrude's facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. Under normal operating conditions, scheduled downtime is required for maintenance and turnaround activities and unscheduled downtime will occur as a result of operational and mechanical problems, unanticipated repairs and other slowdowns. When allowances for such downtime are included, the daily design productive capacity of Syncrude's facilities is approximately 350,000 barrels per day on average and is referred to as "barrels per calendar day". All references to Syncrude's productive capacity in this report refer to barrels per calendar day, unless stated otherwise.

Operating costs were $30.18 per barrel in the fourth quarter of 2009, down $1.92 per barrel from the same quarter of 2008. Annual operating costs for 2009 were $35.29 per barrel, essentially flat in comparison with 2008 operating costs of $35.26 per barrel (see the "Operating costs" section of this MD&A for further discussion).

The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes. The impact of Syncrude's 2009 operations on Canadian Oil Sands' financial results is more fully discussed later in this MD&A.

BUSINESS ENVIRONMENT

Prices for U.S. dollar West Texas Intermediate ("WTI") oil continued to strengthen during the fourth quarter of 2009, averaging U.S. $76.13 per barrel versus U.S. $57.32 per barrel for the first nine months of 2009. Partially offsetting the oil price rise, the Canadian dollar increased to an average of $0.95 U.S./Cdn in the fourth quarter versus $0.85 U.S./Cdn for the first nine months of 2009. Compared to 2008, however, commodity prices during 2009 were substantially lower with U.S. dollar WTI prices averaging $62.09 per barrel versus $99.75 per barrel in 2008.

The deterioration of economic conditions during late 2008 and early 2009 resulted in the deferral or cancellation of several oil sands projects in the Fort McMurray region. With the improvement in market conditions in more recent months, announcements have been made that indicate development of some of these projects is expected to resume. While it is reasonable to expect any continued industry slowdown to contribute to lower costs over time through more competitive access to labour and materials, we have yet to experience material declines in production costs. A significant portion of costs in the oil sands industry are associated with labour, and these costs respond much slower to changing market conditions, particularly as industry-wide labour agreements exist that stipulated wage increases in 2009. We continue to believe the most significant factor in achieving cost reductions at Syncrude is better operational reliability.


SUMMARY OF QUARTERLY RESULTS

($ millions,
 except per
 Trust Unit
 and volume                  2009                            2008
 amounts)          Q4      Q3     Q2      Q1      Q4      Q3      Q2      Q1
----------------------------------------------------------------------------
Revenues (1)   $  863 $   773 $  467  $  512 $   704 $ 1,381  $1,177 $   907

Net income
 (loss)        $   96 $   247 $   46  $   43 $   124 $   604  $  497 $   298
 Per Trust
  Unit, Basic &
  Diluted      $ 0.20 $  0.51 $ 0.10  $ 0.09 $  0.26 $  1.25  $ 1.04 $  0.62

Cash from
 operating
 activities    $  328 $   213 $  (44) $   50 $   466 $   921  $  413 $   441
 Per Trust
  Unit (2)     $ 0.68 $  0.44 $(0.09) $ 0.10 $  0.97 $  1.91  $ 0.86 $  0.92

Unitholder
 distributions $  169 $   121 $   73  $   72 $   361 $   602  $  481 $   360
 Per Trust
  Unit         $ 0.35 $  0.25 $ 0.15  $ 0.15 $  0.75 $  1.25  $ 1.00 $  0.75

Daily average
 sales volumes
 (bbls) (3)   119,287 114,544 75,553 102,825 110,197 116,656  97,744  99,181

Net realized
 SCO selling
 price ($/bbl)
 (4)           $78.67 $ 73.31 $67.92  $55.32 $ 69.40 $127.55 $131.32 $100.41

Operating
 costs ($/bbl)
 (5)           $30.18 $ 27.80 $50.23  $38.78 $ 32.10 $ 32.15 $ 41.92 $ 35.93

Purchased
 natural gas
 price ($/GJ)  $ 4.33 $  2.90 $ 3.09  $ 4.96 $  6.41 $  7.86 $  9.38 $  7.30

West Texas
 Intermediate
 (avg. US$/bbl)
 (6)           $76.13 $ 68.24 $59.79  $43.31 $ 59.08 $118.22 $123.80 $ 97.82

Foreign
 exchange rates
 (US$/Cdn$):
 Average       $ 0.95 $  0.91 $ 0.86  $ 0.80 $  0.83 $  0.96 $  0.99 $  1.00
 Quarter- end  $ 0.96 $  0.93 $ 0.86  $ 0.79 $  0.82 $  0.94 $  0.98 $  0.97

(1) Revenues after crude oil purchases and transportation expense.
(2) Cash from operating activities per Trust Unit is a non-GAAP measure that
    is derived from cash from operating activities reported on the Trust's
    Consolidated Statements of Cash Flows divided by the weighted-average
    number of Trust Units outstanding in the period, as used in the Trust's
    net income per Unit calculations.
(3) Daily average sales volumes after crude oil purchases.
(4) Net realized SCO selling price after foreign currency hedging.
(5) Derived from operating costs, as reported on the Trust's Consolidated
    Statements of Income and Comprehensive Income, divided by the sales
    volumes during the period.
(6) Pricing obtained from Bloomberg.

During the last eight quarters, the following items have had a significant impact on the Trust's financial results:

- Fluctuations in U.S. dollar WTI oil prices have impacted the Trust's revenues, Crown royalties, net income and cash from operating activities;

- Net income was reduced in the fourth quarter of 2009 by $148 million due to an impairment charge and goodwill write-down on the Arctic natural gas assets;

- Planned and unplanned maintenance activities as well as turnarounds have impacted quarterly production volumes, sales revenues and operating costs;

- U.S. to Canadian dollar exchange rate fluctuations have resulted in foreign exchange gains and losses on the revaluation of U.S. dollar denominated debt and have impacted commodity pricing; and

- Tax rate reductions substantively enacted in the first quarter of 2009 resulted in additional future income tax recoveries of $63 million.

The above items are discussed in greater detail later in this MD&A.

Quarterly variances in revenues, net income, and cash from operating activities are caused mainly by fluctuations in crude oil prices, production and sales volumes, operating costs and natural gas prices. Net income also is impacted by unrealized foreign exchange gains and losses, impairment charges and by future income tax amounts. A large proportion of operating costs are fixed and, as such, per barrel operating costs are variable to production volumes. While the supply/demand balance for crude oil affects selling prices, the impact of this equation is difficult to predict and quantify and has not displayed significant seasonality. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is influenced by weather conditions and North American natural gas inventory levels. In addition, production levels may not display seasonal patterns or trends. While maintenance and turnaround activities are typically scheduled to avoid the winter months, the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages may occur.

Maintenance and turnaround activities impact both production volumes and operating costs. The costs associated with these activities are expensed in the period they are incurred, which can lead to significant increases in operating costs. The effect on per barrel operating costs of these maintenance activities is amplified as the facility is generally producing at reduced rates when maintenance work is occurring.

REVIEW OF FINANCIAL RESULTS

In the fourth quarter of 2009, the Trust reported net income of $96 million, or $0.20 per Unit, compared with $124 million, or $0.26 per Unit, recorded in the fourth quarter of 2008. Excluding after-tax impairment charges of $148 million on the Trust's Arctic assets, 2009 net income was $244 million or $0.50 per Unit, reflecting higher sales volumes, oil prices and foreign exchange gains, partially offset by higher Crown royalties.

On an annual basis, net income totaled $432 million, or $0.89 per Unit compared with $1,523 million, or $3.17 per Unit, recorded in 2008. The decline in net income primarily reflects lower revenues, net of lower Crown royalties in 2009.

Revenues after crude oil purchases and transportation costs totaled $863 million in the fourth quarter of 2009 versus $704 million in the fourth quarter of 2008. On an annual basis, revenues after crude oil purchases and transportation costs totaled $2,615 million in 2009 versus $4,169 million in 2008. The decrease in annual revenues was due mainly to lower crude oil prices as well as lower production and sales volumes in 2009 (see "Revenues after Crude Oil Purchases and Transportation Expense" section of this MD&A for further discussion).

Cash from operating activities was $328 million for the fourth quarter of 2009 versus $466 million for the fourth quarter of 2008. The decrease in quarter-over-quarter cash from operating activities was due to increases in non-cash working capital and Crown royalties, partially offset by higher revenues. On an annual basis, cash from operating activities in 2009 decreased to $547 million versus $2,241 million for 2008. The decrease in the yearly cash from operating activities was due to the decrease in revenues and increases in non-cash working capital, partially offset by lower Crown royalties.

Non-cash working capital decreased cash from operating activities by $38 million in the fourth quarter of 2009, primarily as a result of higher accounts receivable, reflecting higher oil production and prices for December 2009 compared to September 2009. In the fourth quarter of 2008, non-cash working capital increased cash from operating activities by $174 million, primarily as a result of lower accounts receivable at December 31, 2008 relative to September 30, 2008.

On an annual basis, increases in non-cash working capital decreased cash from operating activities by $207 million, primarily as a result of higher accounts receivable and higher inventory levels at December 31, 2009 relative to December 31, 2008. In 2008, non-cash working capital increased cash from operating activities by $202 million, primarily as a result of lower accounts receivable at December 31, 2008 relative to December 31, 2007.

Non-GAAP Financial Measures


Net Income per Barrel

                     Three Months Ended          Twelve Months Ended
                         December 31                  December 31
($ per bbl) (1)       2009      2008  Variance    2009       2008  Variance
----------------------------------------------------------------------------

Revenues after crude
 oil purchases and
 transportation
 expense             78.67     69.43      9.24   69.47     107.47    (38.00)
Operating costs     (30.18)   (32.10)     1.92  (35.29)    (35.26)    (0.03)
Crown royalties      (8.47)    (5.84)    (2.63)  (6.06)    (15.44)     9.38
----------------------------------------------------------------------------
                     40.02     31.49      8.53   28.12      56.77    (28.65)
----------------------------------------------------------------------------

Non-production costs (3.26)    (2.36)    (0.90)  (3.75)     (2.00)    (1.75)
Administration and
 insurance           (0.75)    (0.35)    (0.40)  (0.87)     (0.61)    (0.26)
Interest, net        (2.03)    (1.80)    (0.23)  (2.45)     (1.75)    (0.70)
Depreciation,
 depletion and
 accretion (2)      (23.78)   (11.73)   (12.05) (15.16)    (11.46)    (3.70)
Goodwill impairment  (4.73)        -     (4.73)  (1.38)         -     (1.38)
Foreign exchange
 gain (loss)          2.10    (10.40)    12.50    4.28      (4.09)     8.37
Future income tax
 (expense) recovery
 and other            1.16      7.33     (6.17)   2.67       2.39      0.28
----------------------------------------------------------------------------
                    (31.29)   (19.31)   (11.98) (16.66)    (17.52)     0.86
----------------------------------------------------------------------------
Net income per
 barrel               8.73     12.18     (3.45)  11.46      39.25    (27.79)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Sales volumes
 (MMbbls) (3)         10.9      10.1       0.8    37.6       38.8      (1.2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Unless otherwise specified, net income and other per barrel measures in
    this MD&A have been derived by dividing the relevant revenue or cost
    item by the sales volumes in the period.
(2) Includes impairment of Arctic assets.
(3) Sales volumes, net of purchased crude oil volumes.



Revenues after Crude Oil Purchases and Transportation Expense

                             Three Months Ended         Twelve Months Ended
                                  December 31                December 31
($ millions)           2009    2008    Variance    2009     2008   Variance
----------------------------------------------------------------------------
Sales revenue (1)    $  894  $  767     $   127  $2,775  $ 4,539    $(1,764)
Crude oil purchases     (24)    (54)         30    (133)    (337)       204
Transportation expense   (8)    (10)          2     (31)     (37)         6
----------------------------------------------------------------------------
                        862     703         159   2,611    4,165     (1,554)
Currency hedging
 gains (1)                1       1           -       4        4          -
----------------------------------------------------------------------------
                     $  863  $  704     $   159  $2,615  $ 4,169    $(1,554)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Sales volumes
 (MMbbls) (2)          10.9    10.1         0.8    37.6     38.8       (1.2)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The sum of sales revenue and currency hedging gains equals Revenues on
    the Trust's Consolidated Statements of Income and Comprehensive Income.
    Sales revenue includes revenue from the sale of purchased crude oil and
    sulphur revenue.
(2) Sales volumes, net of purchased crude oil volumes.


($ per barrel)
----------------------------------------------------------------------------

Realized SCO selling
 price before
 hedging (3)         $78.59  $69.31      $ 9.28  $69.37  $106.81    $(37.44)
Currency hedging
 gains                 0.08    0.09       (0.01)   0.10     0.10          -
----------------------------------------------------------------------------
Net realized SCO
 selling price       $78.67  $69.40      $ 9.27  $69.47  $106.91    $(37.44)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(3) SCO sales revenue after crude oil purchases and transportation expense
    divided by sales volumes, net of purchased crude oil volumes.

The increase in sales revenue in the fourth quarter of 2009 versus 2008 primarily reflects a higher realized selling price for our synthetic crude oil ("SCO") as well as higher sales volumes. During the fourth quarter of 2009, WTI averaged U.S. $76.13 per barrel compared to U.S. $59.08 per barrel in the fourth quarter of 2008. The impact of the higher U.S. dollar WTI price in the fourth quarter of 2009 was offset somewhat by a stronger Canadian dollar, which averaged $0.95 U.S./Cdn for the fourth quarter of 2009 versus $0.83 U.S./Cdn for the fourth quarter of 2008.

The decrease in sales revenue on an annual basis was due mainly to lower realized selling prices for SCO and lower sales volumes in 2009. WTI prices averaged U.S. $62.09 per barrel in 2009 versus U.S. $99.75 per barrel in 2008. The impact of the lower 2009 U.S. dollar WTI price was offset somewhat by a weaker Canadian dollar, which averaged $0.88 U.S./Cdn in 2009 versus $0.94 U.S./Cdn in 2008.

The Trust's SCO price is also affected by the premium or discount realized relative to Canadian dollar WTI (the "differential"). In the fourth quarter of 2009, the Trust realized a weighted-average SCO discount of $1.69 per barrel versus a discount of $1.63 per barrel for the same period of 2008. In 2009, the Trust realized a weighted-average SCO discount of $1.08 per barrel relative to the average Canadian dollar WTI price versus a premium of $1.94 per barrel in 2008. The differential is dependent upon the supply and demand for SCO and, accordingly, can change quickly depending upon the short-term supply and demand dynamics in the market and pipeline availability for transporting crude oil.

The Trust's fourth quarter sales volumes averaged 119,000 barrels per day and 110,000 barrels per day in 2009 and 2008, respectively. On an annual basis, sales volumes averaged 103,000 barrels per day in 2009 versus an average of 106,000 barrels per day in 2008. Sales volumes for 2009 were impacted by the same factors that impacted Syncrude production including a longer than expected planned turnaround and modifications on the Coker 8-3 complex, reliability issues in mining and upgrading operations, and constrained bitumen production during the first quarter. Sales volumes in 2008 were impacted by the disruption of several operating units in January, the scheduled turnarounds of Coker 8-2 and Coker 8-1, and bitumen production constraints.

From time to time the Trust purchases crude oil from third parties to support the sales of internally produced SCO by fulfilling sales commitments with customers when there are shortfalls in Syncrude's production and by facilitating certain transportation arrangements and operations. The decrease in value of crude oil purchases during 2009 was due to the decrease in commodity prices and purchased volumes.


Operating Costs

               Three Months Ended              Twelve Months Ended
                  December 31                      December 31
                  2009 (1)        2008 (1)      2009 (1)         2008 (1)
----------------------------------------------------------------------------
              $/bbl   $/bbl   $/bbl   $/bbl   $/bbl   $/bbl   $/bbl   $/bbl
            Bitumen     SCO Bitumen     SCO Bitumen     SCO Bitumen     SCO
----------------------------------------------------------------------------

 Bitumen
  production
  (2)        $16.55  $19.23  $18.41  $21.09  $19.32  $22.81  $19.18  $22.19
 Internal
  fuel
  allocation
  (4)          2.34    2.72    3.54    4.06    2.32    2.74    4.04    4.67
----------------------------------------------------------------------------
 Total
  produced
  bitumen
  costs       18.89   21.95   21.95   25.15   21.64   25.55   23.22   26.86

Upgrading
 costs (3)            10.96           12.13           12.53           12.27
 Less:
  Internal fuel
   Allocation
   to bitumen
  (4)                 (2.72)          (4.06)          (2.74)          (4.67)
  Bitumen
   purchases              -               -            0.32            1.04
----------------------------------------------------------------------------
 Total
  Syncrude
  operating
  costs               30.19           33.22           35.66           35.50
 Canadian Oil
  Sands'
  adjustments (5)     (0.01)          (1.12)          (0.37)          (0.24)
----------------------------------------------------------------------------
Total
 operating costs      30.18           32.10           35.29           35.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(thousands
 of barrels
 per day)   Bitumen     SCO Bitumen     SCO Bitumen     SCO Bitumen     SCO
----------------------------------------------------------------------------
Syncrude
 production
 volumes (6)    380     327     353     308     330     280     334     289
----------------------------------------------------------------------------

(1)Information shown above allocates costs to bitumen production and
   upgrading based on deductibility for bitumen royalty purposes. In-order
   to allow time to fully develop an allocation methodology for common
   costs, the Syncrude Royalty Amending Agreement provides for allowed
   bitumen costs to be 64.5 per cent of Syncrude total operating costs until
   December 31, 2010.  Prior year information has been reclassified to
   conform to the new format.
(2)Bitumen production costs relate to the removal of overburden, oil sands
   mining, bitumen extraction, tailings dyke construction and disposal costs
   and purchased energy. The costs are expressed on a per barrel of bitumen
   production basis and converted to a per barrel of SCO based on the
   effective yield of SCO from the processing and upgrading of bitumen.
(3)Upgrading costs include the production, ongoing maintenance, and
   purchased energy costs associated with processing and upgrading of
   bitumen to SCO. They also include the costs of major upgrading equipment
   turnarounds and catalyst replacement, all of which are expensed as
   incurred.
(4)Estimate of internal fuel produced in upgrading operations and consumed
   in bitumen production.  Allocation is based on the Syncrude Royalty
   Amending Agreement.
(5)Canadian Oil Sands' adjustments mainly pertain to asset retirement costs,
   Syncrude-related pension costs, as well as the inventory impact of moving
   from production to sales as Syncrude reports per barrel costs based on
   production volumes and the Trust reports based on sales volumes.
(6)Syncrude SCO production volumes include the impact of processed
   purchased bitumen volumes. Bitumen production volumes exclude the impact
   of purchased bitumen.



                                          Three Months      Twelve Months
                                              Ended              Ended
                                           December 31        December 31
($/bbl of SCO)                           2009      2008      2009      2008
----------------------------------------------------------------------------

Production costs                        26.41     25.89     31.39     28.01
Purchased energy                         3.77      6.21      3.90      7.25
----------------------------------------------------------------------------
Total operating costs                   30.18     32.10     35.29     35.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(GJs/bbl of SCO)
----------------------------------------------------------------------------
Purchased energy consumption             0.87      0.97      0.99      0.95
----------------------------------------------------------------------------

In the fourth quarter of 2009, operating costs were $331 million, averaging $30.18 per barrel, in line with fourth quarter 2008 operating costs of $326 million. On an annual basis, operating costs were $1,328 million in 2009, averaging $35.29 per barrel, a decrease of $40 million from 2008.

The decrease in annual operating costs was primarily due to the following:

- Lower energy costs as a result of a decline in natural gas prices to $3.95 per gigajoule ("GJ") in 2009 compared with $7.66 per GJ in 2008; and

- A decrease in the value of bitumen purchased by Syncrude to $33 million in 2009 ($12 million net to the Trust) compared with $110 million during the same period of 2008 ($40 million net to the Trust).

These cost reductions were offset by:

- Additional maintenance activities at Syncrude on mining, upgrading, utilities and extraction facilities in 2009 relative to 2008;

- Additional mining activities, including increased material movement in 2009 relative to 2008;

- Increased costs for contractors and wages for Syncrude staff; and

- An increase in the value of Syncrude's long-term incentive plans in 2009 versus 2008. A portion of Syncrude's long-term incentive plans is based on the market return performance of several Syncrude owners' shares and units, the market performance of which was stronger in 2009 relative to 2008.

Operating costs in 2009 and 2008 were also impacted by turnarounds on Syncrude's cokers. In 2009 Syncrude performed significant maintenance and modification work on the Coker 8-3 complex. In 2008 Syncrude performed turnarounds on Coker 8-1 and Coker 8-2. The cost of the single 2009 turnaround was similar to the combined cost for the 2008 turnarounds as a result of the larger 2009 scope.

Non-Production Costs

Non-production costs totaled $35 million and $24 million in the fourth quarters of 2009 and 2008, respectively. On an annual basis, non-production costs totaled $141 million for 2009 and $78 million for 2008. The increase in non-production costs over 2008 was due to additional development activities undertaken with respect to future mine train relocations, initiatives to manage tailings ponds, ESP fire repairs and planning for growth initiatives.

Crown Royalties

Pursuant to an agreement reached in 2008 ("Amended Royalty Agreement") with the Alberta government, Syncrude's Crown royalties after 2008 are based on deemed bitumen revenues and allowed bitumen operating, non-production and capital costs. Additional amounts for upgrader growth capital deducted in computing royalties for prior years, and transition payments for the period 2010 to 2015, are also to be factored into the royalty calculation. For 2009 Syncrude was subject to royalties based on a net 25 per cent bitumen royalty rate. A copy of the 2008 Amended Royalty Agreement is available at www.sedar.com under the Trust's company information.

In the fourth quarter of 2009, Crown royalties increased to $93 million, or $8.47 per barrel, from $59 million, or $5.84 per barrel, in the comparable 2008 quarter as a result of increased deemed bitumen revenues resulting from higher commodity prices. On an annual basis, Crown royalties decreased to $228 million, or $6.06 per barrel, in 2009 from $599 million, or $15.44 per barrel in 2008. The decrease in Crown royalties on an annual basis was primarily due to lower deemed bitumen revenues resulting from lower commodity prices and higher capital costs during 2009.

The deemed bitumen revenue under the Amended Royalty Agreement requires that bitumen be valued by a formula that references the value of bitumen based on a Canadian heavy oil price adjusted for reasonable quality, transportation and handling deductions (including diluent costs) to reflect the quality and location differences between Syncrude's bitumen and the reference price of bitumen. The Alberta government, Syncrude and the Syncrude joint venture owners are in discussions to determine the appropriate adjustments for quality, transportation and handling. For estimating and paying royalties, Syncrude has used a bitumen value based on Syncrude and its owners' interpretation of the Amended Royalty Agreement and estimates of the appropriate quality, transportation and handling adjustments. These adjustments are different than those provided under the generic bitumen valuation methodology. Based on discussions to date among the parties to the Amended Royalty Agreement, the royalty amount for 2009 net to Canadian Oil Sands is about $40 million less than the amount calculated under the Alberta government's generic bitumen valuation methodology. The Syncrude joint venture owners and the Alberta government continue to discuss the basis for these reasonable adjustments but if such discussions do not result in an agreed upon solution, either party may seek judicial determination of the matter.

Syncrude also has recorded an additional $29 million for 2009, net to the Trust, of royalties in respect of upgrader growth capital recapture under its Amended Royalty Agreement.


Interest Expense, Net

                                  Three Months Ended    Twelve Months Ended
                                        December 31            December 31
($ millions)                          2009      2008         2009      2008
----------------------------------------------------------------------------

Interest expense on long-term debt  $   23    $   20       $   94    $   76
Interest income and other                -        (1)          (1)       (8)
----------------------------------------------------------------------------
  Interest expense, net             $   23    $   19       $   93    $   68
----------------------------------------------------------------------------

The increase in interest expense on long-term debt was mainly due to the refinancing of 2009 debt maturities with the U.S. $500 million 7.75 per cent Senior Notes issue in the second quarter of 2009.


Depreciation, Depletion and Accretion Expense

                                  Three Months Ended    Twelve Months Ended
                                        December 31            December 31
($ millions)                          2009      2008         2009      2008
----------------------------------------------------------------------------

Depreciation and depletion
 expense-Syncrude                   $  124    $  115       $  423    $  430
Impairment of Arctic assets         $  130    $    -       $  130    $    -
Accretion expense                        6         4           17        14
----------------------------------------------------------------------------
                                    $  260    $  119       $  570    $  444
----------------------------------------------------------------------------

The change in depreciation and depletion ("D&D") expense on the Trust's Syncrude assets was due to lower production volumes offset by a slight increase in the per barrel D&D rate for 2009. The D&D rate per barrel of production increased to $11.27 in 2009 from $11.07 in 2008.

Refer to page 17 of this MD&A for a discussion related to the impairment of Arctic assets.


Foreign Exchange (Gain) Loss

                                  Three Months Ended    Twelve Months Ended
                                        December 31            December 31
($ millions)                          2009      2008         2009      2008
----------------------------------------------------------------------------

Foreign exchange (gain)
 loss-long term debt                $  (28)   $  142       $ (200)   $  204
Foreign exchange (gain)
 loss-other                              5       (36)          39       (45)
----------------------------------------------------------------------------
  Total foreign exchange
   (gain) loss                      $  (23)   $  106       $ (161)   $  159
----------------------------------------------------------------------------

Foreign exchange ("FX") gains/losses are primarily the result of revaluations of our U.S. dollar denominated long-term debt caused by fluctuations in U.S. and Canadian dollar exchange rates.

The FX gains on long-term debt in 2009 were due to a strengthening in the value of the Canadian dollar relative to the U.S. dollar to $0.96 U.S./Cdn at December 31, 2009 from $0.93 U.S./Cdn at September 30, 2009 and $0.82 U.S./ Cdn at December 31, 2008. The FX losses in 2008 were due to the weakening of the Canadian dollar relative to the U.S. dollar to $0.82 U.S./Cdn at December 31, 2008 from $0.94 U.S./Cdn at September 30, 2008 and $1.01 U.S./Cdn at December 31, 2007.

In addition to the foreign exchange gain on long-term debt, Canadian Oil Sands also reported a foreign exchange loss of $39 million on other items during 2009. This loss was primarily due to a foreign exchange loss of $19 million on U.S. dollar cash held by Canadian Oil Sands from its May, 2009 financing to retire U.S. $250 million of debt in August.

Future Income Tax and Other

In the fourth quarter of 2009, a future income tax recovery of $13 million was recorded versus a future income tax recovery of $75 million in the same period of 2008. A future income tax recovery of $101 million was recorded in 2009 versus a future income tax recovery of $93 million in 2008. In addition to the future income tax amounts recorded on changes in temporary differences between accounting and tax values of Canadian Oil Sands' assets and liabilities, a future income tax recovery of $63 million was recorded during the first quarter of 2009 on the substantive enactment of tax rate reductions.

CAPITAL EXPENDITURES

Canadian Oil Sands' expansion-related capital expenditures have declined in recent years and capital costs for 2009 and 2008 were mainly related to sustaining capital. Expansion-related capital are costs incurred to grow the productive capacity of the operation while sustaining capital is effectively all other capital. Capital expenditures may fluctuate considerably year-to-year due to the timing of expansions, equipment replacement and other factors. The productive capacity of Syncrude's operations was previously described in the "Review of Syncrude Operations" section of this MD&A.

In the fourth quarter of 2009, capital expenditures totaled $101 million compared with expenditures of $86 million in the same quarter of 2008. The Syncrude Emissions Reduction ("SER") project accounted for $28 million and $17 million of the capital spent in the fourth quarters of 2009 and 2008, respectively, with the remaining fourth quarter expenditures related to other sustaining capital activities, including the purchase of trucks and shovels, construction of tailings facilities, and other infrastructure projects.

On an annual basis, capital expenditures in 2009 totaled $409 million versus $281 million in 2008. The SER project accounted for $115 million and $73 million of the capital spent in 2009 and 2008, respectively. The remaining expenditures related to other sustaining capital activities, including the purchase of trucks and shovels, modifications to Coker 8-3 and related units, construction of tailings facilities, and other infrastructure projects. Sustaining capital expenditures on a per barrel basis were $10.86 and $7.23 in 2009 and 2008, respectively. Sustaining capital on a per barrel basis is also affected by the Trust's sales volumes, which were lower in 2009 relative to 2008.

IMPAIRMENT OF ARCTIC ASSETS

During the fourth quarter of 2009, the Trust assessed its Arctic assets and related goodwill for impairment. Along with recent technological innovations that have increased access to natural gas shale resources, there continues to be delays in other Arctic developments. The Trust has a "carried interest" in its Arctic resource which reduces risk; however, resource development is dependent on uncertain operator approvals.

As a result of these uncertainties, the Trust extended its assumed timing for development of the Arctic assets. Based on a net present value analysis which assumes a deferred project start date, additional depreciation and depletion of $130 million ($96 million after tax) was recorded by the Trust. A goodwill impairment of $52 million has also been recorded. The remaining net book value recorded by the Trust for the Arctic assets is $35 million and net income during the quarter was reduced by $148 million after tax ($182 million pre-tax).

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The following table outlines the significant financial obligations that are known as of January 28, 2010, which represent future cash payments that the Trust is required to make under existing contractual arrangements that it has entered into directly, or as a 36.74 per cent owner in the Syncrude Joint Venture.


                                            Payments due by period
                                        Less
                                        than                          After
($ millions)                 Total    1 year  1-3 years  4-5 years  5 years
----------------------------------------------------------------------------
Long-term debt (1)           1,993        86        571        135    1,201
Capital expenditure
 commitments (2)               303       147        156          -        -
Pension plan solvency
 deficiency payments (3)        94        14         31         17       32
Management services
 agreement (4)                 125        17         51         34       23
Pipeline commitments (5)       528        19         59         39      411
Asset retirement
 obligations (6)               903        45        129         54      675
Other obligations (7)          424       223        128         20       53
----------------------------------------------------------------------------
                             4,370       551      1,125        299    2,395
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Actual payments differ from the carrying value as the amounts are
    stated at amortized cost plus interest payment commitments on the
    long-term debt.
(2) Capital expenditure commitments are primarily comprised of our 36.74
    per cent share of Syncrude's Emissions Reduction project.
(3) We are responsible for funding our 36.74 per cent share of Syncrude
    Canada's registered pension plan solvency deficiency, which was
    confirmed in the December 31, 2006 actuarial valuation that was
    completed in 2007.
(4) Reflects our 36.74 per cent share of Syncrude Canada's annual fixed
    service fees under the agreement.
(5) Reflects our 36.74 per cent share of the AOSPL pipeline commitment as
    a Syncrude Joint Venture owner, and various other Canadian Oil Sands
    pipeline commitments for transportation access beyond Edmonton.
(6) Reflects our 36.74 percent share of the undiscounted estimated cash
    flows required to settle Syncrude's environmental obligations upon
    reclamation of the Syncrude Joint Venture properties.
(7) These obligations primarily include our 36.74 per cent share of the
    minimum payments required under Syncrude's commitments for natural
    gas purchases. Other items include, but are not limited to,
    annual disposal fees for the flue gas desulphurization unit and
    tire supply agreements.

During 2009, Syncrude entered into new natural gas purchase commitments that expire between 2009 and 2011. The value of this commitment will fluctuate with changes to natural gas prices. The natural gas commitments above are based on an estimated AECO price of $6.00/GJ.

During 2009, the Trust increased its estimated asset retirement obligation as a result of revisions to cost estimates, the expected timing of reclamation expenditures, and revised material movement assumptions to reflect mine plan changes. The estimated present value of the obligation at December 31, 2009 was $389 million ($235 million at December 31, 2008), while the estimated undiscounted cash flows associated with the obligation are $903 million ($774 million at December 31, 2008).


UNITHOLDER DISTRIBUTIONS

                                  Three Months Ended    Twelve Months Ended
                                        December 31            December 31
----------------------------------------------------------------------------
($ millions)                          2009      2008         2009      2008
----------------------------------------------------------------------------
Cash from operating activities      $  328    $  466       $  547   $ 2,241

Net income                          $   96    $  124       $  432   $ 1,523

Unitholder distributions            $  169    $  361       $  435   $ 1,804
----------------------------------------------------------------------------
Excess (shortfall) of cash from
 operating activities over
 Unitholder distributions           $  159    $  105       $  112   $   437

Excess (shortfall) of net
 income over Unitholder
 distributions                      $  (73)   $ (237)      $   (3)  $  (281)
----------------------------------------------------------------------------

In 2009, cash from operating activities exceeded Unitholder distributions by $112 million. Cash from operating activities along with opening cash balances, equity issued by the Trust's Premium Distribution, Distribution Re-Investment and Optional Unit Purchase Plan ("DRIP"), and the U.S. $500 million Senior Note issue in the second quarter were sufficient to fund the Trust's capital expenditures, debt repayments, reclamation trust fund contributions, and distributions.

Unitholder distributions in the fourth quarter of 2009 exceeded net income primarily as a result of the goodwill impairment and additional D&D expense that was recorded by the Trust on the impairment of its Arctic assets. In 2008 Unitholder distributions exceeded net income on both a quarterly and an annual basis as a result of D&D expense and unrealized foreign exchange losses. D&D expense, the goodwill impairment and unrealized foreign exchange losses are non-cash items that do not affect the Trust's cash from operating activities or ability to pay distributions over the near term.

The Trust may use debt and equity financing in addition to cash from operating activities and existing cash balances to fund capital expenditures, reclamation trust contributions, debt repayments, acquisitions, distributions and working capital changes from financing and investing activities.

In early 2009, Canadian Oil Sands reinstated its DRIP to help preserve balance sheet equity during a time of lower crude oil prices, higher maintenance activities, and tight credit markets. In the third quarter, we suspended the DRIP as a result of strengthening crude oil prices, the U.S. $500 million Senior Notes issue, and stabilized capital markets. For the first and second quarters of 2009, participation in the DRIP was about 46 per cent and 41 per cent, respectively, and a total of 2.9 million Units were issued in 2009.

In establishing its distribution levels, the Trust considers its outlook for crude oil prices and Syncrude's operational performance, the Trust's financial obligations, and access to capital markets. We also consider funding for other operating obligations that are included in cash from operating activities. These obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to $69 million and $55 million in 2009 and 2008, respectively.

On January 28, 2010 the Trust declared a quarterly distribution of $0.35 per Unit in respect of the first quarter of 2010 for a total distribution of $170 million. The distribution will be paid on February 26, 2010 to Unitholders of record on February 18, 2010. Quarterly distributions are approved by our Board of Directors after considering the current and expected economic conditions, ensuring financing capacity for Canadian Oil Sands' capital requirements and with the objective of maintaining an investment grade credit rating.

Cash from operating activities and net income can fluctuate from period to period due to Syncrude's operating performance, WTI pricing, SCO differentials to WTI, FX rates and other factors. The Trust strives to reduce the impact of these fluctuations on distributions by taking a longer-term view of the operating and business environment, our net debt level, and our capital expenditure and other commitments. In that regard, the Trust may distribute more or less in a period than is generated in cash from operating activities or net income. The variable nature of cash from operating activities introduces risk in the ability to sustain or provide stability in distributions. Expectations regarding the stability or sustainability of distributions are unwarranted.


LIQUIDITY AND CAPITAL RESOURCES

                                                 December 31    December 31
($ millions)                                            2009           2008
----------------------------------------------------------------------------

Long-term debt                                         1,163          1,258
Cash and cash equivalents                               (122)          (279)
----------------------------------------------------------------------------
  Net debt (1)                                     $   1,041       $    979
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholders' equity                                $   3,969       $  3,910
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total capitalization (2)                           $   5,010       $  4,889
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net debt to total capitalization (%)                      21             20
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Non-GAAP measure

(2) Net debt plus Unitholders' equity

During the second quarter of 2009, the Trust issued U.S. $500 million of Senior Notes. The notes have an annual interest rate of 7.75 per cent payable semi-annually and mature May 15, 2019. Proceeds from the notes were used to repay $200 million of Medium Term Notes that matured during the second quarter of 2009, U.S. $250 million of Senior Notes that matured during the third quarter of 2009, and for general corporate purposes. The next debt maturity occurs in 2013.

Net debt at December 31, 2009 was $1.0 billion, which is consistent with the balance at December 31, 2008. Net debt remained constant as a result of approximately $200 million in foreign exchange gains on our U.S. dollar denominated debt, which offset the impact of the decrease in cash and cash equivalents.

During the first quarter of 2009, the Trust's $67 million line of credit was increased to $70 million and the term on the Trust's $40 million bilateral credit facility was extended to April 22, 2010.

With the refinancing of the 2009 debt maturities, the Trust's liquidity position has significantly improved. While we believe a slightly higher leverage level may provide a more efficient capital structure and conserve tax pools prior to trust taxation, the Trust must also consider a prudent liquidity position, access to capital markets, and future investing and financing requirements. In 2009 the Trust paid distributions in excess of cash from operating activities less capital expenditures. Non-cash foreign exchange gains on our U.S. dollar denominated debt, however, served to offset these net debt increases. While we are comfortable in 2010 paying distributions in excess of cash from operations less capital expenditures, increasing net debt towards $1.6 billion will depend on actual operating results, economic conditions, future investing activities, foreign exchange rates and distribution payments based on these expectations. As a result, actual net debt levels may vary from the target net debt and the net debt target may also change if a more conservative balance sheet is deemed prudent.

UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY

The Trust's Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $14 billion with 484 million Units outstanding and a closing price of $29.91 per Unit on December 31, 2009.

Canadian Oil Sands Trust - Trading Activity

                                  Fourth
                                 Quarter    December    November    October
                                    2009        2009        2009       2009
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unit price
  High                          $  34.89    $  30.74    $  31.67   $  34.89
  Low                           $  27.76    $  28.23    $  28.05   $  27.76
  Close                         $  29.91    $  29.91    $  29.25   $  29.18

Volume of Trust units
 traded (millions)                  91.2        19.2        32.0       40.0
Weighted average Trust
 units outstanding (millions)      484.4       484.4       484.4      484.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------

FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of November 20, 2009 approximately 72 per cent of our Units were held by Canadian residents with the remaining 28 per cent of Units being held by non-Canadian residents. Canadian Oil Sands' Trust Indenture provides that not more than 49 per cent of its Units can be held by non-Canadian residents.

The Trust regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of February 18, 2010. The Trust posts its foreign ownership levels on its web site at www.cos-trust.com under "Investor/Unit Information". The steps to manage foreign ownership levels are described in the Trust's AIF.

CORPORATE CONVERSION

On January 28, 2010, Canadian Oil Sands' Board approved converting to a corporate structure on or about December 31, 2010. Canadian Oil Sands plans to bring the conversion plan forward for Unitholder approval in conjunction with the Annual General Meeting to be held April 29, 2010. As part of its conversion to a corporate structure, Canadian Oil Sands has reviewed its distribution/dividend strategies. Based on current conditions, Canadian Oil Sands expects to determine dividend payments once it becomes a corporation on a similar basis as its current approach to distributions. Accordingly, future dividends that may be paid by Canadian Oil Sands following its conversion to a corporate structure are expected to vary depending on Syncrude's operational performance, Canadian Oil Sands' operating and capital obligations, crude oil prices and access to capital markets. Further, the taxability of Canadian Oil Sands after conversion will impact earnings and cash from operating activities in future periods.

FINANCIAL RISK MANAGEMENT

The Trust did not have any financial derivatives outstanding at December 31, 2009.

Crude Oil Price Risk

Canadian Oil Sands' revenues are impacted by changes in both the U.S. dollar denominated crude oil prices and U.S./Cdn FX rates. The Trust did not have any crude oil price hedges in place during 2009 and 2008, and does not currently intend to enter into any crude oil hedge positions. The Trust may hedge this exposure in the future, however, depending on the business environment and our growth opportunities.

Foreign Currency Risk

Canadian Oil Sands' results are affected by fluctuations in the U.S./Cdn currency exchange rates, as revenues generated are based on a U.S. dollar WTI benchmark price while certain obligations are denominated in Canadian dollars. The Trust did not have any foreign currency hedges in place during 2009 or 2008, and does not currently intend to enter into any new currency hedge positions. The Trust may, however, hedge foreign currency exchange rates in the future, depending on the business environment and growth opportunities.

Interest Rate Risk

Canadian Oil Sands' net income and cash from operating activities are impacted by interest rate changes based on the amount of floating rate debt outstanding or upon the refinancing of maturing long-term debt at prevailing interest rates. As at December 31, 2009 there was no floating interest rate debt outstanding.

Liquidity Risk

Liquidity risk is the risk that Canadian Oil Sands will not be able to meet its financial obligations as they fall due. Canadian Oil Sands actively manages its liquidity risk through its cash, debt and equity strategies. As a result of the U.S. $500 million 7.75 per cent Senior Note issue in the second quarter of 2009, the Trust's liquidity position improved significantly. The next long-term debt maturity is in 2013, and the $800 million credit facility does not expire until April, 2012.

Credit Risk

The financial condition of some of our U.S. based refinery customers has come under pressure during 2009, reflecting low refinery margins during the economic downturn. Canadian Oil Sands carries credit insurance to help mitigate the impact should a loss occur and continues to transact primarily with investment grade customers, with the vast majority of accounts receivable at December 31, 2009 being due from investment grade energy producers and refinery based customers.

At December 31, 2009, our cash and cash equivalents were held in either cash or term deposits with high-quality senior Canadian banks. As of January 28, 2010, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.

CHANGES IN ACCOUNTING POLICIES

Goodwill and Intangible Assets

In February 2008, the Canadian Institute of Chartered Accountants ("CICA") issued a new accounting standard, Section 3064 - Goodwill and Intangible Assets, which replaces Section 3062 - Goodwill and Other Intangible Assets, and Section 3450 - Research and Development costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The section is effective for the Trust beginning January 1, 2009. Application of the new section did not have a material impact on the Trust's financial statements.

NEW ACCOUNTING PRONOUNCEMENTS

There were no new accounting pronouncements by the CICA during 2009 that are expected to have a material impact on the Trust.

The Trust will be converting to international financial reporting standards ("IFRS"), which will replace Canadian GAAP starting in 2011. The Trust is analyzing accounting policy alternatives and system changes required for impact areas, including available first time adoption alternatives. Existing standards that may impact the Trust on adoption include asset retirement obligations, employee future benefits and property plant and equipment.

Assessments of the final impacts of conversion to IFRS, including the adoption of potential IFRS standards under development that might impact the Trust, have not been determined.

In addition to existing IFRS standards, new or revised IFRS standards are being developed by the International Accounting Standards Board ("IASB") which may impact the Trust depending on the timing of their implementation. These standards include Joint Ventures, Income Taxes, Financial Instruments, Emissions Trading Schemes, Extractive Industries, Employee Future Benefits, and Measurement of Liabilities. The Trust continues to monitor the developments within IFRS which might impact its conversion.

The final impacts to the Trust's consolidated financial statements upon the adoption of IFRS will depend on IFRS standards existing in 2011, as well as the accounting policy choices made by Canadian Oil Sands.


2010 OUTLOOK

(millions of Canadian dollars, except
 volume and per barrel amounts)         January 28, 2010   October 28, 2009
----------------------------------------------------------------------------

Syncrude production (MMbbls)                         115                115
Canadian Oil Sands Sales (MMbbls)                   42.3               42.3
Revenues, net of crude oil
 purchases and transportation                      3,029              2,986
Operating costs                                    1,480              1,479
Operating costs per barrel                         35.04              35.01
Crown royalties                                      317                272
Capital expenditures                                 541                541
Cash from operating activities                     1,013                969

Business environment assumptions
---------------------------------
West Texas Intermediate (US$/bbl)                $    70            $    70
Premium (Discount) to average C$
 WTI prices (C$/bbl)                             $ (2.00)           $ (3.00)
Foreign exchange rate (US$/Cdn$)                 $  0.95            $  0.95
AECO natural gas (Cdn$/GJ)                       $  6.00            $  6.00

Canadian Oil Sands' operating costs are estimated at $1,480 million, or $35 per barrel, with capital expenditures of $541 million mainly related to sustaining Syncrude operations.

The outlook continues to incorporate an estimated U.S. $70 per barrel WTI price and a $0.95 U.S./Cdn foreign exchange rate, but the SCO discount to Cdn dollar WTI has been reduced to $2 per barrel from $3 per barrel. These assumptions result in estimated revenues of $3,029 million, or $72 per barrel in 2010. In addition, we have increased our assumed bitumen value in calculating Crown royalties to 70 per cent of Canadian dollar WTI, from 65 per cent. Working capital estimates have also been revised to reflect actual year end balances.

Based on the above assumptions, our 2010 outlook for cash from operating activities is $1,013 million, or $2.09 per Unit. After deducting budgeted 2010 capital expenditures of $541 million, we are estimating $472 million of remaining cash from operating activities, or $0.97 per Unit.


2010 Outlook Sensitivity Analysis (January 28, 2010)

                                             Cash from Operating Activities
                                                        Increase
                                           Annual
Variable (1)                          Sensitivity  $ millions  $/Trust unit
----------------------------------------------------------------------------
Syncrude operating costs decrease      C$1.00/bbl          35          0.07
Syncrude operating costs decrease    C$50 million          15          0.03
WTI crude oil price increase          US$1.00/bbl          33          0.07
Syncrude production increase       2 million bbls          39          0.08
Canadian dollar weakening              US$0.01/C$          23          0.05
AECO natural gas price decrease         C$0.50/GJ          17          0.04


(1) An opposite change in each of these variables will result in the
    opposite cash from operating activities impacts.
    Canadian Oil Sands may become subject to minimum Crown royalties at a
    rate of one per cent of gross bitumen revenue. The sensitivities
    presented herein assume royalties are paid at 25 per cent of net
    bitumen revenue.




CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(unaudited)

                                     Three Months Ended Twelve Months Ended
                                         December 31        December 31
($ millions, except per Unit amounts)    2009      2008      2009      2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Revenues                               $  895    $  768    $2,779    $4,543
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Expenses:
 Operating                                331       326     1,328     1,368
 Non-production                            35        24       141        78
 Crude oil purchases and
  transportation expense                   32        64       164       374
 Crown royalties                           93        59       228       599
 Administration                             6         1        24        17
 Insurance                                  3         1         9         6
 Interest, net (Note 9)                    23        19        93        68
 Depreciation, depletion and
  accretion (Note 5)                      260       119       570       444
 Goodwill impairment (Note 5)              52         -        52         -
 Foreign exchange loss (gain)             (23)      106      (161)      159
----------------------------------------------------------------------------
                                          812       719     2,448     3,113
----------------------------------------------------------------------------
Earnings before taxes                      83        49       331     1,430
 Future income tax expense (recovery)
  and other (Note 10)                     (13)      (75)     (101)      (93)
----------------------------------------------------------------------------
Net income                                 96       124       432     1,523
Other comprehensive loss, net of
 income taxes
 Reclassification of derivative gains
  to net income                            (1)       (1)       (3)       (3)
----------------------------------------------------------------------------
Comprehensive income                   $   95    $  123    $  429    $1,520
----------------------------------------------------------------------------

Weighted average Trust Units (millions)   484       482       484       481
Trust Units, end of period (millions)     484       482       484       482

Net income per Trust Unit:
 Basic                                 $ 0.20    $ 0.26    $ 0.89    $ 3.17
 Diluted                               $ 0.20    $ 0.26    $ 0.89    $ 3.16

See Notes to Unaudited Consolidated Financial Statements



CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
(unaudited)
                                           Three Months       Twelve Months
                                              Ended               Ended
                                           December 31         December 31
($ millions)                             2009      2008      2009      2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Retained earnings
 Balance, beginning of period         $ 1,432   $ 1,599   $ 1,362   $ 1,643
 Net income                                96       124       432     1,523
 Unitholder distributions (Note 12)      (169)     (361)     (435)   (1,804)
----------------------------------------------------------------------------
 Balance, end of period                 1,359     1,362     1,359     1,362
----------------------------------------------------------------------------
Accumulated other comprehensive income
 Balance, beginning of period              19        22        21        24
 Other comprehensive loss                  (1)       (1)       (3)       (3)
----------------------------------------------------------------------------
 Balance, end of period                    18        21        18        21
----------------------------------------------------------------------------
Unitholders' capital
 Balance, beginning of period           2,587     2,524     2,524     2,500
 Issuance of Trust Units (Note 4)           -         -        63        24
----------------------------------------------------------------------------
 Balance, end of period                 2,587     2,524     2,587     2,524
----------------------------------------------------------------------------
Contributed surplus
 Balance, beginning of period               5         3         3         5
 Exercise of employee stock options         -         -         -        (3)
 Stock-based compensation                   -         -         2         1
----------------------------------------------------------------------------
 Balance, end of period                     5         3         5         3
----------------------------------------------------------------------------
Total Unitholders' equity             $ 3,969   $ 3,910   $ 3,969   $ 3,910
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements


CANADIAN OIL SANDS TRUST
CONSOLIDATED BALANCE SHEETS
AS AT
(unaudited)


                                                 December 31    December 31
($ millions)                                            2009           2008
----------------------------------------------------------------------------

ASSETS
 Current assets:
  Cash and cash equivalents                         $    122       $    279
  Accounts receivable                                    354            184
  Inventories                                            133             93
  Prepaid expenses                                         7              5
----------------------------------------------------------------------------
                                                         616            561

 Property, plant and equipment, net                    6,289          6,277
 Goodwill (Note 5)                                         -             52
 Reclamation trust (Note 13)                              48             43
----------------------------------------------------------------------------

                                                    $  6,953       $  6,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
 Current liabilities:
  Accounts payable and accrued liabilities          $    284       $    284
  Current portion of employee future benefits
   (Note 6)                                               17             17
----------------------------------------------------------------------------
                                                         301            301

 Employee future benefits and other liabilities
  (Note 6)                                               104             99
 Long-term debt (Note 8)                               1,163          1,258
 Asset retirement obligation (Note 13)                   389            235
 Future income taxes                                   1,027          1,130
----------------------------------------------------------------------------
                                                       2,984          3,023

Unitholders' equity                                    3,969          3,910
----------------------------------------------------------------------------
                                                    $  6,953       $  6,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements


CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)

                                          Three Months       Twelve Months
                                             Ended               Ended
                                           December 31         December 31
($ millions)                             2009      2008      2009      2008
----------------------------------------------------------------------------

Cash from (used in) operating
 activities
 Net income                            $   96   $   124   $   432  $  1,523
 Items not requiring outlay of cash:
  Depreciation, depletion and accretion
   (Note 5)                               260       119       570       444
  Goodwill impairment (Note 5)             52         -        52         -
  Foreign exchange loss (gain) on
   long-term debt                         (28)      142      (200)      204
  Future income tax expense (recovery)    (13)      (75)     (101)      (93)
 Net change in deferred items and other    (1)      (18)        1       (39)
----------------------------------------------------------------------------
                                          366       292       754     2,039
Change in non-cash working capital        (38)      174      (207)      202
----------------------------------------------------------------------------
 Cash from (used in) operating
  activities                              328       466       547     2,241
----------------------------------------------------------------------------

Cash from (used in) financing
 activities
 Issuance of Senior Notes (Note 8)          -         -       574         -
 Repayment of medium term and Senior
  Notes (Note 8)                            -         -      (471)     (150)
 Net drawdown (repayment) of bank
  credit facilities                         -         -         -       (16)
 Unitholder distributions (Note 12)      (169)     (361)     (372)   (1,804)
 Issuance of Trust Units (Note 4)           -         -         -        21
----------------------------------------------------------------------------
  Cash from (used) in financing
   activities                            (169)     (361)     (269)   (1,949)
----------------------------------------------------------------------------

Cash from (used in) investing activities
 Capital expenditures                    (101)      (86)     (409)     (281)
 Reclamation trust funding                 (2)       (2)       (5)       (6)
 Change in non-cash working capital        (8)      (16)       (2)        6
----------------------------------------------------------------------------
  Cash used in investing activities      (111)     (104)     (416)     (281)
----------------------------------------------------------------------------

Foreign exchange loss on Cash and Cash
 equivalents held in foreign currency       -         -       (19)        -
----------------------------------------------------------------------------

Increase (decrease) in cash and cash
 equivalents                               48         1      (157)       11

Cash and cash equivalents at
 beginning of period                       74       278       279       268
----------------------------------------------------------------------------

Cash and cash equivalents at end of
 period                               $   122   $   279   $   122 $     279
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash and cash equivalents consist of:
 Cash                                                     $    18 $      18
 Short-term investments                                       104       261
----------------------------------------------------------------------------
                                                          $   122 $     279
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplementary Information (Note 15)

See Notes to Unaudited Consolidated Financial Statements

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE AND TWELVE MONTHS ENDED DECEMBER 31, 2009

(Tabular amounts expressed in millions of Canadian dollars, except where otherwise noted.)

1) BASIS OF PRESENTATION

The interim consolidated financial statements include the accounts of Canadian Oil Sands Trust and its subsidiaries (collectively, the "Trust" or "Canadian Oil Sands"), and are presented in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2008, except as discussed in Note 2. Certain disclosures that are normally required to be included in the notes to the annual audited consolidated financial statements have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in the Trust's annual report for the year ended December 31, 2008.

2) CHANGES IN ACCOUNTING POLICIES

In 2009 the Trust adopted the requirements of the Canadian Institute of Chartered Accountants ("CICA") - Section 3064 Goodwill and Intangible Assets, which replaced Section 3062 Goodwill and Other Intangible Assets, and Section 3450 Research and Development Costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. Application of the new section did not have a material impact on the Trust's financial statements.

3) FUTURE CHANGES IN ACCOUNTING POLICIES

The Trust will be subject to International Financial Reporting Standards ("IFRS") commencing in 2011. The Trust is currently assessing the impact conversion to IFRS may have on its financial statements.

4) ISSUANCE OF TRUST UNITS

In the twelve months ended December 31, 2009, approximately 2.9 million Trust Units were issued pursuant to the Trust's Premium Distribution, Distribution Re-investment and Optional Unit Purchase Plan ("DRIP") for $63 million.

In the twelve months ended December 31, 2008, approximately two million Trust Units were issued for $24 million on the exercise of employee stock options.

5) GOODWILL AND DEPRECIATION, DEPLETION, AND ACCRETION EXPENSE

As a result of these uncertainties, the Trust extended its assumed timing for development of the Arctic assets. Based on a net present value analysis which assumes a deferred project start date, additional depreciation and depletion of $130 million ($96 million after tax) was recorded by the Trust. A goodwill impairment of $52 million has also been recorded. As a result, net income during the quarter was reduced by $148 million after tax ($182 million pre-tax).

6) EMPLOYEE FUTURE BENEFITS

Canadian Oil Sands' share of Syncrude Canada's net defined benefit and contribution plans expense for the three and twelve months ended December 31, 2009 and 2008 is based on its 36.74 per cent working interest. The costs have been recorded in operating expense as follows:


                                     Three Months Ended Twelve Months Ended
                                           December 31         December 31
                                         2009      2008      2009      2008
----------------------------------------------------------------------------
Defined benefit plans:
 Pension benefits                        $ 12       $ 6     $  40     $  29
 Other benefit plans                        1         2         4         5
----------------------------------------------------------------------------
                                         $ 13       $ 8     $  44     $  34

Defined contribution plans                  1         -         3         2
----------------------------------------------------------------------------
 Total benefit cost                      $ 14       $ 8     $  47     $  36
----------------------------------------------------------------------------


7) BANK CREDIT FACILITIES

Extendible revolving term facility (a)                                $  40
Line of credit (b)                                                       70
Operating credit facility (c)                                           800
----------------------------------------------------------------------------
                                                                      $ 910
----------------------------------------------------------------------------
----------------------------------------------------------------------------

a) The $40 million extendible revolving term facility is a 364-day facility with a one-year term out, expiring April 22, 2010. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at December 31, 2009, no amounts were drawn on this facility ($Nil - December 31, 2008).

b) The $70 million line of credit is a one-year revolving letter of credit facility. Letters of credit drawn on the facility mature April 30th each year and are automatically renewed, unless notification to cancel is provided by Canadian Oil Sands or the financial institution providing the facility at least 60 days prior to expiry. Letters of credit on this facility bear interest at a credit spread.

Letters of credit of approximately $70 million were written against the line of credit as at December 31, 2009.

c) The $800 million operating facility is a multi-year facility, expiring April 27, 2012. Amounts borrowed through this facility bear interest at a floating rate based on either prime interest rates or bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at December 31, 2009, no amounts were drawn against this facility ($Nil - December 31, 2008).

8) LONG-TERM DEBT

On May 11, 2009, the Trust issued U.S. $500 million of 7.75 per cent Senior Notes, maturing May 15, 2019. Interest is payable on the notes semi-annually on May 15 and November 15.

On June 29, 2009 the Trust repaid $200 million of 5.55 per cent Medium Term Notes.

On August 10, 2009 the Trust repaid U.S. $250 million of 4.8 per cent Senior Notes.

9) INTEREST, NET


                                     Three Months Ended Twelve Months Ended
                                           December 31         December 31
($ millions)                             2009      2008      2009      2008
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Interest expense on long-term debt    $    23    $   20      $ 94  $     76
Interest income and other                   -        (1)       (1)       (8)
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 Interest expense, net                $    23    $   19      $ 93  $     68
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10) FUTURE INCOME TAXES

During the first quarter of 2009, an additional $63 million future income tax recovery was recorded on the substantive enactment of legislation to reduce the tax rates applicable to the Trust in 2011.

11) STOCK BASED COMPENSATION

During 2009, 486,542 options were issued by the Trust to employees with an average exercise price of $19.77 pursuant to the Trust's Unit Incentive Option Plan. The options have an estimated value of $2 million.

12) UNITHOLDER DISTRIBUTIONS

Pursuant to Section 5.1 of the Trust Indenture, the Trust is required to distribute all the Distributable Income, as defined by the Trust Indenture, received or receivable by the Trust in a quarter. The Trust's Distributable Income primarily consists of a royalty from its operating subsidiary, Canadian Oil Sands Limited ("COSL"). The royalty is designed to capture the cash generated by COSL, after the deduction of all costs and expenses including operating and administrative costs, income taxes, capital expenditures, debt interest and principal repayments, working capital and reserves for future obligations deemed appropriate. The amount of royalty income that the Trust receives in any period has a considerable amount of flexibility through the use of discretionary reserves and debt borrowings or repayments (either intercompany or third party). Quarterly distributions are determined by COSL's Board of Directors after considering the current and expected economic and operating conditions, ensuring financing capacity for Syncrude's expansion projects and/or Canadian Oil Sands acquisitions, and with the objective of maintaining an investment grade credit rating.


                                     Three Months Ended Twelve Months Ended
                                           December 31         December 31
                                         2009      2008      2009      2008
----------------------------------------------------------------------------
Cash from operating activities        $   328    $  466    $  547   $ 2,241
Add (Deduct):
 Capital expenditures                    (101)      (86)     (409)     (281)
 Change in non-cash working capital(1)     (8)      (16)       (2)        6
 Reclamation trust funding                 (2)       (2)       (5)       (6)
 Change in cash and cash equivalents
  and financing, net (2)                  (48)       (1)      304      (156)
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Unitholder distributions              $   169    $  361    $  435   $ 1,804
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Unitholder distributions per Trust
 Unit                                 $  0.35    $ 0.75    $ 0.90   $  3.75
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(1) From investing activities.

(2) Primarily represents the change in cash and cash equivalents and net
    financing to fund the Trust's share of investing activities.

Unitholder distributions during 2009 were funded by cash payments of $372 million and by the issuance of 2.9 million Trust Units for $63 million.

13) ASSET RETIREMENT OBLIGATION AND RECLAMATION TRUST

Canadian Oil Sands and each of the other Syncrude owners are liable for their share of ongoing environmental obligations related to the ultimate reclamation of the Syncrude properties on abandonment. The Trust estimates reclamation expenditures will be made over approximately the next 60 years and has applied an average credit-adjusted risk-free discount rate of six per cent (2008-six per cent) in deriving the asset retirement obligation.

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the Trust's share of the obligation associated with the retirement of Syncrude properties.


                                                       As at          As at
                                                 December 31,   December 31,
                                                        2009           2008
----------------------------------------------------------------------------

Asset retirement obligation, beginning of year         $ 235          $ 226
Liabilities settled                                      (25)           (14)
Accretion expense                                         17             14
Change in estimated future cash flows                    162              9
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Asset retirement obligation, end of period             $ 389          $ 235
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During the third quarter of 2009, the Trust increased its estimated asset retirement obligation as a result of revisions to cost estimates, the expected timing of reclamation expenditures, and revised material movement assumptions to reflect mine plan changes.

The total undiscounted estimated cash flows required to settle the Trust's share of Syncrude's obligation was $903 million at December 31, 2009 (December 31, 2008 - $774 million).

The reclamation expenditures will be funded from Canadian Oil Sands' cash from operating activities and reclamation trust. In addition to annual funding for reclamation expenditures, Canadian Oil Sands deposits $0.1322 per barrel of production attributable to its Working Interest to a reclamation trust established for the purpose of funding the operating subsidiary's share of environmental and reclamation obligations. As at December 31, 2009, including interest earned on investments, the balance of the reclamation trust was $48 million (December 31, 2008 - $43 million).

The Trust has posted letters of credit with the Province of Alberta in the amount of $70 million (December 31, 2008 - $67 million) to secure its pro rata share of the reclamation obligations of the Syncrude joint venture owners.

14) COMMITMENTS

During 2009, Syncrude entered into new natural gas purchase commitments that expire between 2009 and 2011. The value of this commitment will fluctuate with changes to natural gas prices. Based on an estimated AECO price of $6.00/GJ, the remaining commitment to the Trust for these contracts at December 31, 2009 is approximately $169 million.

Syncrude has also entered into other new commitments during 2009, which expire between 2013 and 2035. The total value of these commitments at December 31, 2009 was $72 million, or $26 million net to the Trust.

During 2009 Canadian Oil Sands entered into oil storage commitments which will expire in 2013. The remaining commitment as at December 31, 2009 was $12 million.

15) SUPPLEMENTARY INFORMATION


                                     Three Months Ended Twelve Months Ended
                                           December 31         December 31
                                         2009      2008      2009      2008
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Income tax paid                         $   -      $  -         -      $  -
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Interest paid                           $  24      $ 18        92      $ 74
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Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Units Listed - Symbol: COS.UN

Toronto Stock Exchange

Contacts:
Canadian Oil Sands Trust
Siren Fisekci
Director, Investor Relations
(403) 218-6228
investor_relations@cos-trust.comwww.cos-trust.com