Canadian Oil Sands Trust
TSX : COS.UN

Canadian Oil Sands Trust

July 27, 2009 19:24 ET

CORRECTION FROM SOURCE: Canadian Oil Sands Trust Announces 2009 Second Quarter Results

CALGARY, ALBERTA--(Marketwire - July 27, 2009) - A correction from source is being issued with respect to the release sent out July 27, 2009 at 17:48 ET. The corrected version replaces the Consolidated Statements of Cash Flows table. The corrected version follows:

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 cash used in operating activities of $44 million ($0.09 per Trust unit ("Unit")) for the second quarter of 2009 compared with cash from operating activities of $413 million ($0.86 per Unit) for the same period last year. During the first half of 2009, cash from operating activities was $6 million ($0.01 per Unit) compared with the $854 million ($1.78 per Unit) in the 2008 six-month period.

Net income for the second quarter of 2009 was $46 million ($0.10 per Unit) compared with $497 million ($1.04 per Unit) of net income in the 2008 period. Year-to-date, net income totaled $89 million ($0.18 per Unit) in 2009 compared with $795 million ($1.66 per Unit) in 2008.

The decreases in cash from operating activities and net income on a quarter and year-over-year basis reflect lower crude oil prices and lower production, partially offset by a decrease in Crown royalties expense. Net income in 2009 also reflects unrealized foreign exchange gains on U.S. dollar denominated debt and higher future income tax recoveries than the first half of 2008.

The Trust has declared a quarterly distribution amount of $0.25 per Unit for Unitholders of record on August 17, 2009, payable on August 28, 2009, a $0.10 per Unit increase from the distribution paid in the prior quarter. Effective July 25, 2009, the Trust suspended its Premium Distribution, Distribution Re-Investment and Optional Unit Purchase Plan ("DRIP"). The DRIP was active during the first half of 2009, but with the strengthening of crude oil prices and the improvement in the Trust's liquidity position, the Trust no longer felt it was needed.

"Although the first half of 2009 was very challenging operationally, the largest impact to our results was the weaker crude oil prices year-over-year," said Marcel Coutu, President and Chief Executive Officer. "Syncrude made a large investment in repairs and modifications to its new Coker 8-3 complex, designed to improve future yields and run lengths. With this major work completed and mining operations on an improving trend from the bitumen constraints experienced in the last 12 months, we are looking forward to a strong second half of the year and progress towards achieving design capacity rates. Our confidence in the operations, strengthening crude oil prices and an improved liquidity position support our decision to increase the distribution to $0.25 per Unit."

Sales volumes during the second quarter of 2009 averaged about 76,000 barrels per day compared with about 98,000 barrels per day during the same period in 2008. For the first half of 2009, sales volumes averaged about 89,000 barrels per day versus 98,000 barrels per day during the 2008 period. In 2009, Syncrude conducted a scheduled, comprehensive turnaround of Coker 8-3 and related units, the primary upgrading unit brought into operation in August 2006 as part of the Stage 3 expansion. The turnaround included modifications to improve the coker's run length and yield. The work took longer than originally anticipated because of additional work scope, schedule inefficiencies due to an earlier than planned shutdown, and lower than budget workforce productivity. Production in 2009 also was reduced by Coker 8-1 circulation issues and reliability issues in the mining and upgrading operations during the second quarter, and bitumen supply constraints in the first quarter. By comparison, 2008 first half production was impacted by a smaller Coker 8-1 turnaround, bitumen production constraints, and a disruption in operations in the first quarter.

In the second quarter of 2009, Syncrude's total recordable injury rate was 0.33 for every 200,000 hours worked compared to a rate of 0.34 recorded for the same period of 2008.

The reduced production volumes resulted in higher per barrel operating costs in 2009 compared with 2008. For the second quarter of 2009, operating costs averaged $50.23 per barrel compared with $41.92 per barrel in 2008. For the six-month period, per barrel operating costs were $43.66 and $38.90 in 2009 and 2008, respectively. Syncrude's operating costs are largely fixed, so changes in production volumes significantly impact per barrel operating costs.

Capital expenditures for the first half of 2009 were $223 million compared with $101 million in the same period of 2008, reflecting expenditures for the Syncrude Emissions Reduction project, tailings facilities and equipment purchases to improve bitumen production capabilities.

The Trust's liquidity position improved significantly in the second quarter of 2009 with the refinancing of its two 2009 debt maturities through the issuance of U.S. $500 million of Senior unsecured notes. The notes have an annual interest rate of 7.75 per cent payable semi-annually and mature on May 15, 2019.



CANADIAN OIL SANDS TRUST
Highlights

(millions of Canadian dollars, Three Months Ended Six Months Ended
except Trust unit and volume June 30 June 30
amounts) 2009 2008 2009 2008
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Net Income $ 46 $ 497 $ 89 $ 795
Per Trust unit- Basic $ 0.10 $ 1.04 $ 0.18 $ 1.66
Per Trust unit- Diluted $ 0.10 $ 1.04 $ 0.18 $ 1.65

Cash from (used in) Operating
Activities $ (44) $ 413 $ 6 $ 854
Per Trust unit $ (0.09) $ 0.86 $ 0.01 $ 1.78

Unitholder Distributions $ 73 $ 481 $ 145 $ 841
Per Trust unit $ 0.15 $ 1.00 $ 0.30 $ 1.75

Sales Volumes (1)
Total (MMbbls) 6.8 8.9 16.1 17.9
Daily average (bbls) 75,553 97,744 89,114 98,463

Operating Costs per barrel $ 50.23 $ 41.92 $ 43.66 $ 38.90

Net Realized SCO Selling Price
per barrel $ 67.92 $ 131.32 $ 60.69 $ 115.76

West Texas Intermediate (average
$US per barrel) (2) $ 59.79 $ 123.80 $ 51.68 $ 111.12
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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 net of purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.


2009 Outlook

The Trust has lowered its estimate for Syncrude production to 104 million barrels in 2009 to reflect actual results in the first half of the year. Substantially all of Syncrude's major maintenance work planned for 2009 has been completed and the continued focus is on broad plant reliability to ensure bitumen production is sufficient to meet the expected high availability in the upgrader. While the next coker turnaround is scheduled in 2010, circulation issues on Coker 8-1 during the second quarter suggest a heightened risk of advancing the turnaround into 2009; if this occurs, our 2009 production estimate would fall by approximately three million barrels.

Largely reflecting the impact of lower production, the Trust has increased its average annual per barrel operating cost estimate for 2009 to $35 per barrel.

For 2009, we are assuming an average crude oil price of U.S. $55 per barrel WTI, a $0.87 U.S./Cdn foreign exchange rate, and a discount of $1.50 per barrel for our synthetic crude oil relative to Cdn $ WTI.

Based on the above assumptions, we estimate 2009 cash from operating activities of $519 million, or $1.07 per Unit. After deducting capital expenditures of $460 million, we are estimating $59 million of remaining cash from operating activities.

More information on the Trust's outlook is provided in the MD&A section of this report and the July 27, 2009 guidance document, which is available on the Trust's web site at www.cos-trust.com under "investor information".

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") was prepared as of July 27, 2009 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, 2009 and June 30, 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 and postponement of projects; the planned uses for the remainder of the funds from the U.S. Senior Note financing; Crown royalties for the second half of 2009; the expected structure to be assumed given the Federal government's tax changes effective in 2011; 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 preservation of financial flexibility and the ability to meet operating and capital costs from the assumed cash from operating activities in 2009; the expected production, revenues and operating costs for 2009; 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 bitumen purchases, capital expenditures and operating costs; the cost estimate for the 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; 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 belief that the Trust will not be restricted by its net debt to total capitalization financial covenant; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2009 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 Stage 4 development; the level of energy consumption in 2009 and beyond; capital expenditures for 2009; the level of natural gas consumption in 2009 and beyond; the expected price for crude oil and natural gas in 2009 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 second quarter of 2009, crude oil production from the Syncrude Joint Venture ("Syncrude") totalled 18.8 million barrels, or about 206,000 barrels per day, compared with 24.1 million barrels, or about 265,000 barrels per day, during the same period of 2008. Net to the Trust, production totaled 6.9 million barrels in the second quarter of 2009 compared with 8.9 million barrels in 2008, based on our 36.74 per cent working interest.

Production volumes and costs in the second quarter of 2009 were impacted by the turnaround of Coker 8-3 and related units, which began in mid-March and was completed in early June. This was a comprehensive turnaround of the coker and related units associated with the Stage 3 expansion that commenced operations in August, 2006. The turnaround of Coker 8-3 was originally expected to take approximately 60 days; however, it took longer than anticipated because of additional work scope discovered during unit inspections, schedule inefficiencies due to an earlier than planned shutdown, and lower than budget workforce productivity. This turnaround also included modifications to Coker 8-3 which are designed to improve both yield and run length. In addition, coke circulation issues in Coker 8-1 and reliability issues in the mining and upgrading operations reduced production during the second quarter of 2009. By comparison, production during the second quarter of 2008 was impacted by a smaller turnaround of Coker 8-1, which lasted 45 days.

Year-to-date, Syncrude produced 43.4 million barrels in 2009 or about 240,000 barrels per day, compared with 48.4 million barrels or about 266,000 barrels per day in 2008. In addition to the 2009 turnaround activities, circulation issues with Coker 8-1 and operational reliability issues in the second quarter, production in the first half of 2009 was impacted by first quarter bitumen production constraints. By comparison, production in the first half of 2008 reflected the turnaround of Coker 8-1 during the second quarter, bitumen production constraints and a disruption in operations during the first quarter.

Operating costs increased to $50.23 per barrel in the second quarter of 2009, up $8.31 per barrel from the same quarter of 2008. Year-to-date operating costs were $43.66 per barrel in 2009 versus $38.90 per barrel in 2008 (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. 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.

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

During the second quarter of 2009, U.S. dollar West Texas Intermediate ("WTI") oil prices improved, averaging U.S. $59.79 per barrel versus U.S. $43.31 per barrel during the first quarter of 2009. Partially offsetting the oil price increase, the Canadian dollar averaged $0.86 U.S./Cdn in the second quarter versus $0.80 U.S./Cdn for the first quarter of 2009. Compared to the prior year, however, commodity prices during 2009 were substantially lower than 2008 with U.S. dollar WTI prices averaging $51.68 per barrel for the first six months of 2009 versus $111.12 per barrel in the same period of 2008.

The deterioration in economic conditions over the past year has resulted in the deferral or cancellation of several development projects, including oil sands projects in the Fort McMurray region. It is reasonable to expect this slowdown in activity to contribute to lower costs for industry over time through more competitive access to labour and materials; however, it is difficult to determine the potential impact as it takes time for the changes to materialize into lower reported costs. Furthermore, 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 stipulate wage increases for at least another year. Syncrude continues to explore ways to reduce its costs structure, including accessing procurement systems through the Management Services Agreement; however, we cannot yet determine if these efforts and the economic slowdown will result in any long-term reductions in Syncrude's costs. We continue to believe the most significant factor in reducing costs is better operational reliability.

Credit markets have improved and the Trust issued U.S. $500 million in long-term debt during the second quarter. Proceeds from the debt issue were used to refinance $200 million of Medium Term notes on maturity and to repay amounts outstanding on the bank credit facilities, with the remaining funds to be used to refinance a U.S. $250 million Senior Note maturity in the third quarter of 2009 and for general corporate purposes. With the increase in oil prices, the substantial completion of our maintenance program, and funding from the most recent debt issuance, the Trust's liquidity position has improved significantly as it enters the second half of 2009. The Trust continues to be well positioned to execute its strategies.



SUMMARY OF QUARTERLY RESULTS

($ millions,
except per
Trust Unit and
volume 2009 2008 2007
amounts) Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
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Revenues (1) $ 467 $ 512 $ 704 $ 1,381 $1,177 $ 907 $ 950 $ 936

Net income
(loss) $ 46 $ 43 $ 124 $ 604 $ 497 $ 298 $ 515 $ 361
Per Trust
Unit, Basic $ 0.10 $ 0.09 $ 0.26 $ 1.25 $ 1.04 $ 0.62 $ 1.07 $ 0.75
Per Trust
Unit,
Diluted $ 0.10 $ 0.09 $ 0.26 $ 1.25 $ 1.04 $ 0.62 $ 1.07 $ 0.75

Cash from
operating
activities $ (44) $ 50 $ 466 $ 921 $ 413 $ 441 $ 367 $ 484

Per Trust Unit
(2) $(0.09) $ 0.10 $ 0.97 $ 1.91 $ 0.86 $ 0.92 $ 0.77 $ 1.01

Unitholder
distributions $ 73 $ 72 $ 361 $ 602 $ 481 $ 360 $ 264 $ 192
Per Trust
Unit $ 0.15 $ 0.15 $ 0.75 $ 1.25 $ 1.00 $ 0.75 $ 0.55 $ 0.40

Daily average
sales volumes
(bbls) (3) 75,553 102,825 110,197 116,656 97,744 99,181 116,368 124,904

Net realized
SCO selling
price ($/bbl)
(4) $67.92 $55.32 $ 69.40 $127.55 $131.32 $100.41 $ 88.73 $ 81.48

Operating
costs ($/bbl)
(5) $50.23 $38.78 $ 32.10 $ 32.15 $ 41.92 $ 35.93 $ 27.38 $ 20.84

Purchased
natural gas
price ($/GJ) $ 3.09 $ 4.96 $ 6.41 $ 7.86 $ 9.38 $ 7.30 $ 5.84 $ 4.99
West Texas
Intermediate
(avg. US$/bbl)
(6) $59.79 $43.31 $ 59.08 $118.22 $123.80 $ 97.82 $ 90.50 $ 75.15

Foreign
exchange rates
(US$/Cdn$):
Average $ 0.86 $ 0.80 $ 0.83 $ 0.96 $ 0.99 $ 1.00 $ 1.02 $ 0.96
Quarter- end $ 0.86 $ 0.79 $ 0.82 $ 0.94 $ 0.98 $ 0.97 $ 1.01 $ 1.00

(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 significantly impacted the Trust's revenues, Crown royalties, net income and cash from operating activities;

- 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 significant unrealized 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 and in the fourth quarter of 2007 resulted in future income tax recoveries of $63 million and $153 million, respectively.

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 and by future income tax amounts. A large proportion of operating costs are fixed and, as such, per barrel operating costs are highly 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 significantly influenced by weather conditions and North American natural gas inventory levels. In addition, production levels may not display reliable seasonality 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 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 2009, the Trust reported net income of $46 million, or $0.10 per Unit, compared with net income of $497 million, or $1.04 per Unit, recorded in the second quarter of 2008. The decrease was primarily the result of lower revenues, net of lower Crown royalties and foreign exchange gains.

Net income in the first six months of 2009 totaled $89 million, or $0.18 per Unit compared with net income of $795 million, or $1.66 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 $467 million in the second quarter of 2009 versus $1,177 million in the second quarter of 2008. On a year-to-date basis, revenues after crude oil purchases and transportation costs totaled $979 million in 2009 versus $2,084 million in 2008. The decrease in revenues was due to lower commodity prices and production volumes in 2009 (see "Revenues after Crude Oil Purchases and Transportation Expense" section of this MD&A for further discussion).

Cash used in operating activities was $44 million for the second quarter of 2009 versus cash from operating activities of $413 million for the second quarter of 2008. Year-to-date cash from operating activities decreased to $6 million for 2009 versus $854 million for 2008. The change in cash from operating activities was due to the decrease in revenues, reflecting lower crude oil prices, lower production, and increases in non-cash working capital partially offset by lower Crown royalties.

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 compared to March 31, 2009. In the second quarter of 2008, non-cash working capital reduced cash from operating activities by $162 million, primarily as a result of higher accounts receivable at June 30, 2008 relative to March 31, 2008.

In the first six months 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. In the same period of 2008, non-cash working capital reduced cash from operating activities by $136 million primarily as a result of higher accounts receivable net of higher accounts payable at June 30, 2008 relative to December 31, 2007.

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 and certain per barrel measures. These 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 (Loss) per Barrel
Three Months Ended Six Months Ended
June 30 June 30
($ per bbl) (1) 2009 2008 Variance 2009 2008 Variance
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Revenues after crude
oil purchases and
transportation expense 67.92 132.34 (64.42) 60.69 116.30 (55.61)
Operating costs (50.23) (41.92) (8.31) (43.66) (38.90) (4.76)
Crown royalties (3.33) (19.94) 16.61 (1.69) (17.24) 15.55
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14.36 70.48 (56.12) 15.34 60.16 (44.82)
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Non-production costs (5.65) (1.79) (3.86) (4.46) (1.83) (2.63)
Administration and
insurance (1.15) (0.97) (0.18) (0.96) (0.86) (0.10)
Interest, net (3.64) (1.87) (1.77) (2.78) (1.85) (0.93)
Depletion, depreciation
and accretion (11.82) (11.39) (0.43) (11.60) (11.37) (0.23)
Foreign exchange
gain (loss) 11.22 0.51 10.71 2.96 (1.17) 4.13
Future income tax
(expense) recovery
and other 3.37 1.12 2.25 6.99 1.34 5.65
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(7.67) (14.39) 6.72 (9.85) (15.74) 5.89
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Net income per barrel 6.69 56.09 (49.40) 5.49 44.42 (38.93)
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Sales volumes
(MMbbls)(2) 6.8 8.9 (2.1) 16.1 17.9 (1.8)
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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, net of purchased crude oil volumes.


Revenues after Crude Oil Purchases and Transportation Expense

Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2009 2008 Variance 2009 2008 Variance
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Sales revenue (1) $ 525 $ 1,285 $ (760) $1,073 $2,310 $ (1,237)
Crude oil purchases (52) (101) 49 (81) (210) 129
Transportation expense (7) (8) 1 (15) (18) 3
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466 1,176 (710) 977 2,082 (1,105)

Currency hedging
gains (1) 1 1 - 2 2 -
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$ 467 $ 1,177 $ (710) $ 979 $2,084 $ (1,105)
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Sales volumes
(MMbbls) (2) 6.8 8.9 (2.1) 16.1 17.9 (1.8)
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(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)
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Realized SCO selling
price before
hedging (3) $ 67.79 $131.22 $ (63.43) $60.58 $115.66 $ (55.08)
Currency hedging
gains 0.13 0.10 0.03 0.11 0.10 0.01
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Net realized SCO
selling price $ 67.92 $131.32 $ (63.40) $60.69 $115.76 $ (55.07)
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(3) SCO sales revenue after crude oil purchases and transportation expense
divided by sales volumes, net of purchased crude oil volumes.


The decrease in sales revenue on both a quarterly and a year-to-date basis for 2009 versus 2008 reflects both a lower realized selling price for our synthetic crude oil ("SCO") and lower production volumes. During the second quarter of 2009, the WTI price averaged U.S. $59.79 per barrel compared to U.S. $123.80 per barrel for the second quarter of 2008. The impact of the lower U.S. dollar WTI price in the second quarter 2009 was offset somewhat by a weaker Canadian dollar, which averaged $0.86 U.S./Cdn for the second quarter of 2009 versus $0.99 U.S./Cdn for the second quarter of 2008. Year-to-date, WTI averaged U.S. $51.68 per barrel in 2009 versus U.S. $111.12 per barrel 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 second quarter of 2009, the Trust's SCO realized a weighted-average discount of $2.59 per barrel versus a premium of $4.05 per barrel for the same period of 2008. Year-to-date in 2009, the Trust's SCO realized a weighted-average discount of $0.29 per barrel relative to the average Canadian dollar WTI price versus a premium of $2.87 per barrel in the same period of 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 sales volumes for the second quarter averaged 76,000 barrels per day and 98,000 barrels per day in 2009 and 2008, respectively. Year-to-date sales volumes averaged 89,000 barrels per day in 2009 versus an average of 98,000 barrels per day for the first half of 2008. Sales volumes for 2009 were primarily impacted by the turnaround activities, circulation issues in Coker 8-1, reliability issues in mining and upgrading operations, and by constrained bitumen production during the first quarter. Sales volumes in 2008 were impacted by the disruption of several operating units in January, the scheduled turnaround of Coker 8-1 in the second quarter, 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 primarily due to the decrease in commodity prices.



Operating Costs

Three Months Ended Six Months Ended
June 30 June 30
2009(1) 2008(1) 2009(1) 2008(1)
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$/bbl $/bbl $/bbl $/bbl $/bbl $/bbl $/bbl $/bbl
Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO
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Bitumen
production(2) $ 26.97 $31.95 $ 21.68 $26.18 $ 23.74 $28.73 $ 20.23 $24.09
Internal
fuel
allocation (4) 2.64 3.13 4.45 5.37 2.45 2.97 4.10 4.89
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Total
produced
bitumen
costs 29.61 35.08 26.13 31.55 26.19 31.70 24.33 28.98

Upgrading
costs(3) 16.65 12.93 15.46 12.62
Less:
Internal
fuel
allocation
to bitumen(4) (3.13) (5.37) (2.97) (4.89)
Bitumen
purchases 0.95 2.95 0.57 2.27
----------------------------------------------------------------------------
Total Syncrude
operating costs 49.56 42.06 44.76 38.98
Canadian Oil
Sands' adjustments(5) 0.67 (0.14) (1.10) (0.08)
----------------------------------------------------------------------------

Total operating
costs 50.23 41.92 43.66 38.90
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(thousands
of barrels
per day) Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Syncrude
production
volumes(6) 245 206 327 265 290 240 323 266
----------------------------------------------------------------------------


(1) Information shown above allocates costs to bitumen production and upgrading based on deductibility for bitumen royalty purposes. In order for 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 Ended Six Months Ended
June 30 June 30
($/bbl of SCO) 2009 2008 2009 2008
----------------------------------------------------------------------------

Production costs 46.30 33.23 38.75 30.58
Purchased energy 3.93 8.69 4.91 8.32
----------------------------------------------------------------------------
Total operating costs 50.23 41.92 43.66 38.90
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(GJs/bbl of SCO)
----------------------------------------------------------------------------
Purchased energy consumption 1.27 0.93 1.14 1.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In the second quarter of 2009, operating costs were $345 million, averaging $50.23 per barrel, a decrease of $28 million from second quarter 2008 operating costs of $373 million. Year-to-date operating costs were $704 million in 2009, averaging $43.66 per barrel, an increase of $7 million over 2008 amounts.

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

- Additional maintenance activities at Syncrude on mining, upgrading, utilities and extraction facilities in 2009 relative to 2008 as a result of reliability issues;

- Higher turnaround costs in 2009 as a result of the comprehensive and extended turnaround of Coker 8-3 and related units compared with the turnaround of Coker 8-1 in 2008;

- Additional mining activities, including increased material movement in 2009 relative to 2008, in an effort to increase bitumen inventories and production;

- Inflationary pressures, including increased costs for contractors and wages for Syncrude staff;

- Lower energy costs as a result of a decline in natural gas prices to $4.31 per gigajoule ("GJ") in the first six months of 2009 compared with $8.27 per GJ in the same period of 2008; and

- A decrease in the value of purchased bitumen to $25 million in 2009 compared with $110 million during the same period of 2008.

On a per barrel basis, operating costs were higher in 2009 compared to 2008 as a result of lower production volumes. A significant portion of Syncrude's operating costs are fixed, and as such, any change in production volumes impacts per barrel operating costs.

Non-Production Costs

Non-production costs totaled $39 million and $16 million in the second quarters of 2009 and 2008, respectively. Year-to-date non-production costs totaled $72 million for 2009 and $33 million for 2008. The increase in non-production costs over 2008 was due to additional development activities undertaken by Syncrude with respect to mine train relocations, tailings initiatives, ESP fire repairs and planning for growth initiatives. 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 2009, Crown royalties decreased to $23 million, or $3.33 per barrel, from $178 million, or $19.94 per barrel, in the comparable 2008 quarter. Year-to-date Crown royalties decreased to $27 million, or $1.69 per barrel, in 2009 from $309 million, or $17.24 per barrel in 2008. The decrease in Crown royalties was primarily due to lower revenues and higher operating and capital costs. During the second quarter Syncrude became subject to royalties based on a net 25 per cent bitumen royalty rate for 2009 and recorded an additional $15 million, net to the Trust, of royalties in respect of upgrader growth capital recapture under its amended Royalty agreement. If Syncrude remains subject to a 25 per cent net royalty rate, additional royalties of $15 million, net to the Trust, will be payable in respect of upgrader growth capital recapture for the second half of 2009.

Pursuant to an agreement reached with the Alberta government during 2008, Syncrude's Crown royalties are now based on deemed bitumen revenues and allowed bitumen operating, non-production and capital costs.



Interest Expense, Net

Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Interest expense on long-term debt $ 25 $ 18 $ 46 $ 38
Interest income and other - (2) (1) (5)
----------------------------------------------------------------------------
Interest expense, net $ 25 $ 16 $ 45 $ 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The increase in interest expense on long-term debt was mainly due to the U.S. $500 million debt that was issued during the second quarter of 2009.



Depreciation, Depletion and Accretion Expense

Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Depreciation and depletion expense $ 78 $ 98 $ 180 $ 197
Accretion expense 3 4 7 7
----------------------------------------------------------------------------
$ 81 $ 102 $ 187 $ 204
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The decrease in depreciation and depletion ("D&D") expense 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.



Foreign Exchange (Gain) Loss

Three Months Ended Six Months Ended
June 30 June 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Unrealized foreign exchange loss
(gain) $ (83) $ (8) $ (52) $ 26
Realized foreign exchange loss (gain) 6 3 4 (5)
----------------------------------------------------------------------------
Total foreign exchange loss (gain) $ (77) $ (5) $ (48) $ 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Unrealized 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 unrealized FX gains in 2009 were due to a strengthening in the value 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. The unrealized FX gains and losses in 2008 were due to the change in the value of the Canadian dollar relative to the U.S. dollar to $0.98 U.S./Cdn at June 30, 2008 from $0.97 U.S./Cdn at March 31, 2008 and $1.01 U.S./Cdn at December 31, 2007.

Future Income Tax and Other

In the second quarter of 2009, a future income tax recovery of $23 million was recorded on the reduction of temporary differences versus a future income tax recovery of $10 million during 2008. On a year-to-date basis, a future income tax recovery of $113 million was recorded in 2009 versus a future income tax recovery of $24 million in 2008. In addition to the recovery recorded on the reduction of temporary differences between the 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. Temporary differences between accounting and tax values of Canadian Oil Sands' assets and liabilities decreased in both 2009 and 2008, primarily as a result of Unitholder distributions exceeding earnings before tax.

During the first quarter of 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. Based on current information, Canadian Oil Sands plans to convert into a corporate structure; however, we will retain the flow-through tax attributes of a trust structure until the beginning of 2011, unless circumstances arise that favour a faster transition.

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. We define expansion capital expenditures as 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 second quarter of 2009, capital expenditures totaled $139 million compared with expenditures of $54 million in the same quarter of 2008. The Syncrude Emissions Reduction ("SER") project accounted for $32 million and $21 million of the capital spent in the second quarters of 2009 and 2008, respectively, with the remaining 2009 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.

Year-to-date capital expenditures totaled $223 million in 2009 versus $101 million in 2008. The SER project accounted for $57 million and $38 million of the capital spent in 2009 and 2008, respectively, with the remaining expenditures relating 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 approximately $13.97 and $5.63 on a year-to-date basis 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.

Syncrude is undertaking the SER project 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 is $1.6 billion ($590 million net to the Trust) and the Trust's share of SER expenditures to date is approximately $238 million.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

Contractual obligations are summarized in the Trust's 2008 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 the first six months of 2009, Syncrude entered into new natural gas purchase commitments for a total of 62 million GJ's (23 million GJ's net to the Trust), 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 $4.50/GJ, the remaining commitment to the Trust for these contracts at June 30, 2009 is approximately $100 million.

Syncrude has also entered into nitrogen purchase commitments for an estimated total value of $57 million ($21 million net to the Trust) that will expire at the end of 2016.

During the second quarter of 2009, the Trust issued U.S. $500 million dollars of Senior unsecured notes. The notes have an annual interest rate of 7.75 per cent payable semi-annually and mature May 15, 2019.

With the exception of the items noted above and $18 million in respect of oil storage commitments entered into during the first quarter of 2009, there have been no significant changes to the Trust's contractual obligations and commitments from our 2008 year-end disclosure.



UNITHOLDER DISTRIBUTIONS
Three Months Ended Six Months Ended
June 30 June 30
----------------------------------------------------------------------------
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Cash from operating activities $ (44) $ 413 $ 6 $ 854

Net income $ 46 $ 497 $ 89 $ 795

Unitholder distributions $ 73 $ 481 $ 145 $ 841
----------------------------------------------------------------------------

Excess (shortfall) of cash from
operating activities over
Unitholder distributions $ (117) $ (68) $ (139) $ 13

Excess (shortfall) of net income
over Unitholder distributions $ (27) $ 16 $ (56) $ (46)
----------------------------------------------------------------------------


During the first half of 2009 Unitholder distributions exceeded cash from operating activities by $139 million. As a result, 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 second quarter Senior note issue funded the Trust's capital expenditures, debt repayment, reclamation trust fund contributions, and distributions.

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. Effective July 25, 2009, we suspended the DRIP as a result of strengthening crude oil prices, the U.S. $500 million Senior notes issue, and a view that the credit markets had stabilized. 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 operational performance, the Trust's 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 $42 million and $20 million on a year-to-date basis in 2009 and 2008, respectively.

The issuance of debt in the second quarter of 2009 significantly improved the Trust's liquidity position and its balance sheet remains strong. In addition, crude oil prices have improved during 2009 and Syncrude has mainly completed its 2009 planned maintenance program. These factors, and the resulting estimated production and revenue increases in the second half of 2009, provided the basis for distribution levels in excess of cash from operating activities and net income in the first six months of 2009; they also provide the foundation for the third quarter distribution.

On July 27, 2009 the Trust declared a quarterly distribution of $0.25 per Unit in respect of the third quarter of 2009 for a total distribution of $121 million. The distribution will be paid on August 28, 2009 to Unitholders of record on August 17, 2009. 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 relative to our target, 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. Further, the taxation of income trusts commencing January 1, 2011 will alter future cash from operating activities and distribution levels.



LIQUIDITY AND CAPITAL RESOURCES

June 30 December 31
($ millions) 2009 2008
----------------------------------------------------------------------------

Current portion of long-term debt (1) $ 290 $ -
Long-term debt 1,291 1,258
Cash and cash equivalents (366) (279)
----------------------------------------------------------------------------
Net debt (2) $ 1,215 $ 979
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholders' equity $ 3,917 $ 3,910
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total capitalization (3) $ 5,132 $ 4,889
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net debt to total capitalization (%) 24 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) U.S. $250 million Senior Notes mature on August 10, 2009
(2) Non-GAAP measure
(3) Net debt plus Unitholders' equity


During the second quarter of 2009, the Trust issued U.S. $500 million of Senior unsecured 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 as well as amounts drawn on the $800 million bank credit facility. The remaining proceeds will be used to repay U.S. $250 million of Senior Notes that mature in the third quarter of 2009, as well as for general corporate purposes. The next debt maturity subsequent to 2009 occurs in 2013.

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 will 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. Currently we have a net debt target of approximately $1.6 billion by the end of 2010; however, achievement of the net debt target will depend on actual operating results and economic conditions relative to expectations as well as distribution payments based on these expectations. As a result, actual net debt levels may vary from the net debt target 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 $13 billion with 484 million Units outstanding and a closing price of $27.79 per Unit on June 30, 2009.



Canadian Oil Sands Trust - Trading
Activity Second
Quarter June May April
2009 2009 2009 2009
----------------------------------------------------------------------------

Unit price
High $ 29.95 $ 29.85 $ 29.95 $ 29.33
Low $ 23.30 $ 25.17 $ 24.00 $ 23.30
Close $ 27.79 $ 27.79 $ 28.00 $ 24.64

Volume of Trust units traded
(millions) 109.4 35.7 41.4 32.3
Weighted average Trust units
outstanding (millions) 483.7 484.4 483.3 483.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------


FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of May 11, 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 August 17, 2009. 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.

FINANCIAL RISK MANAGEMENT

The Trust did not have any financial derivatives outstanding at June 30, 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 the second quarter of 2009 and 2008 and we do 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 Hedging

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 second quarter of 2009 or 2008, and we do 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, 2009 there was no floating interest rate debt outstanding and debt maturing during the third quarter is expected to be repaid with remaining proceeds from the Trust's debt issuance during the second quarter of 2009.

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 Senior note issue in the second quarter of 2009, the Trust's liquidity position has improved significantly.

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/purchased term deposits. The maximum exposure to any one customer or financial counterparty is controlled through a credit policy that limits exposure based on credit ratings.

At June 30, 2009, over 90 per cent of our customer accounts receivable balance was due from investment grade energy producers and refinery-based customers, and over 90 per cent of our cash and cash equivalents were invested in term deposits from a range of high-quality senior Canadian banks and U.S. Treasury bills. As of July 27, 2009, 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 the second quarter 2009 that are expected to have a material impact on the Trust.

The Trust is continuing with its conversion to international financial reporting standards ("IFRS"), which will replace Canadian GAAP starting in 2011. Assessments of the impacts of conversion to IFRS, including the adoption of potential IFRS standards under development that might impact the Trust, have not been finalized. The impacts to the consolidated financial statements on the adoption of IFRS will depend on the circumstances prevailing on January 1, 2011 as well as the accounting policy choices by Canadian Oil Sands.



2009 OUTLOOK

(millions of Canadian dollars, except
volume and per barrel amounts) July 27, 2009 April 29, 2009
----------------------------------------------------------------------------

Syncrude production (MMbbls) 104 109
Canadian Oil Sands Sales (MMbbls) 38.2 40.0
Revenues, net of crude oil purchases and
transportation 2,360 2,328
Operating costs 1,338 1,340
Operating costs per barrel 35.01 33.46
Crown royalties 100 103
Capital expenditures 460 453
Cash from operating activities 519 586

Business environment assumptions
West Texas Intermediate (US$/bbl) $ 55 $ 50
Premium (Discount) to average C$ WTI
prices (C$/bbl) $ (1.50) $ (2.50)
Foreign exchange rate (US$/Cdn$) $ 0.87 $ 0.83
AECO natural gas (Cdn$/GJ) $ 4.50 $ 5.00


On July 27, 2009, the Trust revised its outlook and lowered its 2009 Syncrude production range to 100 to 106 million barrels with an estimate of 104 million barrels.

The revised production estimate incorporates actual volumes for the first half of 2009 and an allowance for unplanned maintenance work in the second half of the year. With the planned 2009 maintenance program substantially complete, the Trust expects production volumes and per barrel operating costs in the second half of 2009 to improve relative to the first half of the year. To achieve the outlook production, we are estimating that Syncrude will average approximately 326,000 barrels per day in the last half of 2009, which can be achieved with stable operations. While higher daily production rates are possible, Syncrude continues to focus resources to expose minable ore and address reliability issues. In addition, while the next coker turnaround is scheduled in 2010, circulation issues on Coker 8-1 during the second quarter suggest a heightened risk of advancing the turnaround into 2009; if this occurs, our 2009 production estimate would fall by approximately three million barrels.

The outlook has also been revised to reflect results to date, as well as current commodity price and foreign exchange rate estimates. For 2009, we are assuming an average U.S.$55 per barrel WTI crude oil price, an $0.87 U.S./Cdn foreign exchange rate, and a $1.50 per barrel SCO discount to Cdn $WTI, resulting in estimated revenues of $62 per barrel for the year.



July 27, 2009 (2) April 29, 2009 (3)
Cdn $ US$ Per Cdn $ US$ Per
2009 Cost Estimates (1) Per Bbl Bbl Per Bbl Bbl
----------------------------------------------------------------------------
Syncrude Costs
Operating expenses $ 35.01 $ 30.46 $ 33.46 $ 27.60
Non-production costs $ 3.60 $ 3.13 $ 3.45 $ 2.85
---------------------------------------
$ 38.61 $ 33.59 $ 36.91 $ 30.45
Capital expenditures $ 12.05 $ 10.48 $ 11.31 $ 9.33
---------------------------------------
Total Syncrude costs $ 50.66 $ 44.07 $ 48.22 $ 39.78
---------------------------------------
Canadian Oil Sands Costs
Interest $ 2.43 $ 2.11 $ 1.91 $ 1.58
Administration, Insurance and
Other $ 1.36 $ 1.18 $ 0.71 $ 0.59
---------------------------------------
Total Canadian Oil Sands Costs $ 3.79 $ 3.30 $ 2.62 $ 2.16
---------------------------------------

Total Syncrude and Canadian Oil
Sands Costs $ 54.45 $ 47.37 $ 50.84 $ 41.94
Crown Royalties $ 2.63 $ 2.29 $ 2.57 $ 2.12
---------------------------------------
Total Costs $ 57.08 $ 49.66 $ 53.41 $ 44.06
---------------------------------------
---------------------------------------

(1) This table updates the cost estimate outlook section provided in the
Trust's 2008 annual MD&A.
(2) The July 27, 2009 per barrel cost estimates are based on 104 milllion
barrels of Syncrude production and an $0.87 U.S./Cdn exchange rate, as
per the July Outlook.
(3) The April 29, 2009 per barrel cost estimates are based on 109 milllion
barrels of Syncrude production and an $0.825 U.S./Cdn exchange rate, as
per the April Outlook.


Revised annual operating costs are estimated at $35 per barrel, consisting of $30.40 per barrel of production costs and $4.60 per barrel of purchased energy costs. Our revised estimate of the Trust's operating costs of $1,338 million, or $35 per barrel, reflects additional maintenance and turnaround costs, offset by lower purchased energy costs. The per barrel figures also reflect the impact of the five million barrel reduction in estimated Syncrude production. When combined with non-production costs and capital expenditures, total Syncrude costs per our 2009 outlook are estimated at $51 per barrel. Canadian Oil Sands expects to incur an additional $3.80 per barrel of costs to cover interest expense, administration, and insurance, resulting in 2009 outlook total costs of approximately $54.50 per barrel for Syncrude and Canadian Oil Sands. Crown royalties are estimated at $2.63 per barrel, reflecting payment of net revenue royalties and upgrader growth recapture.

Based on the above assumptions, our estimate of 2009 cash from operating activities is $519 million or $1.07 per Unit. After deducting estimated 2009 capital expenditures of $460 million, we are estimating $59 million of remaining cash from operating activities, or $0.12 per Unit.

Distributions paid in 2009 are expected to be 100 per cent taxable as other income. The actual taxability of the distributions will be determined and reported to Unitholders prior to the end of the first quarter of 2010.

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.



2009 Outlook Sensitivity Analysis (July 27, 2009)
Cash from Operating Activities
Increase
Annual
Variable (1) Sensitivity $ millions $/Trust unit
----------------------------------------------------------------------------

Syncrude operating costs decrease C$1.00/bbl 32 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 34 0.07
Canadian dollar weakening US$0.01/C$ 20 0.04
AECO natural gas price decrease C$0.50/GJ 16 0.03

(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) 2009 2008 2009 2008
----------------------------------------------------------------------------

Revenues $ 526 $ 1,286 $ 1,075 $ 2,312
----------------------------------------------------------------------------

Expenses:
Operating 345 373 704 697
Non-production 39 16 72 33
Crude oil purchases and
transportation expense 59 109 96 228
Crown royalties 23 178 27 309
Administration 6 9 12 13
Insurance 2 1 4 3
Interest, net (Note 8) 25 16 45 33
Depreciation, depletion and accretion 81 102 187 204
Foreign exchange loss (gain) (77) (5) (48) 21
----------------------------------------------------------------------------
503 799 1,099 1,541
----------------------------------------------------------------------------
Earnings before taxes 23 487 (24) 771
Future income tax expense
(recovery) and other (Note 9) (23) (10) (113) (24)
----------------------------------------------------------------------------
Net income 46 497 89 795
Other comprehensive loss, net of
income taxes
Reclassification of derivative
gains to net income - - (1) (1)
----------------------------------------------------------------------------
Comprehensive income $ 46 $ 497 $ 88 $ 794
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average Trust Units (millions) 484 481 483 480
Trust Units, end of period (millions) 484 482 484 482

Net income per Trust Unit:
Basic $ 0.10 $ 1.04 $ 0.18 $ 1.66
Diluted $ 0.10 $ 1.04 $ 0.18 $ 1.65

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) 2009 2008 2009 2008
----------------------------------------------------------------------------
Retained earnings
Balance, beginning of period $ 1,333 $ 1,581 $ 1,362 $ 1,643
Net income 46 497 89 795
Unitholder distributions (Note 11) (73) (481) (145) (841)
----------------------------------------------------------------------------
Balance, end of period 1,306 1,597 1,306 1,597
----------------------------------------------------------------------------
Accumulated other comprehensive income
Balance, beginning of period 20 23 21 24
Other comprehensive loss - - (1) (1)
----------------------------------------------------------------------------
Balance, end of period 20 23 20 23
----------------------------------------------------------------------------
Unitholders' capital
Balance, beginning of period 2,557 2,500 2,524 2,500
Issuance of Trust Units (Note 4) 30 24 63 24
----------------------------------------------------------------------------
Balance, end of period 2,587 2,524 2,587 2,524
----------------------------------------------------------------------------
Contributed surplus
Balance, beginning of period 4 5 3 5
Exercise of employee stock options - (3) - (3)
Stock-based compensation - 1 1 1
----------------------------------------------------------------------------
Balance, end of period 4 3 4 3
----------------------------------------------------------------------------
Total Unitholders' equity $ 3,917 $ 4,147 $ 3,917 $ 4,147
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements


CONSOLIDATED BALANCE SHEETS AS AT
(unaudited)
June 30 December 31
($ millions) 2009 2008
----------------------------------------------------------------------------

ASSETS
Current assets:
Cash and cash equivalents $ 366 $ 279
Accounts receivable 254 184
Inventories 117 93
Prepaid expenses 1 5
----------------------------------------------------------------------------
738 561

Property, plant and equipment, net 6,314 6,277
Goodwill 52 52
Reclamation trust 45 43
----------------------------------------------------------------------------

$ 7,149 $ 6,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 297 $ 284
Current portion of long-term debt (Note 7) 290 -
Current portion of employee future benefits 17 17
----------------------------------------------------------------------------
604 301
Employee future benefits and other liabilities 100 99
Long-term debt (Note 7) 1,291 1,258
Asset retirement obligation 222 235
Future income taxes 1,015 1,130
----------------------------------------------------------------------------
3,232 3,023

Unitholders' equity 3,917 3,910
----------------------------------------------------------------------------

$ 7,149 $ 6,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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) 2009 2008 2009 2008
----------------------------------------------------------------------------

Cash from (used in) operating
activities
Net income $ 46 $ 497 $ 89 $ 795
Items not requiring outlay of cash:
Depreciation, depletion and accretion 81 102 187 204
Unrealized foreign exchange on
long-term debt (83) (8) (52) 26
Future income tax expense (recovery) (23) (10) (113) (24)
Net change in deferred items and
other 2 (6) (19) (11)
----------------------------------------------------------------------------
23 575 92 990
Change in non-cash working capital (67) (162) (86) (136)
----------------------------------------------------------------------------
Cash from (used in) operating
activities (44) 413 6 854
----------------------------------------------------------------------------

Cash from (used in) financing
activities
Issuance of Senior Notes (Note 7) 574 - 574 -
Repayment of medium term and Senior
Notes (Note 7) (200) (150) (200) (150)
Net drawdown (repayment) of bank
credit facilities (25) - - (16)
Unitholder distributions (Note 11) (43) (481) (82) (841)
Issuance of Trust Units (Note 4) - 21 - 21
----------------------------------------------------------------------------
Cash from (used) in financing
activities 306 (610) 292 (986)
----------------------------------------------------------------------------

Cash from (used in) investing
activities
Capital expenditures (139) (54) (223) (101)
Reclamation trust funding (1) (2) (2) (3)
Change in non-cash working capital 3 - 14 -
----------------------------------------------------------------------------
Cash used in investing activities (137) (56) (211) (104)
----------------------------------------------------------------------------

Increase (decrease) in cash and cash
equivalents 125 (253) 87 (236)

Cash and cash equivalents at
beginning of period 241 285 279 268
----------------------------------------------------------------------------

Cash and cash equivalents at end of
period $ 366 $ 32 $ 366 $ 32
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash and cash equivalents consist of:
Cash $ 6 $ 3
Short-term investments 360 29
----------------------------------------------------------------------------
$ 366 $ 32
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information (Note 13)

See Notes to Unaudited Consolidated Financial Statements



NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 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 six months ended June 30, 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 six months ended June 30, 2008, approximately 2.1 million Trust Units were issued for $24 million on the exercise of employee stock options.

5) 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 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, 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 Six Months Ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------

Defined benefit plans:
Pension benefits $ 9 $ 7 $ 17 $ 15
Other benefit plans 1 1 3 2
----------------------------------------------------------------------------
$ 10 $ 8 $ 20 $ 17

Defined contribution plans - - 1 1
----------------------------------------------------------------------------
Total benefit cost $ 10 $ 8 $ 21 $ 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6) BANK CREDIT FACILITIES

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


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 $40 million extendible revolving term facility is a 364-day facility with a one-year term out, expiring April 22, 2010. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at June 30, 2009, no amounts were drawn on this facility. ($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 June 30, 2009.

c) The $800 million operating facility is a multi-year facility, expiring April 27, 2012. Amounts borrowed through this facility bear interest at a floating rate based on either prime interest rates or bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at June 30, 2009, no amounts were drawn against this facility ($Nil - December 31, 2008).

7) 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.

The Trust repaid $200 million of 5.55 per cent Medium Term Notes that matured on June 29, 2009.

During the second quarter of 2009, the Trust reclassified U.S. $250 million of Senior Notes from long-term debt to current liabilities as the Trust expects to repay the debt in the third quarter of 2009 from cash.



8) INTEREST, NET

Three Months Ended Six Months Ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------

Interest expense on
long-term debt $ 25 $ 18 $ 46 $ 38
Interest income and other - (2) (1) (5)
----------------------------------------------------------------------------
Interest expense, net $ 25 $ 16 $ 45 $ 33
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9) 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.

10) STOCK BASED COMPENSATION

During 2009, 482,517 options were issued by the Trust to employees with an average exercise price of $19.70 pursuant to the Trust's Unit Incentive Option Plan. The options have an estimated weighted-average fair value of $4.54 per option.

11) 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 Six Months Ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash from operating activities $ (44) $ 413 $ 6 $ 854
Add (Deduct):
Capital expenditures (139) (54) (223) (101)
Change in non-cash working
capital (1) 3 - 14 -
Reclamation trust funding (1) (2) (2) (3)
Change in cash and cash
equivalents and financing,
net (2) 254 124 350 91
----------------------------------------------------------------------------
Unitholder distributions $ 73 $ 481 $ 145 $ 841
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholder distributions per
Trust Unit $ 0.15 $ 1.00 $ 0.30 $ 1.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 the first half of 2009 were funded by cash payments of $82 million and by the issuance of 2.9 million Trust Units for $63 million.

12) COMMITMENTS

During the first six months of 2009, Syncrude entered into new natural gas purchase commitments for a total of 62 million ("GJ's") (23 million GJ's net to the Trust), 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 $4.50/GJ, the remaining commitment to the Trust for these contracts at June 30, 2009 is approximately $100 million.

Syncrude has also entered into nitrogen commitments for an estimated total value of $57 million ($21 million net to the Trust) that will expire at the end of 2016.

During the first six months of 2009 Canadian Oil Sands entered into oil storage commitments totalling $18 million which expire in 2013.



13) SUPPLEMENTARY INFORMATION

Three Months Ended Six Months Ended
June 30 June 30
2009 2008 2009 2008
----------------------------------------------------------------------------

Income tax paid $ - $ - - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 10 $ 13 41 $ 38
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Canadian Oil Sands Limited
Marcel Coutu
President & Chief Executive Officer

Units Listed - Symbol: COS.UN
Toronto Stock Exchange


Canadian Oil Sands Trust
2500 First Canadian Centre
350 - 7 Avenue S.W.
Calgary, Alberta T2P 3N9
Ph: (403) 218-6200
Fax: (403) 218-6201


Contact Information