Canadian Oil Sands Trust
TSX : COS.UN

Canadian Oil Sands Trust

April 29, 2009 23:59 ET

Canadian Oil Sands Trust Announces 2009 First Quarter Results

CALGARY, ALBERTA--(Marketwire - April 29, 2009) -

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 2009 cash from operating activities of $50 million ($0.10 per Unit) compared with $441 million ($0.92 per Unit) in the same quarter in 2008. Net income for the quarter was $43 million ($0.09 per Unit) compared with $298 million ($0.62 per Unit) for the first quarter of 2008. The decrease in cash from operating activities and net income in 2009 reflects the significant decline in crude oil prices with average West Texas Intermediate ("WTI") prices down 56 per cent from the first quarter of 2008. The financial results also reflect higher operating costs net of lower Crown royalties. Higher future income tax recoveries were recorded in the 2009 first quarter, increasing net income, while changes in non-cash working capital reduced cash from operating activities compared with the 2008 first quarter.

"We experienced a difficult first quarter with very weak crude oil prices and more than the usual winter challenges," said Marcel Coutu, President and Chief Executive Officer. "We expect production to improve as constraints in bitumen supply are gradually addressed and we complete the turnaround work that began in the first quarter, positioning us for a much stronger second half of the year. Our financial plan during this economic downturn remains on track with a focus on maintaining a healthy balance sheet, and more importantly, a solid liquidity position."

Mr. Coutu added: "I am cautiously optimistic that crude oil prices are now on a recovering trend. Despite a global recession that may extend for a few more quarters, an eventual oil price recovery may be accelerated by natural production declines due to lower industry reinvestment in producing fields and outright production cuts by OPEC nations."

The Trust has declared a distribution of $0.15 per Unit for the second quarter of 2009, unchanged from the previous quarter. The distribution is payable on May 29, 2009 to Unitholders of record on May 11, 2009. Eligible Unitholders can elect to participate in the Trust's Premium Distribution, Distribution Re-Investment and Optional Unit Purchase Plan ("DRIP") by contacting their financial advisor or Computershare Trust Company.

During the first quarter of 2009, sales volumes averaged about 103,000 barrels per day as compared to 99,000 barrels per day for the first quarter of 2008. Constraints in bitumen supply and unplanned maintenance reduced production in the first quarter of both years. In mid-March 2009, Syncrude began turnaround work on Coker 8-3. The turnaround was scheduled to commence early in the second quarter, and its advancement also impacted first quarter volumes.

Operating costs in the first quarter of 2009 were $38.78 per barrel compared with $35.93 per barrel in the 2008 period, reflecting a $35 million increase in total operating costs in the first quarter of 2009 over the first quarter of 2008. The increase was primarily due to higher maintenance costs, higher labour costs and additional mining activity in 2009 relative to 2008.

The Trust's 2009 Outlook estimates production of 40 million barrels (109,500 barrels per day), operating costs of approximately $33.50 per barrel, and capital expenditures totaling $453 million. The estimate for production was reduced in March 2009 to reflect the lower than estimated first quarter production and the early turnaround of Coker 8-3, which delayed a sulphur plant turnaround and resulted in an extension of the overall turnaround schedule. Based on the Trust's assumption of WTI crude oil averaging U.S. $50 per barrel in 2009, together with our other assumptions outlined in our Outlook, we are estimating cash from operating activities of $1.21 per Unit in 2009.

More information on the Trust's Outlook, including detailed analysis of 2009 cost estimates, is provided in the MD&A section of this report and the April 29, 2009 guidance document, which is available on the Trust's 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, 2009 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/default.aspx. An archive of the Web cast will be available approximately one hour following the meeting.



CANADIAN OIL SANDS TRUST
Highlights

Three Months Ended
March 31
(millions of Canadian dollars, except
Trust unit and volume amounts) 2009 2008
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Net Income $ 43 $ 298
Per Trust unit- Basic $ 0.09 $ 0.62
Per Trust unit- Diluted $ 0.09 $ 0.62

Cash from Operating Activities $ 50 $ 441
Per Trust unit $ 0.10 $ 0.92

Unitholder Distributions $ 72 $ 360
Per Trust unit $ 0.15 $ 0.75

Sales Volumes(1)
Total (MMbbls) 9.3 9.0
Daily average (bbls) 102,825 99,181

Operating Costs per barrel $ 38.78 $ 35.93

Net Realized SCO Selling Price per barrel
Realized SCO selling price before hedging $ 55.22 $ 100.31
Currency hedging gains 0.10 0.10
Net Realized SCO Selling Price per barrel $ 55.32 $ 100.41

West Texas Intermediate (average
$US per barrel)(2) $ 43.31 $ 97.82
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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.



The following Management's Discussion and Analysis ("MD&A") was prepared as of April 29, 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 months ended March 31, 2009 and March 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 web site 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 expected structure to be assumed given the Federal government's tax changes effective in 2011; the impact that continued credit market turmoil and low crude prices may have on distributions; future distributions and any increase or decrease from current payment amounts; the preservation of financial flexibility and the ability to meet operating and capital costs from the assumed cash from operating activities in 2009; future royalty rates under the New Royalty Framework post-2015; the expected impact on the Trust and distributions and the belief that debt covenants will not influence the Trust's liquidity in the foreseeable future or limit the Trust's ability to pay distributions; expectations regarding the sustainability of operations at certain levels of WTI prices; plans regarding refinancing of the 2009 debt maturities and views on future credit markets, accessibility of capital markets, and availability of financing and the impact on distributions; 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 expectation that no crude oil hedges will be entered into in the future; 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; the expected production, revenues and operating costs for 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 first quarter of 2009, crude oil production from the Syncrude Joint Venture ("Syncrude") totaled 24.6 million barrels, or 274,000 barrels per day, compared with 24.3 million barrels, or 267,000 barrels per day, during the same period of 2008. Net to the Trust, production totaled 9.0 million barrels in the first quarter of 2009 compared with 8.9 million barrels in 2008, based on our 36.74 per cent working interest.

Production volumes in the first quarter of 2009 were impacted by constraints in bitumen production, which were caused by reliability and mine productivity issues, and by the turnaround of Coker 8-3 that began mid-March. Bitumen constraints, and the disruption of several operating units in January 2008, also reduced SCO production during the first quarter of 200 8.

Operating costs were $38.78 per barrel in 2009 versus $35.93 per barrel in the first quarter of 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

In the first quarter of 2009, the global recession, volatile commodity prices and foreign exchange ("FX") rates impacted the Trust. During this period, U.S. dollar West Texas Intermediate ("WTI") prices fluctuated between $33.98 per barrel and $54.34 per barrel and the Canadian to U.S. exchange rate fluctuated between $0.77 U.S./Cdn and $0.85 U.S./Cdn. In general, commodity prices have strengthened during the first quarter with U.S. dollar WTI prices averaging $48 per barrel in March 2009 versus $42 per barrel in January 2009.

As a result of weak economic conditions, a number of crude oil projects have been delayed or postponed, including oil sands projects in the Fort McMurray region. It is still too early to determine if there will be any long term reductions in costs at Syncrude resulting from lower industry activity as a number of Syncrude's contracts are for multiple years and were entered into prior to the economic slowdown. Generally, there is less demand for workers and contractors in the current economic environment, alleviating somewhat the challenge of finding and retaining qualified staff; however, it is still too early to determine the potential impact of this on Syncrude.

Credit markets appear to have stabilized relative to the fourth quarter of 2008 with many entities able to access capital during the first quarter of 2009, albeit at a higher cost than recent years.



SUMMARY OF QUARTERLY RESULTS

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

Net income (loss) $ 43 $ 124 $ 604 $ 497
Per Trust Unit, Basic $ 0.09 $ 0.26 $ 1.25 $ 1.04
Per Trust Unit,
Diluted $ 0.09 $ 0.26 $ 1.25 $ 1.04

Cash from operating
activities $ 50 $ 466 $ 921 $ 413
Per Trust Unit(2) $ 0.10 $ 0.97 $ 1.91 $ 0.86

Unitholder distributions $ 39 $ 361 $ 602 $ 481
Per Trust Unit $ 0.15 $ 0.75 $ 1.25 $ 1.00

Daily average sales
volumes (bbls)(3) 102,825 110,197 116,656 97,744

Net realized SCO selling
price ($/bbl)(4) $ 55.32 $ 69.40 $ 127.55 $ 131.32

Operating costs
($/bbl)(5) $ 38.78 $ 32.10 $ 32.15 $ 41.92

Purchased natural gas
price ($/GJ) $ 4.96 $ 6.41 $ 7.86 $ 9.38

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

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




($ millions, except per
Trust Unit and volume 2008 2007
amounts) Q1 Q4 Q3 Q2
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Revenues(1) $ 907 $ 950 $ 936 $ 690

Net income (loss) $ 298 $ 515 $ 361 $ (395)
Per Trust Unit, Basic $ 0.62 $ 1.07 $ 0.75 $ (0.82)
Per Trust Unit,
Diluted $ 0.62 $ 1.07 $ 0.75 $ (0.82)

Cash from operating
activities $ 441 $ 367 $ 484 $ 324
Per Trust Unit(2) $ 0.92 $ 0.77 $ 1.01 $ 0.68

Unitholder distributions $ 360 $ 264 $ 192 $ 191
Per Trust Unit $ 0.75 $ 0.55 $ 0.40 $ 0.40

Daily average sales
volumes (bbls)(3) 99,181 116,368 124,904 98,720

Net realized SCO selling
price ($/bbl)(4) $ 100.41 $ 88.73 $ 81.48 $ 76.81

Operating costs
($/bbl)(5) $ 35.93 $ 27.38 $ 20.84 $ 30.13

Purchased natural gas
price ($/GJ) $ 7.30 $ 5.84 $ 4.99 $ 6.78

West Texas Intermediate
(avg. US$/bbl)(6) $ 97.82 $ 90.50 $ 75.15 $ 65.02

Foreign exchange rates
(US$/Cdn$):
Average $ 1.00 $ 1.02 $ 0.96 $ 0.91
Quarter - end $ 0.97 $ 1.01 $ 1.00 $ 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.
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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;

- The substantive enactment of income tax legislation in June 2007 resulted in an additional future income tax expense of $701 million in the second quarter of 2007;

- 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;

- Tax rate reductions substantively enacted in the first quarter of 2009 and in the fourth and second quarters of 2007 resulted in future income tax recoveries of $63 million, $153 million and $38 million in
each quarter, respectively; and

- Planned and unplanned maintenance activities have impacted quarterly production volumes, sales revenues and operating costs.

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 is also 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. Maintenance and turnaround activities are typically scheduled to avoid the winter months, however the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages may occur.

Accordingly, production levels may not display reliable seasonality patterns or trends.

Maintenance and turnaround costs are expensed in the period incurred and can lead to significant increases in operating costs and reductions in production in those periods. 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.

REVIEW OF FINANCIAL RESULTS

In the first quarter of 2009, net income totaled $43 million, or $0.09 per Unit, compared with net income of $298 million, or $0.62 per Unit, recorded in 2008. The decrease in net income was primarily the result of lower revenues and higher operating costs, net of lower Crown royalties and higher future income tax recoveries.

Cash from operating activities decreased to $50 million for the first quarter of 2009 versus $441 million for the first quarter of 2008. The change in quarter-over-quarter cash from operating activities was due to the decreased revenues, reflecting lower commodity prices, higher operating costs and changes in non-cash working capital partially offset by lower Crown royalties.

Changes in non-cash working capital decreased cash from operating activities by $19 million in the first quarter of 2009, primarily as a result of higher accounts receivable at March 31, 2009 versus December 31, 2008. The increase in accounts receivable reflected higher oil prices in March 2009 versus December 2008, partially offset by lower sales volumes. In the first quarter of 2008, changes in non-cash working capital increased cash from operating activities by $26 million, primarily as a result of higher accounts payable at March 31, 2008 relative to December 31, 2007.

Non-cash working capital and changes therein can vary 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, the timing of capital expenditures, and inventory fluctuations.



Net Income per Barrel

Three Months Ended
March 31
($ per bbl)(1) 2009 2008 Variance
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Revenues after crude oil purchases
and transportation expense 55.32 100.49 (45.17)
Operating costs (38.78) (35.93) (2.85)
Crown royalties (0.48) (14.57) 14.09
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16.06 49.99 (33.93)
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Non-production costs (3.57) (1.87) (1.70)
Administration and insurance (0.82) (0.73) (0.09)
Interest, net (2.14) (1.83) (0.31)
Depletion, depreciation and accretion (11.43) (11.33) (0.10)
Foreign exchange gain (loss) (3.18) (2.83) (0.35)
Future income tax (expense)
recovery and other 9.68 1.55 8.13
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(11.46) (17.04) 5.58
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Net income per barrel 4.60 32.95 (28.35)
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Sales volumes (MMbbls)(2) 9.3 9.0 0.3
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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


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.

Revenues after Crude Oil Purchases and Transportation Expense



Three Months Ended
March 31
($ millions) 2009 2008 Variance
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Sales revenue(1) $ 548 $ 1,025 $ (477)
Crude oil purchases (29) (109) 80
Transportation expense (8) (10) 2
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511 906 (395)

Currency hedging gains(1) 1 1 -
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$ 512 $ 907 $ (395)
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Sales volumes (MMbbls)(2) 9.3 9.0 0.3
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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) $ 55.22 $ 100.31 $ (45.09)
Currency hedging gains 0.10 $ 0.10 -
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Net realized SCO selling price $ 55.32 $ 100.41 $ (45.09)
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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 first quarter sales revenue for 2009 versus 2008 was due to a lower realized selling price for our synthetic crude oil ("SCO"), reflecting a significant decline in WTI prices and a modest decrease in the price differential to Canadian dollar WTI. During the first quarter of 2009, WTI prices averaged U.S. $43.31 per barrel compared to U.S. $97.82 per barrel for the first quarter of 2008. The impact of the lower U.S. dollar WTI prices in the first quarter 2009 was offset somewhat by a weaker Canadian dollar, which averaged $0.80 U.S./Cdn for the first quarter of 2009 versus $1.00 U.S./Cdn for the first quarter of 2008.

The Trust's SCO price is affected by the premium or discount realized relative to Canadian dollar WTI (the "differential"). In the first quarter of 2009, the Trust's SCO realized a weighted-average premium of $1.43 per barrel versus a premium of $1.72 per barrel for 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 first quarter averaged 103,000 barrels per day and 99,000 barrels per day in 2009 and 2008, respectively. Sales volumes during the first quarter of 2009 were impacted by the coker turnaround and by constrained bitumen production. First quarter 2008 sales volumes were impacted by the disruption of several operating units in January 2008 and bitumen production constraints.

From time to time the Trust purchases crude oil from third parties. These purchases support the sales of internally produced SCO in ways such as helping to fulfill sales commitments with customers when there are shortfalls in Syncrude's production and to facilitate certain transportation arrangements and operations. The decrease in value of crude oil purchases during the first quarter of 2009 was due to the decrease in commodity prices and a decrease in purchased volumes.



Operating Costs
Three Months Ended
March 31
2009(1) 2008(1)
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$/bbl $/bbl $/bbl $/bbl
Bitumen SCO Bitumen SCO
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Bitumen production(2) $ 21.37 $ 26.28 $ 18.75 $ 22.01
Internal fuel allocation(4) 2.32 2.85 3.75 4.40
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Total produced bitumen costs 23.69 29.13 22.50 26.41

Upgrading Costs(3) 14.55 12.31
Less: Internal fuel
allocation to bitumen(4) (2.85) (4.40)
Bitumen purchases 0.28 1.58
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Total Syncrude
operating costs 41.11 35.90
Canadian Oil Sands'
adjustments(5) (2.33) 0.03
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Total operating costs 38.78 35.93
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(thousands of barrels per day) Bitumen SCO Bitumen SCO
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Syncrude production volumes(6) 337 274 313 267
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(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's operating costs
excluding bitumen 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,
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
March 31
($/bbl of SCO) 2009 2008
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Production costs 33.12 27.97
Purchased energy 5.66 7.96
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Total operating costs 38.78 35.93
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(GJs/bbl of SCO)
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Purchased energy consumption 1.14 1.09
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In the first quarter of 2009, operating costs were $359 million, averaging $38.78 per barrel, an increase of $35 million over first quarter 2008 operating costs of $324 million. The increase in year-over-year operating costs was primarily due to the following:

- Higher maintenance costs in 2009 relative to 2008 in respect of mining activities, the turnaround of Coker 8-3, and repairs to the electrostatic precipitator units damaged by the December 2007 fire;

- Increased costs for contractors and wages for Syncrude staff as a result of salary increases and contract settlements, and an increase in Syncrude staff levels relative to the first quarter of 2008; and
- Additional mining activities to increase bitumen production in the first quarter of 2009 relative to 2008. Syncrude also increased its use of contracted equipment and operators to supplement its own material movement activities in 2009.

The increase in operating costs was partially offset by:

- Lower energy costs in 2009 relative to 2008 as a result of decreases in natural gas prices; and

- A decrease in the cost of purchased bitumen in 2009 relative to 2008.

Non-Production Costs

Non-production costs totaled $33 million and $17 million in the first quarters of 2009 and 2008, respectively. The increase in non-production costs over 2008 was due to additional development activities at Syncrude. 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 2009, Crown royalties decreased to $4 million, or $0.48 per barrel, from $131 million, or $14.57 per barrel, in the comparable 2008 quarter. The decrease in Crown royalties was primarily due to lower revenues, which also resulted in Syncrude paying royalties based on the minimum one per cent bitumen royalty rate for the first quarter of 2009. While in a minimum royalty, Syncrude is not subject to additional royalties in respect of upgrader growth capital recapture. Should Syncrude resume paying royalty on a net revenue basis, royalties of approximately $30 million will be payable in 2009 in respect of upgrader growth capital recapture in addition to the net revenue royalty payments.

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



Interest Expense, Net
Three Months Ended
March 31
2009 2008
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Interest expense on long-term debt $ 21 $ 20
Interest income and other (1) (3)
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Interest expense, net $ 20 $ 17
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Interest expense on long-term debt was similar in both years as a result
of similar levels of long-term debt outstanding.

Depreciation, Depletion and Accretion Expense


Three Months Ended
March 31
($ millions) 2009 2008
-------------------------------------------------------------------------
Depreciation and depletion expense $ 102 $ 99
Accretion expense 4 3
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$ 106 $ 102
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The increase in the depreciation and depletion ("D&D") expense was due to increased production volumes and 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 Loss

Three Months Ended
March 31
($ millions) 2009 2008
-------------------------------------------------------------------------
Unrealized foreign exchange loss (gain) $ 31 $ 34
Realized foreign exchange loss (gain) (2) (8)
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Total foreign exchange loss (gain) $ 29 $ 26
-------------------------------------------------------------------------
-------------------------------------------------------------------------


Unrealized foreign exchange ("FX") 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. During 2009, the unrealized FX loss resulted from 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. The unrealized FX loss in 2008 was due to the weakening of the Canadian dollar to $0.97 U.S./Cdn at March 31, 2008 from $1.01 U.S./Cdn at December 31, 2007.

Future Income Tax and Other

In the first quarter of 2009, a future income tax recovery of $63 million resulted from the substantive enactment of tax rate reductions applicable to the Trust. In addition, a future income tax recovery of $27 million was recorded in the first quarter of 2009 on the decrease of temporary differences between the accounting and tax values of Canadian Oil Sands' assets and liabilities. In the first quarter of 2008 a future income tax recovery of $14 million was recorded on the reduction of temporary differences. Temporary differences 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 will likely convert into a corporation. However, we plan to retain the flow-through tax attributes of a trust structure until 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 first quarter of 2009, capital expenditures totaled $84 million compared with expenditures of $47 million in the same quarter of 2008. The Syncrude Emissions Reduction ("SER") project accounted for $25 million and $17 million of the capital spent in the first quarters of 2009 and 2008, respectively. The remaining amounts in each quarter pertain to other sustaining capital activities including replacement of trucks and shovels as well as infrastructure projects. Sustaining capital expenditures on a per barrel basis were approximately $9.10 and $5.25 in each of the first quarters of 2009 and 2008, respectively. 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 $206 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 quarter of 2009, Syncrude entered into new natural gas commitments for a total of 46 million gigajoules ("GJ") (17 million GJ's net to the Trust) that will expire December 31, 2011. The value of this commitment will fluctuate with changes to natural gas prices. Based on an estimated AECO price of $5.00/GJ, per the Trusts' revised guidance dated April 29, 2009, the additional commitment to the Trust is approximately $85 million.

With the exception of the Trust's share of new natural gas purchase commitments and $18 million in respect of oil storage commitments, 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
March 31
-------------------------------------------------------------------------
($ millions) 2009 2008
-------------------------------------------------------------------------
Cash from operating activities $ 50 $ 441

Net income $ 43 $ 298

Unitholder distributions $ 72 $ 360
-------------------------------------------------------------------------

Excess (shortfall) of cash
from operating activities
over Unitholder distributions $ (22) $ 81

Excess (shortfall) of net income
over Unitholder distributions $ (29) $ (62)
-------------------------------------------------------------------------


During the first quarter of 2009, cash from operating activities, opening cash balances, equity issued by the Trust's Premium Distribution, Distribution Re-Investment and Optional Unit Purchase Plan ("DRIP"), and draws on its credit facilities funded the Trust's distributions, capital expenditures, and reclamation trust fund contributions.

In February 2009, Canadian Oil Sands reinstated its DRIP to help preserve balance sheet equity during this period of lower crude oil prices and credit market risk. The participation level in Canadian Oil Sands' DRIP for the distribution paid on February 27, 2009 was about 46 per cent, resulting in an issuance of 1.7 million units.

As of April 27, 2009 Canadian resident Unitholders are eligible to participate in all components of the DRIP and U.S. resident Unitholders may participate in the regular DRIP but not the Premium DRIP or optional cash purchase components of the DRIP.

Unitholder distributions in 2009 exceeded net income primarily as a result of non-cash items included in the calculation of net income such as DD&A and unrealized foreign exchange 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 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.

On April 29, 2009 the Trust declared a quarterly distribution of $0.15 per Unit in respect of the second quarter of 2009 for a total distribution of $72 million. The distribution will be paid on May 29, 2009 to Unitholders of record on May 11, 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.

In establishing its distribution levels, the Trust considers its outlook for crude oil prices and Syncrude operational performance, as well as the Trust's obligations and access to capital markets. We are managing distribution levels to maintain liquidity and financial flexibility in light of prevailing and expected economic conditions and access to capital markets. The Trust has approximately $200 million and $315 million of debt maturing in the second and third quarters of 2009, respectively, that it plans on refinancing through existing credit facilities and/or in the debt capital markets.

In determining distributions, Canadian Oil Sands also considers funding for other operating obligations which are included in cash from operating activities. These obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to $33 million and $11 million in the first quarter of 2009 and 2008, respectively.

Cash from operating activities and net income can fluctuate from period to period due to Syncrude operating performance, WTI pricing, SCO differentials to WTI pricing, 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.

Canadian Oil Sands currently has a long-term net debt target of approximately $1.6 billion by the end of 2010. This target and actual net debt may change as factors such as crude oil prices, Syncrude's operational performance, distributions and FX rates vary from assumptions. While we believe this net debt target reflects efficient capital management and conserves tax pools prior to trust taxation, achievement of this target also must consider a prudent liquidity position and capital market access. Accordingly, the target may change if a more conservative balance sheet is deemed prudent.



LIQUIDITY AND CAPITAL RESOURCES


March 31 December 31
($ millions) 2009 2008
-------------------------------------------------------------------------
Long-term debt $ 1,314 $ 1,258
Cash and cash equivalents (241) (279)
-------------------------------------------------------------------------
Net debt(1) $ 1,073 $ 979
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Unitholders' equity $ 3,914 $ 3,910
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Total capitalization(2) $ 4,987 $ 4,889
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Net debt to total capitalization (%) 22 20
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Non-GAAP measure
(2) Net debt plus Unitholders' equity


As at March 31, 2009, the Trust had drawn $25 million against credit facilities of $840 million. During the first quarter, 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.

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 $12 billion
with 483 million Units outstanding and a closing price of $24.25 per Unit on
March 31, 2009.



Canadian Oil Sands Trust - Trading Activity

First
Quarter March February January
2009 2009 2009 2009
-------------------------------------------------------------------------

Unit price
High $ 26.85 $ 26.85 $ 22.83 $ 24.94
Low $ 16.65 $ 17.91 $ 18.07 $ 16.65
Close $ 24.25 $ 24.25 $ 20.00 $ 18.70

Volume of Trust units traded
(millions) 132.4 40.3 47.5 44.6

Weighted average Trust units
outstanding (millions) 482.2 483.2 481.7 481.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------


FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of February 9, 2009 approximately 30 per cent of our Units were held by non-Canadian residents with the remaining 70 per cent of Units being held by 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 11, 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 March 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 the first 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 and certain obligations are denominated in U.S. dollars. The Trust did not have any foreign currency hedges in place during the first 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. Interest payable on the Trust's credit facilities is based on a floating rate, and the Trust had $25 million outstanding on its credit facilities as at March 31, 2009. During 2009 the Trust has approximately $515 million in long-term debt maturing which is expected to be refinanced with credit facilities and/or in the debt capital markets.

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.

In addition to Syncrude obligations, two tranches of Canadian Oil Sands' debt totaling approximately $515 million will mature during 2009. The Trust has identified potential mitigating strategies to reduce liquidity risk around these maturities. These strategies include the use of operating lines and/or accessing the capital markets prior to these maturities, as well as the use of cash from operating activities which may impact future distributions.

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 March 31, 2009, over 90 per cent of our accounts receivable balance was due from investment grade energy producers and refinery-based customers, and our cash and cash equivalents were either invested in term deposits or held on deposit with a range of high-quality senior Canadian banks. As of April 29, 2009, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.

SUSTAINABLE DEVELOPMENT

Canadian Oil Sands is subject to various environmental legislation and risk factors, which were outlined in its MD&A for the year ended December 31, 2008 ("annual MD&A"). A copy of this report has been filed on SEDAR and is available on our web site. During the first quarter of 2009 there were no material changes to matters disclosed in the annual MD&A.

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 first 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) April 29, 2009 January 28, 2009
-------------------------------------------------------------------------

Syncrude production (MMbbls) 109 115
Canadian Oil Sands Sales (MMbbls) 40.0 42.3
Revenues, net of crude oil purchases
and transportation expense 2,328 2,392
Operating costs 1,340 1,300
Operating costs per barrel 33.46 30.76
Crown royalties 103 65
Capital expenditures 453 440
Cash from operating activities 586 747

Business environment assumptions
--------------------------------
West Texas Intermediate (US$/bbl) $ 50 $ 50
Premium (Discount) to average
C$ WTI prices (C$/bbl) $ (2.50) $ (4.00)
Foreign exchange rate (US$/Cdn$) $ 0.83 $ 0.83
AECO natural gas (Cdn$/GJ) $ 5.00 $ 6.00


On March 20, 2009, the Trust reduced its 2009 Syncrude production estimate from 115 million barrels to 109 million barrels.

The revised production estimate incorporates: lower than expected actual production in the first quarter, the impact of extended turnaround activity in the first half of 2009, an allowance for planned and unplanned maintenance work, and the impact of reliability issues in the mining and extraction processes. Syncrude continues to focus resources to address these issues, including the use of contractor services to accelerate overburden removal, expose more oil sands ore and increase feed volumes to our extraction plants.

Given the significant maintenance program planned in the first half of 2009 and the lower than expected actual winter production, the production outlook is more weighted towards the last half of the year. Syncrude production will need to average approximately 325,000 barrels per day in the last half of 2009 to achieve the Outlook production, which we believe can be achieved with stable operations and the current plan for maintenance work during that time.

We are assuming a U.S.$50 per barrel WTI crude oil price, a $0.825 U.S./Cdn foreign exchange rate, and a $2.50 per barrel SCO discount to Cdn $ WTI, resulting in estimated revenues of $58 per barrel for the year. The SCO discount estimate to Canadian dollar WTI was changed to $2.50 per barrel from the previous $4.00 per barrel discount to reflect actual first quarter results and expectations for the remainder of the year.



April 29, 2009 January 29, 2009
Cdn $ Per US$ Per Cdn $ Per US$ Per
2009 Cost Estimates Bbl Bbl(1) Bbl Bbl(1)
-------------------------------------------------------------------------
Syncrude Costs
Operating expenses $ 33.46 $ 27.60 $ 30.76 $ 25.38
Non-production costs $ 3.45 $ 2.85 $ 3.37 $ 2.78
--------- --------- --------- ---------
$ 36.91 $ 30.45 $ 34.13 $ 28.16
Capital expenditures $ 11.31 $ 9.33 $ 10.41 $ 8.59
--------- --------- --------- ---------
Total Syncrude costs $ 48.22 $ 39.78 $ 44.54 $ 36.75
--------- --------- --------- ---------
Canadian Oil Sands Costs
Interest $ 1.91 $ 1.58 $ 1.73 $ 1.43
Administration, Insurance
and Other $ 0.71 $ 0.59 $ 0.78 $ 0.64
--------- --------- --------- ---------
Total Canadian Oil Sands
Costs $ 2.62 $ 2.16 $ 2.51 $ 2.07
--------- --------- --------- ---------
Total Syncrude and Canadian
Oil Sands Costs $ 50.84 $ 41.94 $ 47.05 $ 38.82

Crown Royalties $ 2.57 $ 2.12 $ 1.55 $ 1.28
--------- --------- --------- ---------
Total Costs $ 53.41 $ 44.06 $ 48.60 $ 40.10
--------- --------- --------- ---------
--------- --------- --------- ---------

(1) Amounts have been converted to US$ at the 2009 Outlook foreign
exchange rate of $0.825 US/Cdn for convenience of the reader.


The April 29, 2009 per barrel cost estimates reflect the impact on per barrel costs of the reduced production outlook to 109 million barrels.

We have increased our estimate of the Trust's operating costs to $1,340 million, or about $33.50 per barrel, consisting of $29 per barrel of production costs and $4.50 per barrel of purchased energy costs. The revised estimate reflects year-to-date results, additional costs of the turnaround, and the impact on per barrel costs of reduced production volumes, partially offset by lower purchased energy costs. When combined with Syncrude non-production costs and capital expenditures, total Syncrude costs per our 2009 Outlook are estimated at $48 per barrel. Canadian Oil Sands expects to incur an additional $3 per barrel of costs to cover interest expense, administration, and insurance, resulting in 2009 Outlook total costs of $51 per barrel for Syncrude and Canadian Oil Sands. Crown royalties are estimated at an additional $2.57 per barrel, reflecting an increase in estimated bitumen valuation and payment of net revenue royalties and upgrader growth recapture.

Based on the above assumptions, our estimate of 2009 cash from operating activities is $586 million or $1.21 per Unit. After deducting estimated 2009 capital expenditures of $453 million, we are estimating $133 million of remaining cash from operating activities, or $0.28 per Unit, to repay debt or pay distributions. In order to preserve financial flexibility during the current period of heightened liquidity risk, we are maintaining our quarterly distribution of $0.15 per Unit for the second quarter of 2009 and continue to offer the DRIP to further preserve equity on the balance sheet.

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 the North American markets could impact the differential for SCO relative to crude benchmarks; however, these factors are difficult to predict.
2009 Outlook Sensitivity Analysis (April 29, 2009)



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 16 0.03
WTI crude oil price increase US$1.00/bbl 38 0.08
Syncrude production increase 2 million bbls 33 0.07
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 1 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) 2009 2008
-------------------------------------------------------------------------

Revenues $ 549 $ 1,026
-------------------------------------------------------------------------

Expenses:
Operating 359 324
Non-production 33 17
Crude oil purchases and transportation expense 37 119
Crown royalties 4 131
Administration 6 4
Insurance 2 2
Interest, net (Note 7) 20 17
Depreciation, depletion and accretion 106 102
Foreign exchange loss (gain) 29 26
-------------------------------------------------------------------------
596 742
-------------------------------------------------------------------------
Earnings (loss) before taxes (47) 284
Future income tax expense (recovery) and other (90) (14)
-------------------------------------------------------------------------
Net income 43 298
Other comprehensive loss, net of income taxes
Reclassification of derivative gains to net income (1) (1)
-------------------------------------------------------------------------
Comprehensive income $ 42 $ 297
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Weighted average Trust Units (millions) 482 479
Trust Units, end of period (millions) 483 479

Net income per Trust Unit:
Basic and diluted $ 0.09 $ 0.62

See Notes to Unaudited Consolidated Financial Statements



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

Three Months Ended
March 31
($ millions) 2009 2008
-------------------------------------------------------------------------
Retained earnings
Balance, beginning of period $ 1,362 $ 1,643
Net income 43 298
Unitholder distributions (Note 10) (72) (360)
-------------------------------------------------------------------------
Balance, end of period 1,333 1,581
-------------------------------------------------------------------------
Accumulated other comprehensive income
Balance, beginning of period 21 24
Other comprehensive loss (1) (1)
-------------------------------------------------------------------------
Balance, end of period 20 23
-------------------------------------------------------------------------
Unitholders' capital
Balance, beginning of period 2,524 2,500
Issuance of Trust Units (Note 4) 33 -
-------------------------------------------------------------------------
Balance, end of period 2,557 2,500
-------------------------------------------------------------------------
Contributed surplus
Balance, beginning of period 3 5
Stock-based compensation 1 -
-------------------------------------------------------------------------
Balance, end of period 4 5
-------------------------------------------------------------------------
Total Unitholders' equity $ 3,914 $ 4,109
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements



CONSOLIDATED BALANCE SHEETS
AS AT
(unaudited)

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

ASSETS
Current assets:
Cash and cash equivalents $ 241 $ 279
Accounts receivable 221 184
Inventories 94 93
Prepaid expenses 7 5
-------------------------------------------------------------------------
563 561

Property, plant and equipment, net 6,253 6,277
Goodwill 52 52
Reclamation trust 44 43
-------------------------------------------------------------------------

$ 6,912 $ 6,933
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 311 $ 284
Current portion of employee future benefits 17 17
-------------------------------------------------------------------------
328 301
Employee future benefits and other liabilities 100 99
Long-term debt 1,314 1,258
Asset retirement obligation 217 235
Future income taxes 1,039 1,130
-------------------------------------------------------------------------
2,998 3,023

Unitholders' equity 3,914 3,910
-------------------------------------------------------------------------

$ 6,912 $ 6,933
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements



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

Three Months Ended
March 31
($ millions) 2009 2008
-------------------------------------------------------------------------

Cash from (used in) operating activities
Net income $ 43 $ 298
Items not requiring outlay of cash:
Depreciation, depletion and accretion 106 102
Unrealized foreign exchange on long-term debt 31 34
Future income tax expense (recovery) (90) (14)
Net change in deferred items and other (21) (5)
-------------------------------------------------------------------------
69 415
Change in non-cash working capital (19) 26
-------------------------------------------------------------------------
Cash from operating activities 50 441
-------------------------------------------------------------------------

Cash from (used in) financing activities
Net drawdown (repayment) of bank credit facilities 25 (16)
Unitholder distributions (Note 10) (39) (360)
-------------------------------------------------------------------------
Cash used in financing activities (14) (376)
-------------------------------------------------------------------------

Cash from (used in) investing activities
Capital expenditures (84) (47)
Reclamation trust funding (1) (1)
Change in non-cash working capital 11 -
-------------------------------------------------------------------------
Cash used in investing activities (74) (48)
-------------------------------------------------------------------------

Increase (decrease) in cash and cash equivalents (38) 17

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

Cash and cash equivalents at end of period $ 241 $ 285
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Cash and cash equivalents consist of:
Cash 12 $ 1
Short-term investments 229 284
-------------------------------------------------------------------------
$ 241 $ 285
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary Information (Note 12)

See Notes to Unaudited Consolidated Financial Statements

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 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 three months ended March 31, 2009, approximately 1.7 million Trust Units were issued pursuant to the Trust's Premium Distribution, Distribution Re-investment and Optional Unit Purchase Plan ("DRIP") for $33 million.

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 months ended March 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
March 31
2009 2008
---------------------------------------------------------------------
Defined benefit plans:
Pension benefits $ 8 $ 8
Other benefit plans 2 1
---------------------------------------------------------------------
$ 10 $ 9

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



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 March 31, 2009, no amounts were drawn on this facility.

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 $67 million were written against the line of credit as at March 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 March 31, 2009, $25 million was drawn against this facility ($Nil - December 31, 2008).



7) INTEREST, NET

Three Months Ended
March 31
2009 2008
---------------------------------------------------------------------

Interest expense on long-term debt $ 21 $ 20
Interest income and other (1) (3)
---------------------------------------------------------------------
Interest expense, net $ 20 $ 17
---------------------------------------------------------------------
---------------------------------------------------------------------


8) 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.

9) STOCK BASED COMPENSATION

During the first quarter of 2009, 441,672 options were issued by the Trust to employees with an average exercise price of $19.15 pursuant to the Trust's Unit Incentive Option Plan.

10) 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
March 31
2009 2008
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Cash from operating activities $ 50 $ 441
Add (Deduct):
Capital expenditures (84) (47)
Change in non-cash working capital(1) 11 -
Reclamation trust funding (1) (1)
Change in cash and cash equivalents and
financing, net(2) 96 (33)
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Unitholder distributions $ 72 $ 360
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Unitholder distributions per Trust Unit $ 0.15 $ 0.75
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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 the first quarter of 2009 were funded by cash payments of $39 million and by the issuance of 1.7 million Trust Units for $33 million.

11) COMMITMENTS

During the first quarter of 2009, Syncrude entered into new natural gas commitments for a total of 46 million gigajoules ("GJ") (17 million net to the Trust) that expire December 31, 2011. The value of this commitment will fluctuate with changes to natural gas prices. Based on an estimated AECO price of $5.00/GJ, the additional commitment to the Trust is approximately $85 million.



12) SUPPLEMENTARY INFORMATION

Three Months Ended
March 31
2009 2008
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Income tax paid $ - $ -
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Interest paid $ 31 $ 25
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Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Units Listed - Symbol: COS.UN
Toronto Stock Exchange

Contact Information

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

    OR

    Canadian Oil Sands Trust Limited
    Siren Fisekci
    Director, Investor Relations,
    (403) 218-6228
    Email: investor_relations@cos-trust.com
    Website: www.cos-trust.com