Canadian Oil Sands Trust
TSX : COS.UN

Canadian Oil Sands Trust

April 25, 2007 23:59 ET

Canadian Oil Sands Trust Announces 2007 First Quarter Results and a Quarterly Distribution Increase to $0.40 Per Trust Unit and 2007 First Quarter Results

CALGARY, ALBERTA--(Marketwire - April 25, 2007) - Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust" or "we") (TSX:COS.UN) today announced first quarter 2007 results and a 33 per cent increase in the Trust's quarterly distribution to $0.40 per Trust unit ("Unit") for Unitholders of record on May 8, 2007, payable on May 31, 2007. Net income in the first quarter of 2007 increased to $262 million, or $0.55 per Unit, from $91 million, or $0.20 per Unit, during the previous year's same period. First quarter 2007 cash from operating activities was $202 million, or $0.42 per Unit, compared to $187 million, or $0.40 per Unit, in 2006. Non-cash operating working capital requirements, primarily a result of higher accounts receivable, reduced first quarter 2007 cash from operating activities by $94 million.

Net income and cash from operating activities reflect higher revenues as a result of incremental Stage 3 production, less turnaround and maintenance activity compared to the prior year, and a larger Syncrude working interest. As well, net income and cash from operating activities benefited from a 41 per cent reduction in per barrel operating costs quarter-over-quarter, offset somewhat by a higher Crown royalty expense.

Crown royalties increased to $9.58 per barrel in 2007 from $0.67 per barrel in 2006 with the shift to the higher royalty rate of 25 per cent of net revenues from the minimum one per cent of gross revenue, which occurred in the second quarter of 2006. In the first quarter of 2007 Syncrude paid royalties totaling $256 million to the Province of Alberta. The Syncrude project began paying the higher rate at roughly the same time as the Stage 3 expansion was completed as a result of robust crude oil prices, which increased revenues from the base plant and accelerated project payout.

"Reflecting our constructive view of our free cash flow over the next several quarters and our intention to move to fuller payout of that free cash flow, we are very pleased to announce our third distribution increase since our Stage 3 project funding began to diminish," said Marcel Coutu, President and Chief Executive Officer. "Reduced capital spending, growing volumes from our recently expanded facilities and a renewed focus on costs and operational reliability are cornerstones of our current operation. These form the foundation upon which our next growth stages will be launched."

First Quarter Highlights

The Trust's 2007 financial results reflect a 36.74 per cent working interest in the Syncrude Joint Venture, which represents the Trust's increased ownership following its previously announced acquisition of a 1.25 per cent Syncrude interest from Talisman Energy Inc. ("Talisman") on January 2, 2007. Prior year comparative information is based on the Trust's previous ownership of 35.49 per cent.

- Sales volumes increased 46 per cent, averaging about 109,000

barrels per day, in the first quarter of 2007 compared to the same

2006 period. The Trust's larger Syncrude ownership, incremental

production from Stage 3, and less turnaround and maintenance

activity quarter-over-quarter contributed to higher volumes

in 2007.

- Operating costs averaged $23.56 per barrel in 2007, down from

$40.26 per barrel in 2006 as a result of lower turnaround and

maintenance activity, a decrease in the value of Syncrude's long-

term incentive plan, and lower purchased energy costs in 2007

compared to 2006.

- Quarterly capital expenditures in 2007 declined to $33 million

from $137 million in 2006 with the completion of the Stage 3

project in August 2006.

- Net debt to book capitalization of 25 per cent at the end of the

first quarter of 2007 remained the same as at 2006 year end.

- The Trust is maintaining its single point estimate for 2007

production of 110 million barrels, or 40.4 million barrels net to

the Trust. On March 13, 2007, the Trust announced a reduction to

the upper end of its production range by five million barrels with

the current range now between 105 to 115 million barrels, or 39 to

42 million barrels net to the Trust. The change reflects

constrained production rates from Coker 8-3 since late 2006.

Syncrude plans to perform maintenance on Coker 8-3 during the

second quarter of 2007 to restore production throughput.

- The Syncrude Joint Venture owners have approved the

recommendations of an Opportunity Assessment Team as part of the

Management Services Agreement between Syncrude Canada Ltd. and

Imperial Oil Resources Ltd., previously announced on November 1,

2006. Implementation of the recommendations will be led by

Mr. Tom Katinas, who has been appointed to the consolidated role

of President and Chief Executive Officer of Syncrude Canada

effective May 1, 2007.

Effective April 25, 2007, Mr. Walter O'Donoghue will be retiring from Canadian Oil Sands' board of directors. Commencing as chairman in 1995 of Athabasca Oil Sands Trust, one of the predecessors of Canadian Oil Sands Trust, Mr. O'Donoghue has served as a board member since the Trust's inception. We want to thank him for providing his knowledge and insight in helping to create and develop the Trust into the successful entity that it is today. We wish him the best in his retirement.

Canadian Oil Sands Trust's Annual and Special Meeting of Unitholders will

be held on April 25, 2007 at 2:30 pm. A live audio Web cast of the

meeting will be available on our Web site at www.cos-trust.com under

investor information, presentations and Web casts. An archive of the Web

cast will be available approximately one hour following the meeting.

CANADIAN OIL SANDS TRUST



Highlights

Three Months Ended

(millions of Canadian dollars, March 31

except Trust unit and volume amounts) 2007 2006

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Net Income $ 262 $ 91

Per Trust unit - Basic $ 0.55 $ 0.20

Per Trust unit - Diluted $ 0.55 $ 0.20

Cash from Operating Activities $ 202 $ 187

Per Trust unit $ 0.42 $ 0.40

Unitholder Distributions $ 144 $ 93

Per Trust unit $ 0.30 $ 0.20

Syncrude Sweet Blend Sales Volumes (i)

Total (MMbbls) 9.8 6.7

Daily average (bbls) 108,981 74,929

Operating Costs per barrel $ 23.56 $ 40.26

Net Realized Selling Price per barrel

Realized selling price before hedging $ 68.47 $ 69.17

Currency hedging gains (losses) 0.22 1.07

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Net realized selling price $ 68.69 $ 70.24

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West Texas Intermediate ($US per barrel) $ 58.23 $ 63.48

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(i) 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.


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") was prepared as of April 25, 2007 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, 2007 and March 31, 2006, as well as the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2006.

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 contain "forward-looking statements" under applicable securities law. Forward-looking statements in this M&DA include, but are not limited to, statements with respect to: the expectation that Coker 8-3 will achieve its productive capacity after undergoing maintenance in the second quarter; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2007 for Canadian Oil Sands' product; the expected reserves and the impact of such reserves estimates on the D&D rate; the potential amount payable in respect of any future income tax liability; the expected impact on the Trust from the announced changes to the federal government's taxation of income trusts; the expectation that the net debt level will allow the Trust to remain unhedged while providing the capacity to fund growth opportunities; the belief that the Trust will not be restricted by its net debt to total capitalization financial covenant; the expected increased reliability and other benefits from the management services agreement between Syncrude Canada Ltd. and Imperial Oil Resources; the anticipated timing to reach full production rates from Coker 8-3 and to modify the FGD unit and hydrogen plant; the expected impact that increased supplies of synthetic crude oil will have on the net realized selling price that Canadian Oil Sands receives for its product; the level of energy consumption in 2007 and beyond; the timing to start and complete the turnaround of Coker 8-3; capital expenditures for 2007; the anticipated cost and completion date for the SER project; the expectation not to enter into crude oil hedges in the future; the level of natural gas consumption in 2007 and beyond; the expected timing to produce SSP; the expected price for crude oil and natural gas in 2007, the expected production, revenues and operating costs for 2007; the net sales proceeds of the disposition of the remainder of Canadian Arctic Gas Ltd.'s conventional assets; 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; and the expected impact of any future environmental legislation or changes to the Crown royalties regime.
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 impact of technology on operations and processes and how new complex technology may not perform as expected, 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 variances of stock market activities generally, normal risks associated with litigation, general economic, business and market conditions, regulatory changes, 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. The discussion on proposed tax changes in trust tax legislation is based solely on the general information found in the background paper issued by Finance at the time of the October 31, 2006 announcement (which is not legislation), the guidelines issued by Finance on December 15, 2006, and the draft amendments to the Tax Act released on December 21, 2006. No assurance can be given that the final legislation implementing the 2006 proposed tax changes will be consistent with the foregoing or that Canadian federal income tax law respecting income trusts and other flow-through entities will not be further changed in a manner which adversely affects the Trust and its Unitholders. To the extent that changes, including the 2006 proposed tax changes, are implemented, such changes could result in the income tax considerations described in this MD&A being materially different in certain respects. 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 2007, the Syncrude Joint Venture ("Syncrude") oil production totalled 26.6 million barrels, or an average of 296,000 barrels per day, compared to 18.4 million barrels, or 205,000 barrels per day, during the same period of 2006. First quarter 2007 production was slightly under the 27 million barrel estimate provided in our January 29, 2007 Guidance Document. Net to the Trust, production totalled 9.8 million barrels in the first quarter of 2007 based on our 36.74 per cent working interest compared to 6.5 million barrels in 2006 based on a 35.49 per cent interest.

Production in the first quarter of 2007 was primarily affected by unplanned maintenance on Coker 8-2, which began in late 2006 and extended into late January, combined with constrained production rates from the new Coker 8 - 3. Comparatively, production in the first quarter of 2006 was affected by an extensive maintenance schedule with turnarounds of several units including an extended turnaround of Coker 8-1. As well, the increase in the Trust's share of Syncrude's production in 2007 reflects the Trust's higher 36.74 per cent ownership interest.

Coker 8-3 has been producing at about 70 per cent of its capacity since late 2006. During March, lower volumes from Coker 8-3 were offset by higher output from Cokers 8-1 and 8-2 with production averaging 356,000 barrels per day during the month. To bring Coker 8-3 closer to its design rate, Syncrude plans to perform maintenance starting in May of 2007 to remove coke residue build-up within the vessel. While maintenance on Coker 8-3 was not scheduled to occur this early in its run length, we did anticipate encountering various performance issues associated with bringing a new, complex expansion such as Stage 3 into operation.

Canadian Oil Sands' operating costs declined to $23.56 per barrel in the first quarter of 2007 compared with $40.26 per barrel in the same quarter last year. There was less turnaround and maintenance activity quarter-over-quarter, thereby increasing production and reducing per barrel costs. First quarter 2007 operating costs also reflect lower purchased energy and Syncrude incentive compensation costs compared to the same quarter of 2006 (see "Operating Costs" section of this MD&A for further discussion).

Syncrude's post-Stage 3 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. This daily production capacity is referred to as "barrels per stream day". However, under normal operating conditions, scheduled downtime is required for maintenance and turnaround activities and unscheduled downtime will occur as a result of mechanical problems, unanticipated repairs and other slowdowns. When allowances for such downtime are included, the daily design productive capacity of Syncrude's post-Stage 3 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 the following discussions 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. These in-transit volumes vary with current production. The growth in Syncrude™ Sweet Blend ("SSB") volumes from the Stage 3 facilities also has required Canadian Oil Sands to access more distant markets to sell its volumes, which generally increases in-transit pipeline volumes. The impact of Syncrude's first quarter operations on Canadian Oil Sands' financial results is more fully discussed later in this MD&A.



SUMMARY OF QUARTERLY RESULTS

($ millions, except

per Trust Unit and 2007 2006

volume amounts) Q1 Q4 Q3 Q2 Q1

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Revenues(1) $ 674 $ 646 $ 689 $ 624 $ 473

Net income $ 262 $ 128 $ 278 $ 337 $ 91

Per Trust Unit,

Basic(2) $ 0.55 $ 0.27 $ 0.60 $ 0.72 $ 0.20

Per Trust Unit,

Diluted(2) $ 0.55 $ 0.27 $ 0.59 $ 0.72 $ 0.20

Cash from operating

activities $ 202 $ 412 $ 334 $ 209 $ 187

Per Trust

Unit(2) $ 0.42 $ 0.88 $ 0.72 $ 0.45 $ 0.40

Daily average sales

volumes (bbls) 108,891 110,185 95,438 86,394 74,929

Net realized selling

price ($/bbl) $ 68.69 $ 63.71 $ 78.43 $ 79.35 $ 70.24

Operating costs

($/bbl) $ 23.56 $ 23.60 $ 19.68 $ 28.48 $ 40.26

Purchased natural

gas price ($/GJ) $ 6.99 $ 6.51 $ 5.42 $ 5.72 $ 7.42

($ millions, except

per Trust Unit and 2005

volume amounts) Q4 Q3 Q2

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

Revenues(1) $ 519 $ 612 $ 492

Net income $ 174 $ 380 $ 218

Per Trust Unit,

Basic(2) $ 0.38 $ 0.83 $ 0.48

Per Trust Unit,

Diluted(2) $ 0.37 $ 0.83 $ 0.48

Cash from operating

activities $ 281 $ 364 $ 199

Per Trust

Unit(2) $ 0.61 $ 0.79 $ 0.43

Daily average sales

volumes (bbls) 78,318 85,942 79,506

Net realized selling

price ($/bbl) $ 72.07 $ 77.43 $ 68.03

Operating costs

($/bbl) $ 25.54 $ 23.61 $ 21.35

Purchased natural

gas price ($/GJ) $ 10.73 $ 8.31 $ 6.94

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

(2) Trust Unit information has been adjusted to reflect the 5:1 Unit

split that occurred on May 3, 2006.

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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 non-cash foreign exchange gains and losses caused by fluctuations in foreign exchange rates on our U.S. dollar denominated debt and by future income tax changes. A large proportion of operating costs are fixed and, as such, unit 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 occur in the first or second quarter. However, the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages will occur. As a result, production levels also 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, as demonstrated by the particularly high per barrel operating costs in the first quarter of 2006. 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.

Three significant changes have occurred over the last eight quarters that have impacted the Trust's financial results:

- Syncrude's Stage 3 expansion came on-line at the end of August

2006, increasing Syncrude's productive capacity by about 100,000

barrels per day with a corresponding impact on the Trust's

revenues.

- During the second quarter of 2006, Crown royalties shifted to the

higher rate of 25 per cent of net revenue, compared to the

one per cent of gross revenue rate that had applied since

January 1, 2002, increasing Crown royalties expense and somewhat

offsetting the revenue increases to net income and cash from

operating activities in the latter half of 2006 and the first

quarter of 2007.

- Starting in the first quarter of 2007, the Trust's financial

results reflect a 36.74 per cent working interest in Syncrude,

which represents its increased ownership following the acquisition

of Talisman Energy Inc.'s ("Talisman") 1.25 per cent working

interest on January 2, 2007. Prior year comparative information is

based on the Trust's previous ownership of 35.49 per cent.

REVIEW OF FINANCIAL RESULTS

Net income in the first quarter of 2007 increased by $171 million to total $262 million, or $0.55 per Trust Unit ("Unit"), from the same period of last year. Cash from operating activities was $202 million, or $0.42 per Unit, in the first quarter of 2007 compared to $187 million, or $0.40 per Unit, in 2006. The increase in cash from operating activities quarter-over-quarter was not as significant as the change in net income, mainly due to changes in operating non-cash working capital. In the first quarter of 2007, non-cash operating working capital requirements reduced cash from operating activities by $94 million, primarily a result of higher accounts receivable. An increase in March sales volumes and the average realized selling price resulted in a higher accounts receivable balance relative to December 31, 2006. Comparatively in the first quarter of 2006, cash from operating activities increased by $46 million from changes in non-cash working capital, mainly due to lower accounts receivable at quarter-end relative to December 31, 2005.



Three Months Ended

March 31

($ per bbl) 2007 2006 $ Change

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Net realized selling price 68.69 70.24 (1.55)

Operating costs (23.56) (40.26) 16.70

Crown royalties (9.58) (0.67) (8.91)

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Netback 35.55 29.31 6.24

Non-production costs (1.78) (3.76) 1.98

Administration and insurance (0.65) (1.07) 0.42

Interest, net (2.48) (3.69) 1.21

Depletion, depreciation and accretion (8.49) (7.46) (1.03)

Foreign exchange gain (loss) 0.79 (0.25) 1.04

Current and future income tax

recovery (expense) 3.74 0.41 3.33

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(8.87) (15.82) 6.95

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Net income per barrel 26.68 13.49 13.19

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Sales volumes (MMbbls) 9.8 6.7 3.1

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Incremental Stage 3 production, less turnaround and maintenance activity, and a larger Syncrude working interest in the first quarter relative to the prior year contributed to a $201 million increase in revenues (after crude oil purchases and transportation expense) to $674 million in 2007 compared to 2006. Net income and cash from operating activities also benefited from a $40 million reduction in operating costs quarter-over-quarter. Operating costs were $23.56 per barrel in the first quarter of 2007, a decrease of $16.70 per barrel compared to the same period in 2006; however, partially offsetting the increase in revenues and reduction in operating costs was an $89 million increase to Crown royalties expense relative to the same quarter of 2006. Crown royalties amounted to $94 million, or $9.58 per barrel, in the first quarter of 2007, compared to $5 million, or $0.67 per barrel, in the same period of 2006. The higher royalties reflect both the higher Crown royalty rate and the increase in net revenue in the current year.

Also reducing net income in the first quarter of 2007 relative to the same period of 2006 was a $32 million increase to depreciation, depletion and accretion expense. An increase in the per barrel depreciation and depletion ("D&D") rate, combined with higher production volumes, resulted in the quarter-over-quarter increase in this non-cash expense; however, offsetting this decrease to net income was a $33 million increase to future income tax recovery mainly as a result of changes in temporary differences of the Trust's subsidiary in the first quarter of 2007.

Non-GAAP Financial Measures

In this report, we may refer to the Trust's free cash flow as well as cash from operating activities per Unit, which are measures that do not have any standardized meaning under Canadian generally accepted accounting principles ("GAAP"). Free cash flow is derived from cash from operating activities reported on the Trust's Consolidated Statement of Cash Flows, less capital expenditures and reclamation trust contributions in the period. In management's opinion, free cash flow is a key indicator of the Trust's ability to repay debt and pay distributions to its Unitholders. Free cash flow may not be directly comparable to similar measures presented by other companies or trusts.



Revenues after Crude Oil Purchases and Transportation Expense

Three Months Ended

March 31

($ millions) 2007 2006 Variance

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Sales revenue(1) $ 781 $ 509 $ 272

Crude oil purchases (99) (34) (65)

Transportation expense (10) (9) (1)

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672 466 206

Currency hedging gains(1) 2 7 (5)

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$ 674 $ 473 $ 201

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Sales volumes (MMbbls) 9.8 6.7 3.1

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(1) The sum of sales revenue and currency hedging gains equals Revenues

on the Trust's Consolidated Statement of Income and Comprehensive

Income.

($ per barrel)

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Realized selling price before

hedging(2) $ 68.47 $ 69.17 $ (0.70)

Currency hedging gains 0.22 1.07 (0.85)

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Net realized selling price $ 68.69 $ 70.24 $ (1.55)

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(2) Sales revenue, after and transportation expense divided by SSB sales

volumes, net of purchased crude oil volumes.


Sales revenue after crude oil purchases and transportation expense and before currency hedging in the first quarter of 2007 relative to the comparable quarter of 2006 reflects the 46 per cent increase in sales volumes quarter-over-quarter. The Trust's larger Syncrude ownership and incremental production from the Stage 3 facilities during the first quarter of 2007, together with the lower production in the prior year's quarter due to extensive turnaround and maintenance activity, resulted in the higher 2007 sales volumes.

While volumes increased significantly relative to 2006, the increase to revenues was partially reduced by a decrease in our realized SSB selling price, which averaged $68.47 per barrel, before currency hedging gains, in the first quarter of 2007, compared to $69.17 per barrel in the same period of 2006. While our average realized selling price did not change significantly from the prior year, the underlying elements of the prices varied more significantly quarter-over-quarter. West Texas Intermediate ("WTI") prices, which our SSB product pricing tends to follow, averaged approximately US$58 per barrel in 2007, a decrease of over $5 per barrel compared to the same quarter of 2006. This decrease was offset by a weakening of the Canadian dollar relative to the U.S. dollar, which averaged $0.85 US/Cdn in the first quarter of 2007 compared to $0.87 US/Cdn in the same quarter of 2006, and a significant improvement in our pricing differentials relative to WTI. Our SSB product realized a weighted-average discount of $0.08 per barrel compared to average Canadian dollar WTI in the first quarter of 2007 versus a discount of $4.39 per barrel in the same period in 2006. The improvement in differential quarter-over-quarter highlights the relatively weak differential reported in the first quarter of 2006. The large discount realized in that period was driven by both reduced product demand as a result of refinery outages, and increased supply of light crude oil resulting from a pipeline reconfiguration. As well, pipeline restrictions limited access to extended markets placing downward pressure on SSB prices in the first quarter of 2006. By comparison, the first quarter of 2007 reflected a tighter supply/demand balance as a result of lower than anticipated supply and new demand. The differential can change quickly between a premium or a discount depending on the synthetic supply/demand dynamics in the marketplace and pipeline availability for transporting the crude oil.



Operating costs

Three Months Ended

March 31

2007 2006

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$/bbl $/bbl $/bbl $/bbl

Bitumen SSB Bitumen SSB

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Bitumen Costs(1)

Overburden removal 1.69 3.24

Bitumen production 8.46 9.47

Purchased energy(3) 2.72 3.90

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12.87 15.39 16.61 19.21

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Upgrading Costs(2)

Bitumen processing and

upgrading 4.81 5.33

Turnaround and catalysts 1.02 7.49

Purchased energy(3) 2.87 3.99

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8.70 16.81

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Other and research 0.04 3.51

Change in treated and

untreated inventory (0.55) 0.93

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Total Syncrude operating costs 23.58 40.46

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Canadian Oil Sands adjustments(4) (0.02) (0.20)

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Total operating costs 23.56 40.26

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(thousands of barrels

per day) Bitumen SSB Bitumen SSB

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Syncrude production volumes 354 296 237 205

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(1) Bitumen costs relate to the removal of overburden, oil sands mining,

bitumen extraction and tailings dyke construction and disposal costs.

The costs are expressed on a per barrel of bitumen production basis

and converted to a per barrel of SSB based on the yield of SSB from

the processing and upgrading of bitumen.

(2) Upgrading costs include the production and ongoing maintenance costs

associated with processing and upgrading of bitumen to SSB. It also

includes the costs of major refining equipment turnarounds and

catalyst replacement.

(3) Natural gas costs averaged $6.99/GJ and $7.42/GJ in the first

quarters of 2007 and 2006, respectively.

(4) Canadian Oil Sands' adjustments mainly pertain to Syncrude-related

pension costs, property insurance costs, site restoration costs, as

well as the inventory impact of moving from production to sales as

Syncrude reports per barrel costs based on production volumes and we

report based on sales volumes.

Three Months Ended

March 31

($/bbl of SSB) 2007 2006

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Production costs 17.43 31.76

Purchased energy 6.13 8.50

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Total operating costs 23.56 40.26

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(GJs/bbl of SSB)

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Purchased energy consumption 0.88 1.15

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During planned and unplanned shutdowns, Syncrude directs resources towards other activities, and thus, the operation is less efficient with lower production and higher operating costs. This is evident in the decrease in overburden removal costs and bitumen production of about $3 per barrel of SSB in the first quarter of 2007 compared to the same 2006 period. The Stage 3 project had not yet commenced production in the first quarter of 2006 and Syncrude utilized the additional Stage 3 staff and equipment that it had in place to remove additional overburden. These additional overburden removal costs were expensed as incurred, resulting in higher bitumen costs on a per barrel basis. Lower turnaround and maintenance activity in the first quarter of 2007 relative to the comparable 2006 quarter also reduced operating costs by over $6 per barrel. While there was unplanned maintenance work on Coker 8-2 and repairs to one of the hydrotreaters in the first quarter of 2007, the prior year's first quarter had more extensive turnarounds, including Coker 8-1.

Also contributing to a reduction in per barrel production costs was a decrease in the value of Syncrude's long-term incentive plan of almost $4 per barrel. A portion of Syncrude's long-term incentive compensation is based on the market return performance of several Syncrude owners' shares/units, which was not as strong in the first quarter of 2007 relative to the same period in 2006.

Purchased energy costs fell by $2.37 per barrel in the first quarter of 2007 due to lower natural gas prices and energy consumption per barrel compared to the same quarter of 2006. In the first quarters of 2007 and 2006, natural gas prices averaged $6.99 and $7.42 per gigajoule, respectively. Energy consumption per barrel decreased by 23 per cent in 2007 due to higher maintenance activity and commissioning of Stage 3 units during the 2006 first quarter. Natural gas consumption rises during periods of maintenance activity, particularly during coker turnarounds as process heat integration within the facilities declines, requiring additional natural gas purchases during unit outages. In addition, commissioning of individual Stage 3 units in 2006 raised purchased energy consumption as these units were brought into service without an offsetting increase in SSB production.

Non-production costs

Non-production costs consist primarily of development expenditures relating to capital programs, which are expensed, such as: commissioning costs, pre-feasibility engineering, technical and support services, research and development ("R&D"), and regulatory and stakeholder consultation expenditures. Accordingly, non-production costs can vary depending on the number of projects on-going and the status of the projects. In the first quarter of 2007, non-production costs totalled $18 million, a decrease of $7 million from the same quarter in 2006, mainly reflecting the completion of the Stage 3 project. Stage 3 contributed $12 million of commissioning and start-up costs in the first quarter of 2006.

Crown Royalties

Under Alberta's generic Oil Sands Royalty, the Crown royalty is calculated as the greater of one per cent of gross plant gate revenue before hedging, or 25 per cent of net revenues, calculated as gross plant gate revenue before hedging, less allowed Syncrude operating, non-production and capital costs. Crown royalties increased by $89 million to $94 million, or $9.58 per barrel, in the first quarter of 2007 from $5 million, or $0.67 per barrel, in the comparable 2006 quarter. The increase in 2007 Crown royalties reflects both the shift to the higher royalty rate, which occurred in the second quarter of 2006, and higher net revenues as a result of a larger Syncrude working interest and incremental Stage 3 production volumes. The shift to the higher rate is triggered once a project reaches payout by recovering its costs and a return allowance equal to a Government of Canada long-term bond rate. As a result of robust crude oil prices, which increased revenues from Syncrude's base plant, payout of the Stage 3 expansion was accelerated and resulted in Syncrude moving to the higher Crown royalty rate in the second quarter of 2006.



Depreciation, depletion and accretion expense

Three Months Ended

March 31

($ millions) 2007 2006

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Depreciation and depletion expense $ 80 $ 48

Accretion expense 2 2

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$ 82 $ 50

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D&D expense for the first quarter of 2007 rose by $32 million compared to the same quarter of 2006, reflecting an increase in production volumes and a higher per barrel D&D rate. The larger production volumes in 2007 are attributable to the larger Syncrude ownership, incremental Stage 3 production volumes, and less turnaround and maintenance activity in the quarter relative to the prior year.

We revised our per barrel D&D rate in the first quarter of 2007 to reflect the additional assets and reserves acquired in the January acquisition of a 1.25 per cent working interest, as well as the updated reserve and future development cost estimates provided for in the Trust's December 31, 2006 independent reserves report. The D&D rate for 2007 is approximately $8 per barrel, an increase of about $1 per barrel from prior year as a result of the acquisition and higher future development cost estimates, which reflect a higher cost environment relative to the prior year.

The Trust's reserves report is outlined in its Annual Information Form and can be found at www.sedar.com, or on our website at www.cos-trust.com under investor information.

Foreign exchange

Foreign exchange 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. In addition, other foreign exchange gains/losses are created through the revaluation of cash, accounts receivable and payable balances denominated in U.S. dollars.

In the first quarter of 2007, Canadian Oil Sands recorded a $7 million foreign exchange gain compared to a $2 million loss in the same quarter of 2006. The revaluation of our U.S. dollar denominated debt resulted in a non-cash foreign exchange gain of $11 million, reflecting a strengthening of the Canadian dollar to $0.87 US/Cdn on March 31, 2007 from $0.86 US/Cdn at December 31, 2006. By comparison, the Canadian dollar weakened slightly on March 31, 2006 compared with December 31, 2005, resulting in an unrealized foreign exchange loss of $1 million in the first quarter of 2006.

Future Income Tax

In the first quarter of 2007, Canadian Oil Sands reported a future income tax recovery of $38 million, which was an increase of $33 million from the same period in 2006. The larger recovery primarily reflects decreases to temporary differences between the book and tax basis of the Trust's subsidiary's assets and liabilities.

Also in the first quarter of 2007, Canadian Oil Sands recorded an additional future income tax liability on its Consolidated Balance Sheet totalling $327 million, with a corresponding increase to property, plant and equipment, as a result of the 1.25 per cent working interest acquisition on January 2 and the subsequent dissolution of the partnership in which the working interest was held. The future income tax liability represents the temporary differences between the book values of the net assets and the related tax pools acquired, tax-effected at the substantively enacted rates expected to be in effect when such temporary differences reverse. Details of the acquisition and related future income tax adjustments are included in Note 4 to the unaudited Consolidated Financial Statements for the quarter ending March 31, 2007.

As of the date of this MD&A, the proposed taxation of income trusts as originally announced by the federal government late in 2006 is not yet legislation. As such, Canadian Oil Sands has not recorded future income taxes related to the Trust. As stated in the Trust's 2006 annual report, we anticipate recording a future income tax expense and corresponding increase to future income tax liability of approximately $0.6 billion related to the Trust's taxable temporary differences if and when the new trust tax rules are substantively enacted.

Capital expenditures

With the completion of Syncrude's Stage 3 project in 2006, Canadian Oil Sands' expansion capital expenditures have been reduced significantly and, as such, current capital costs are essentially all related to sustaining capital. The Trust defines expansion capital expenditures as the costs incurred to grow the productive capacity of the operation, such as the Stage 3 project, while sustaining capital is effectively all other capital and includes the costs required to maintain the current productive capacity of Syncrude's mines and upgraders. Sustaining capital may fluctuate considerably year-to-year due to timing of equipment replacement and other factors.

In the first quarter of 2007, capital expenditures totalled $33 million, a reduction of $104 million from the same quarter of 2006. In 2007, approximately $15 million related to the Syncrude Emissions Reduction ("SER") project with the remaining $18 million pertaining to the maintenance of Syncrude's existing plant and facilities, all of which are considered sustaining capital. Comparatively, in the same period of 2006, approximately 71 per cent of capital expenditures pertained to the Stage 3 expansion. Sustaining capital expenditures on a per barrel basis were approximately $3.50 and $6 in the first quarters of 2007 and 2006, respectively.

The SER project is being undertaken to retrofit technology into the operation of Syncrude's original two cokers to significantly reduce total sulphur dioxide and other emissions. Expenditures on the SER project are expected to total approximately $772 million, or $284 million net to the Trust based on its 36.74 per cent working interest. The Trust's share of the SER project expenditures incurred to date, including amounts expensed, is approximately $51 million, with the remaining costs to be incurred in the next four years to coordinate with equipment turnaround schedules.

We estimate sustaining capital expenditures will average $6 per barrel, including the SER project, over the next four years. Excluding major sustaining capital expenditure projects which occur from time to time, such as the SER project, we anticipate average sustaining capital expenditures of approximately $5 per barrel, or $240 million annually, net to the Trust, based on annual Syncrude productive capacity of 128 million barrels, or 47 million barrels net to the Trust.

Canadian Oil Sands is in the process of selling the remaining conventional properties it acquired in 2006 from Canadian Arctic Gas Ltd. The properties are reflected on the Trust's Consolidated Balance Sheet under the heading "Assets held for sale". The conventional properties which the Trust still owned at March 31, 2007 did not generate material income in the first quarter of 2007.

CHANGE IN ACCOUNTING POLICIES

Effective January 1, 2007, the Trust prospectively adopted the Canadian Institute of Chartered Accountant's ("CICA") Handbook Section 3855, Financial Instruments - Recognition and Measurement; Section 3865, Hedges; Section 1530, Comprehensive Income and Section 3861, Financial Instruments - Disclosure and Presentation. The impacts of adopting the new standards are reflected in the Trust's current quarter results, and prior year comparative financial statements have not been restated. While the new rules resulted in changes to how the Trust accounts for its financial instruments, there were no material impacts on the Trust's current quarter financial results. For a description of the new accounting rules and the impact on the Trust's financial statements of adopting such rules, including the impact on the Trust's deferred financing charges, long-term debt, and deferred currency hedging gains, see Note 2 to the unaudited Consolidated Financial Statements for the quarter ending March 31, 2007.



LIQUIDITY AND CAPITAL RESOURCES

March 31 December 31

($ millions) 2007 2006

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

Long-term debt $ 1,543 $ 1,644

Cash and cash equivalents (65) (353)

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

Net debt $ 1,478 $ 1,291

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Unitholders' equity $ 4,339 $ 3,956

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Total capitalization(1) $ 5,817 $ 5,247

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(1) Net debt plus Unitholders' equity

Net debt to total capitalization (%) 25 25

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In the first quarter of 2007, Canadian Oil Sands made a $237.5 million cash payment and issued 8.2 million Units for $237.5 million to Talisman as consideration for the purchase of Talisman's 1.25 per cent indirect Syncrude working interest. The Trust had built cash at the end of December 2006 in anticipation of paying Talisman on January 2, 2007. The acquisition was followed by the maturity of $195 million of medium term notes on January 15, 2007, which the Trust refinanced by drawing on its $800 million operating credit facility. During the quarter, Canadian Oil Sands paid down $75 million of the amounts drawn on the facility, leaving $120 million drawn at March 31, 2007. As discussed in Note 2 to the unaudited Consolidated Financial Statements, the Trust recorded a $16 million reduction to its long-term debt as a result of adopting the new financial instruments accounting standards. The reduction reflected the reclassification of deferred financing charges against long-term debt, which were previously recorded in other assets on the Trust's Consolidated Balance Sheet. Overall, including an unrealized foreign exchange gain of $11 million, the Trusts' long-term debt decreased by $101 million to $1.5 billion at quarter-end, while net debt increased $187 million to $1.5 billion reflecting the reduced cash balance. As at March 31, 2007, the Trust's unutilized credit facilities amounted to $704 million, including amounts drawn on its $40 million revolving term facility.

The Units issued from treasury increased Unitholders' equity. However, as the Units were issued directly to Talisman, there was no cash impact. The investing section of the Trust's cash flow statement, therefore only reflects the cash paid to Talisman for the additional working interest less cash balances acquired. The remaining growth in Unitholders' equity is primarily attributable to net income of $262 million exceeding distributions of $144 million paid in the quarter.

The $202 million of cash generated by the Trust's operating activities in the first quarter of 2007 was more than adequate to pay distributions of $144 million, or $0.30 per Unit, on February 28 and to fund $40 million of investing activities, excluding the acquisition of Talisman's Syncrude interest. As previously indicated, the Trust suspended its Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan ("DRIP") as of January 31, 2007 and, as such, the DRIP did not provide additional equity financing in the quarter. In the same quarter of 2006, cash from operating activities of $187 million was insufficient to fund distributions of $93 million, or $0.20 per Unit, and investing activities of $165 million.

The Trust's free cash flow rose $119 million to total $168 million, or $0.35 per Unit, in the first quarter of 2007 compared to the same period of 2006. The increase primarily reflects the reduction in the Trust's capital expenditures in 2007 with the completion of Stage 3 in 2006.

A Unitholder distribution schedule pertaining to the quarter ended March 31 is included in Note 10 to the unaudited Consolidated Financial Statements. The Trust historically has used debt and equity financing to the extent that cash from operating activities was insufficient to fund distributions, capital expenditures, mining reclamation trust contributions, acquisitions and working capital changes from financing and investing activities.

On April 25, 2007, the Trust declared a distribution of $0.40 per Unit for total distributions of $192 million. The distribution will be paid on May 31, 2007 to Unitholders of record on May 8, 2007. Canadian Oil Sands' Board approved a 33 per cent increase to the Trust's second quarter distribution based on our current outlook, as outlined later in this MD&A, and net debt slightly lower than our target of $1.6 billion. The Trust had previously indicated it intends to move to fuller payout of its free cash flow while targeting a net debt level of about $1.6 billion. The Trust believes this net debt target maintains its strong balance sheet allowing it to remain unhedged on crude oil production, and providing the capacity to fund growth opportunities. The Trust's actual net debt will fluctuate around this level as factors such as crude oil prices and Syncrude operational performance, vary from our assumptions.

Debt covenants do not specifically limit the Trust's ability to pay distributions and are not expected to influence the Trust's liquidity in the foreseeable future. Aside from the typical covenants relating to restrictions on Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business, the most restrictive financial covenant limits total debt-to-total book capitalization at an amount less than 0.55 to 1.0. With a current net debt book capitalization of approximately 25 per cent, a significant increase in debt or decrease in equity would be required to negatively impact the Trust's financial flexibility, and at the current time, we do not anticipate such changes.

In determining the Trust's distributions, Canadian Oil Sands considers funding for its significant operating obligations, which are included in cash from operating activities. Such obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to approximately $8 million in each of the first quarters of 2007 and 2006 and approximated the related expense for both pension and reclamation of $10 million in each of the same quarters. We are anticipating an increase of $5 million in each of the next five years in the Trust's funding requirements related to its share of Syncrude's pension plan funding. The increase is based on preliminary estimates from Syncrude's December 31, 2006 actuarial valuation, which will be completed during the second quarter of 2007. With regards to reclamation, we do not anticipate incurring significant increases in reclamation funding requirements for many years given the long reserve life of the Syncrude resource. We do not expect a significant difference in our actual reclamation funding in 2007 over amounts paid in 2006, which totalled approximately $7 million, including amounts contributed to our mining reclamation trust account.

UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY

Canadian Oil Sands Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $14 billion with 479 million Units outstanding and a closing price of $28.26 per Unit on March 31, 2007.



First

Canadian Oil Sands Trust - Quarter March February January

Trading Activity 2007 2007 2007 2007

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Unit price

High $ 33.00 $ 29.20 $ 30.39 $ 33.00

Low $ 25.09 $ 25.09 $ 26.72 $ 26.67

Close $ 28.26 $ 28.26 $ 27.30 $ 30.07

Volume of Trust units traded

(millions) 101.3 34.6 32.6 34.1

Weighted average Trust units

outstanding (millions) 479.0 479.1 479.1 478.8

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Contractual Obligations and Commitments

As of March 31, 2007, the Trust's share of Syncrude's capital expenditure commitments increased by $42 million, which are to be incurred over the next two years. As discussed previously, Syncrude's pension plan actuarial valuation for December 31, 2006 is to be completed in the second quarter of 2007, at which time the updated pension funding commitments will be provided. There have been no other significant changes to the Trust's contractual obligations and commitments from our 2006 year-end disclosure, other than reductions to the capital expenditure and various payment obligation commitments as a result of expenditures incurred in the first quarter and changes in long-term debt.

Regarding the Management Services Agreement previously announced on November 1, 2006, the Syncrude Joint Venture owners have approved the recommendations of an Opportunity Assessment Team ("OAT"). Since late 2006, the OAT comprised of experts from Syncrude, Imperial, ExxonMobil and the other Joint Venture owners has been examining possibilities for improvement at Syncrude. In April, the OAT presented their specific recommendations, which were approved by the Syncrude owners. Such approval was required to proceed with implementation of the Management Services Agreement.

The implementation phase will involve the secondment of Imperial and ExxonMobil personnel and perhaps personnel from other owner companies to Syncrude. The secondees will work closely with Syncrude management and staff to assist in the implementation of the Opportunity Assessment Team's recommendations and Imperial/ExxonMobil's global best practices and systems. To lead this effort, Mr. Tom Katinas has been appointed to the role of President and Chief Executive Officer of Syncrude Canada effective May 1, 2007. Mr. Katinas succeeds current CEO, Charles Ruigrok. Mr. Ruigrok will work with Mr. Katinas to ensure a smooth transition of responsibilities.

FINANCIAL RISK MANAGEMENT

Crude Oil Price Risk

As Canadian Oil Sands did not have any crude oil price hedges in 2007 and 2006, revenues were not impacted by crude oil hedging gains or losses and benefited fully from strong WTI prices. As at March 31, 2007 and, based on current expectations, the Trust remains unhedged on its crude oil price exposure.

However, it may hedge its crude oil production in the future as part of growth financing strategies.

Foreign Currency Hedging

As at March 31, 2007, we had $15 million of U.S. dollars hedged at an average U.S. dollar exchange rate of $0.69 US/Cdn. At the present time, we do not intend to increase our currency hedge positions. However, the Trust may hedge foreign 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. At March 31, 2007, we had $120 million drawn on our credit facilities that bear interest at a floating rate based on bankers' acceptances plus a credit spread. The Trust's other floating rate debt was repaid in January.

With the adoption of the new financial instrument accounting rules and the decision to no longer apply hedge accounting, all of the Trust's financial risk management activities are now recorded on its Consolidated Balance Sheet at fair value. The Trust did not have any significant positions outstanding at March 31, 2007.

FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of February 8, 2007, approximately 33 per cent of our Unitholders are non-Canadian residents with the remaining 67 per cent being 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 continues to monitor its foreign ownership levels on a regular basis through declarations from Unitholders. The next declarations to be requested will be as of May 8, 2007. The Trust posts the results of the declarations on its web site at www.cos-trust.com under investor information, frequently asked questions. This section of the web site describes the Trust's steps for managing its non-Canadian resident ownership levels.

ANNOUNCED CHANGES TO ACCELERATED CAPITAL COST ALLOWANCE RULES

On March 19, 2007, the federal government announced, as part of its 2007 budget, plans to phase out accelerated capital cost allowance ("ACCA") for oil sands projects. The ACCA phase-out does not affect the deductibility of costs for oil sands projects but does affect the timing of the deductibility. Currently, most machinery, equipment and structures used to produce income from an oil sands project are eligible for the Class 41 capital cost allowance ("CCA") at a rate of 25 per cent per annum on a declining balance basis. In addition to this regular deduction, an acceleration of the CCA up to income from an oil sands project was available for eligible assets acquired before the beginning of commercial production for major expansions (i.e. greater than 25 per cent) or for the portion of investment expenditures in excess of five per cent of the gross revenue for the year from the project. The acceleration remains available for our existing eligible pools, which amount to approximately 80 per cent of our tax carry forward balances at December 31, 2006. However, acceleration on new Class 41 costs will be phased out gradually over the 2011 to 2015 period. As the proposed phase-out of ACCA will effectively delay the timing of deductibility of future capital costs for income tax purposes, it has a negative impact on the economics of new projects or major expansions.

ALBERTA ANNOUNCES LEGISLATION TO REDUCE GREENHOUSE GAS EMISSIONS

On March 8, 2007, the Alberta government introduced legislation to reduce greenhouse gas emission intensity. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12 per cent over the average emissions levels of 2003, 2004 and 2005; if they are not able to do so, these facilities will be required to pay $15 per tonne for every tonne above the 12 per cent target, beginning July 1, 2007. The payments will be deposited into an Alberta-based technology fund that will be used to develop infrastructure to reduce emissions or to support research into innovative climate change solutions. Large emitters also have the option of investing in projects outside of their operations that reduce or offset emissions on their behalf, providing these projects are Alberta-based and verified by a third party that the emission reductions are real.

The new legislation will apply to the Syncrude project but until all of the specifics regarding its implementation are provided it is difficult to provide an estimate of the cost impact. The federal government also is anticipated to announce legislation to reduce greenhouse gas emissions; however, at this time no information has been provided regarding the specifics of such legislation.

REVIEW OF ALBERTA OIL SANDS ROYALTY

As previously indicated, the Government of Alberta is examining Alberta's royalty and tax regime. In February 2007, the Alberta government appointed an independent panel of experts to conduct a review focusing on all aspects of the royalty system, including oil sands, conventional oil and gas, and coalbed methane. A final report with recommendations will be presented to the Minister of Finance by August 31, 2007. Canadian Oil Sands intends to participate in the process by making a formal presentation at the Royalty Review Panel's public meeting in Fort McMurray on June 4, 2007. At this time, Canadian Oil Sands cannot determine the potential impact of any changes to the royalty rate on its operations.

2007 OUTLOOK

Our single point estimate for 2007 production is unchanged at 110 million barrels, or 40.4 million barrels net to the Trust, which reflects maintenance on Coker 8-3 in May to remove coke residue build-up. Once Coker 8-3 is operating at its design capacity, Syncrude should be able to reduce throughput in Cokers 8-1 and 8-2 and thereby slightly extend these cokers' run lengths. The result is that Syncrude is planning to defer the turnaround of another coker previously scheduled for the fall of 2007 into early 2008 and our annual production target remains unchanged at 110 million barrels. While Syncrude anticipates that the Coker 8-3 maintenance will enable that coker to produce at higher rates, the high end production range of 120 million barrels is less probable, given the reduced run rates for Coker 8-3 for the first part of the year. Consequently, on March 13, 2007, we reduced the high end of our production range by five million barrels from the guidance provided on January 29, 2007 with the current range now between 105 to 115 million barrels, or 39 to 42 million barrels based on our 36.74 per cent interest. The low end of the production range continues to reflect the possibility that another coker turnaround could occur later this year. Syncrude had planned to modify the new hydrogen plant steam generation system in the fall of 2007 but now expects to perform this work coincident with a coker turnaround in order to optimize the efficiency of maintenance work. As a result, the transition of Syncrude's production volumes to the higher Syncrude™ Sweet Premium quality is expected to be delayed into 2008.

The unscheduled Coker 8-3 maintenance work, together with other scheduled maintenance work, is expected to result in Syncrude production totalling 23 million barrels in the second quarter. We estimate production in each of the third and fourth quarters of 2007 to total 30 million barrels.

We have increased our WTI crude oil price estimate for the year to average US$60 per barrel and reduced the discount to Canadian dollar WTI to $2.50 per barrel from $4.00 per barrel. The revision to our differential is based on the differentials realized in the first quarter of the year, and we are estimating positive differentials in the second quarter because of the reduced supply from various oil sands producers undergoing turnarounds and tie-ins, as well as lower relative WTI prices compared to other crude oil benchmarks as a result of market dynamics in the U.S. These estimates, together with a stronger average foreign exchange rate of $0.87 US/Cdn, are expected to result in 2007 revenues totalling $2.7 billion.

Operating costs are estimated at $25.56 per barrel, which includes $7.34 per barrel for purchased energy based on an average AECO natural gas price of $7.75 per gigajoule for 2007. Our practice is to expense turnaround and maintenance costs in the period they are incurred. Accordingly, operating costs are expected to be higher in the second quarter as a result of the Coker 8-3 and other maintenance work. We expect Crown royalties expense to total $333 million, or $8.22 per barrel, in 2007.

We expect cash from operating activities to total $1,098 million, or $2.29 per Unit, including an increase in operating non-cash working capital of $36 million. Capital expenditures are estimated at $251 million with approximately 90 per cent directed to sustaining capital, including $78 million for the SER project. The remaining 10 per cent pertains to Stage 3 completion and modification costs. Free cash flow, defined as cash from operating activities less capital expenditures and reclamation trust contributions, is estimated to be $1.76 per Unit in 2007.

We estimate that virtually all of the distributions paid in 2007 will be taxable as other income. The actual taxability of the 2007 distributions will be determined and reported to Unitholders prior to the end of the first quarter of 2008. The Trust's 2006 distributions were 97 per cent taxable.

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 price differential for SSB relative to crude benchmarks; however, these factors are difficult to predict.



2007 Outlook Sensitivity Cash from Operating Activities

Analysis

Annual(2) Increase

Variable(1) Sensitivity $ millions $/Unit

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Syncrude operating costs

decrease C$1.00/bbl 31 0.06

Syncrude operating costs

decrease C$50 million 14 0.03

WTI crude oil price increase US$1.00/bbl 29 0.06

Syncrude production increase 2 million bbls 31 0.07

Canadian dollar weakening US$0.01/C$ 21 0.04

AECO natural gas price

decrease C$0.50/GJ 15 0.03

(1) An opposite change in each of these variables will result in the

opposite cash from operating activities impacts.

(2) Sensitivities assume a larger change in unrealized quarters to result

in the annual impact.


More information on the Trust's outlook is provided in the April 25, 2007 guidance document, which is available on the Trust's web site at www.cos-trust.com under investor information.



CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(unaudited)

Three Months Ended

March 31

($ millions, except per Unit amounts) 2007 2006

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

Revenues $ 783 $ 516

Crude oil purchases and transportation expense (109) (43)

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

674 473

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

Expenses:

Operating 231 271

Non-production 18 25

Crown royalties 94 5

Administration 4 5

Insurance 3 2

Interest, net (Note 9) 24 25

Depreciation, depletion and accretion 82 50

Foreign exchange loss (gain) (7) 2

Large Corporations Tax and other 1 2

Future income tax recovery (38) (5)

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412 382

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Net income 262 91

Other comprehensive income, net of income taxes

Reclassification of derivative gains to net income (2) -

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

Comprehensive income $ 260 $ 91

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Weighted average Trust Units (millions)(i) 479 463

Trust Units, end of period (millions)(i) 479 464

Net income per Trust Unit(i):

Basic $ 0.55 $ 0.20

Diluted $ 0.55 $ 0.20

(i) Unit information has been adjusted to reflect the 5:1 Unit split,

which occurred on May 3, 2006.

CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY

(unaudited)

Three Months Ended

March 31

($ millions) 2007 2006

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

Retained earnings

Balance at January 1, as previously reported $ 1,692 $ 1,370

Transition adjustment on adoption of Financial

Instruments standards (Note 2) (1) -

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

Balance at January 1, adjusted 1,691 1,370

Net income 262 91

Unitholder distributions (Note 10) (144) (93)

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

Balance at March 31 1,809 1,368

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Accumulated other comprehensive income

Balance at January 1 - -

Transition adjustment on adoption of

Financial Instruments standards (Note 2) 30 -

Other comprehensive income (2) -

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

Balance at March 31 28 -

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

Unitholders' capital

Balance at January 1 2,260 2,010

Issuance of Trust Units (Note 5) 238 43

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

Balance at March 31 2,498 2,053

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Contributed surplus

Balance at January 1 4 3

Stock-based compensation - -

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

Balance at March 31 4 3

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Total Unitholders' equity $ 4,339 $ 3,424

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CANADIAN OIL SANDS TRUST

CONSOLIDATED BALANCE SHEETS

(unaudited)

March December

31 31

($ millions) 2007 2006

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

ASSETS

Current assets:

Cash and cash equivalents $ 65 $ 353

Accounts receivable 341 244

Inventories 95 84

Prepaid expenses 3 7

Derivative assets (Note 2) 5 -

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509 688

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Capital assets, net 6,500 5,739

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Other assets

Goodwill 52 52

Assets held for sale 6 6

Reclamation trust 31 30

Deferred financing charges, net and other

(Note 2) - 17

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89 105

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$ 7,098 $ 6,532

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LIABILITIES AND UNITHOLDERS' EQUITY

Current liabilities:

Accounts payable and accrued liabilities $ 307 $ 304

Current portion of employee future benefits 11 11

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318 315

Employee future benefits and other liabilities 107 100

Long-term debt (Note 2) 1,543 1,644

Asset retirement obligation 181 173

Deferred currency hedging gains (Note 2) - 35

Future income taxes 610 309

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2,759 2,576

Unitholders' equity 4,339 3,956

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$ 7,098 $ 6,532

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CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

Three Months Ended

March 31

($ millions) 2007 2006

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

Cash provided by (used in):

Cash from (used in) operating activities

Net income $ 262 $ 91

Items not requiring outlay of cash:

Depreciation, depletion and accretion 82 50

Foreign exchange on long-term debt (11) 1

Future income tax recovery (38) (5)

Other - 2

Net change in deferred items 1 2

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Funds from operations 296 141

Change in non-cash working capital (94) 46

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Cash from operating activities 202 187

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Cash from (used in) financing activities

Issuance (repayment) of medium term notes (Note 8) (195) -

Net drawdown (repayment) of bank credit facilities 120 (22)

Unitholder distributions (Note 10) (144) (93)

Issuance of Trust Units (Note 5) - 43

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Cash used in financing activities (219) (72)

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Cash from (used in) investing activities

Capital expenditures (33) (137)

Acquisition of additional Syncrude working

interest (Note 4) (231) -

Reclamation trust (1) (1)

Change in non-cash working capital (6) (27)

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Cash used in investing activities (271) (165)

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

Decrease in cash and cash equivalents (288) (50)

Cash and cash equivalents at beginning of period 353 88

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

Cash and cash equivalents at end of period $ 65 $ 38

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

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Cash and cash equivalents consist of:

Cash $ - $ -

Short-term investments 65 38

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

$ 65 $ 38

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2007

(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,

2006, except as discussed in Note 2. The disclosures provided below

are incremental to those included with the annual consolidated

financial statements. 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, 2006.

2) CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2007, Canadian Oil Sands adopted the

requirements of the Canadian Institute of Chartered Accountants

("CICA") related to the new financial instruments accounting

framework, which encompasses the following new CICA Handbook

sections: 3855 Financial Instruments - Recognition and Measurement,

1530 Comprehensive income, and 3861 Financial Instruments -

Disclosure and Presentation. The CICA Handbook section 3865 Hedges is

effective January 1, 2007, however, Canadian Oil Sands has elected

not to apply hedge accounting on a go-forward basis, and, therefore,

has only applied the transitional provisions of this Handbook

section.

These new Handbook sections provide comprehensive requirements for

the recognition and measurement of financial instruments, and

introduce a new component of equity referred to as accumulated other

comprehensive income ("AOCI"). In accordance with the transitional

provisions of all of the new sections, the comparative interim

consolidated financial statements have not been restated.

Under these new standards, all financial instruments, including

derivatives, are recognized on the Trust's Consolidated Balance

Sheet. Derivatives are measured at fair value with unrealized gains

and losses reported in net income. Short-term investments are

measured at fair value with unrealized gains and losses reported in

AOCI. The Trust's other financial instruments (accounts receivable,

accounts payable, and long-term debt) are measured at amortized cost

using the effective interest rate method. Transaction costs are added

to the amount of the associated financial instrument and amortized

accordingly.

Several adjustments to the Trust's consolidated financial statements

were required upon transition to the new financial instruments

framework, which were the following:

Deferred currency hedging gains

In 1996, Canadian Oil Sands entered into currency hedging contracts

to fix the exchange rate in future years. During 1999, Canadian Oil

Sands unwound various positions and exchanged the resulting gains for

adjustments to other existing currency contracts. These gains were

deferred and as at December 31, 2006, the remaining cumulative

deferral of the unrecognized gains was $35 million. Prior to the

adoption of the new standards, the remaining deferral was to be

recognized as revenue over the period 2007 to 2016 which is when the

hedging contracts would have expired had they not been unwound.

On transition, the deferred currency hedging gains of $35 million

were reclassified to opening AOCI. The related future income tax

asset of $10 million was reclassified from Canadian Oil Sands' future

income tax liability to AOCI. The deferred gains included in AOCI

will be amortized on a straight-line basis into net income and

recorded as currency hedging gains in the Trust's revenues over the

period 2007 to 2016, with a corresponding decrease to other

comprehensive income, net of future income tax.

Long-term debt and deferred financing charges

Prior to the adoption of the new standards, the Trust's long-term

debt was recorded at cost. The related financing charges were

included in "Deferred financing charges, net and other" on the

Trust's Consolidated Balance Sheet, and recognized in net income over

the life of the debt.

Under the transitional provisions of Handbook section 3855 Financial

Instruments - Recognition and Measurement, the Trust's long-term debt

is now recorded at amortized cost using the effective interest rate

method. The related financing charges have been included in the cost

of the long-term debt. As a result of these changes, "Deferred

financing charges, net and other" of $16 million, which was

previously recorded as assets of the Trust, were reclassified to

"Long-term debt" on the Consolidated Balance Sheet, and $1 million

was recorded as a decrease to opening retained earnings.

Currency exchange contracts and interest rate swaps

Prior to the adoption of the new standards, one foreign currency

exchange contract with an estimated fair value gain of $6 million was

outstanding. The derivative had been designated as a hedge, and

therefore was not recorded on the Trust's Consolidated Balance Sheet.

Beginning January 1, 2007, Canadian Oil Sands is no longer applying

hedge accounting to any of its hedging activities.

Based on the transitional provisions of Handbook section 3865 Hedges,

the Trust's foreign currency exchange contract was recognized on the

Consolidated Balance Sheet and included in "Derivative assets" at its

estimated fair value of $6 million on January 1, 2007, with a

corresponding increase to opening AOCI. On adoption, a $2 million

increase to the Trust's future income tax liability and a

corresponding reduction to AOCI were also recorded related to the

foreign currency hedge. This foreign currency contract will be

settled by December 31, 2007.

The Trust also has an interest rate swap on its US$70 million Senior

Notes, which did not qualify for hedge accounting prior to January 1,

2007. The $1 million liability representing the unrecognized gains on

the swap was recorded on the Trust's Consolidated Balance Sheet and

included in "Employee future benefits and other liabilities" at

December 31, 2006. On adoption of the new accounting rules on

January 1, 2007, the liability balance was reclassed to opening AOCI.

This interest rate swap will be settled by May 15, 2007.

Determination of fair value

The fair value of the Trust's long-term debt, which is disclosed in

the notes to the Trust's 2006 annual financial statements, and

derivatives are determined based on market price indications.

Comprehensive income

The Consolidated Statement of Income and Comprehensive Income

includes a new line item for comprehensive income, which includes

both net income and other comprehensive income. Other comprehensive

income includes recognition of unrealized gains and losses on

derivatives and hedging gains that were previously deferred, net of

the related future income tax on those items.

3) FUTURE CHANGES IN ACCOUNTING POLICIES

Capital disclosures

The CICA issued a new accounting standard, Section 1535 Capital

Disclosures, which requires the disclosure of both qualitative and

quantitative information that provides users of financial statements

with information to evaluate the entity's objective, policies and

processes for managing capital. This new section is effective for the

Trust beginning January 1, 2008.

Financial Instruments - Disclosure and Financial Instruments -

Presentation

Two new accounting standards were issued by the CICA, Section 3862

Financial Instruments - Disclosures, and Section 3863 Financial

Instruments - Presentation. These sections will replace Section 3861

Financial Instruments - Disclosure and Presentation once adopted. The

objective of Section 3862 is to provide users with information to

evaluate the significance of the financial instruments on the

entity's financial position and performance, the nature and extent of

risks arising from financial instruments, and how the entity manages

those risks. The provisions of Section 3863 deal with the

classification of financial instruments, related interest, dividends,

losses and gains, and the circumstances in which financial assets and

financial liabilities are offset. These new sections are effective

for the Trust beginning January 1, 2008.

4) ACQUISITION OF ADDITIONAL SYNCRUDE WORKING INTEREST

On January 2, 2007, a subsidiary of the Trust closed an acquisition

with Talisman Energy Inc. ("Talisman") to purchase an additional

1.25 per cent indirect working interest in the Syncrude Joint Venture

("Syncrude") for total consideration of $476 million ($468 million

net of $8 million cash acquired), including acquisition-related costs

of approximately $1 million. The transaction price was comprised of

$237.5 million in cash and 8,189,655 Units issued from treasury with

an approximate value at the time of entering the acquisition

agreement of $29 per Unit.

The acquisition has been accounted for as a purchase of assets in

accordance with Canadian GAAP. The Trust has allocated the purchase

price to the assets and liabilities as follows:



Net assets and liabilities assumed

Property, plant and equipment $ 668

Cash 8

Working capital 1

Employee future benefits and other liabilities (8)

Asset retirement obligation (6)

Future income taxes (187)

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$ 476

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Consideration

Cash $ 238

Issuance of Trust Units 237

Acquisition costs 1

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$ 476

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The additional 1.25 per cent working interest that Canadian Oil Sands

acquired was held in a partnership owned by Talisman and a subsidiary

of the Trust. Immediately following Canadian Oil Sand's acquisition

of Talisman's interest in the partnership, the partnership was

dissolved. The dissolution resulted in an adjustment, which increased

Canadian Oil Sands' future income tax liability by $140 million and

correspondingly increased its property, plant and equipment on the

Consolidated Balance Sheet, which was accounted for prospectively.

5) ISSUANCE OF TRUST UNITS

In the three months ended March 31, 2007, approximately 8.2 million

Units were issued for proceeds of $238 million, primarily related to

the acquisition of the 1.25 per cent indirect working interest in

Syncrude.

The following table summarizes Units that have been issued:



Number of

Date Units Amount

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Balance, January 1, 2007 470.9 $ 2,260

Issued for acquisition of additional Syncrude

working interest (non-cash) 8.2 237

Issued on exercise of employee options - 1

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Balance, March 31, 2007 479.1 $ 2,498

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6) 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 retirement

and post-employment benefits to most of its employees. Other post-

employment benefits include certain health care and life insurance

benefits for retirees, their beneficiaries and covered dependents.

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,

2007 and 2006 is based on its 36.74 per cent and 35.49 per cent

working interests in each of those periods, respectively. The costs

have been recorded in operating expense as follows:



Three Months Ended

March 31

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

2007 2006

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Defined benefit plans:

Pension benefits $ 7 $ 7

Other benefit plans 1 1

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$ 8 $ 8

Defined contribution plans - -

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Total Benefit cost $ 8 $ 8

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7) BANK CREDIT FACILITIES

Credit facility

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Extendible revolving term facility (a) $ 40

Line of credit (b) 45

Operating credit facility (c) 800

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$ 885

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a) The $40 million extendible revolving term facility is a 364-day

facility with a one year term out, expiring April 24, 2008. 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.

b) The $45 million line of credit is a one year revolving letter of

credit facility. The amount of this facility was increased during

the quarter to $45 million from $35 million at December 31, 2006.

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 $49 million have been written

against the extendible revolving term facility and line of credit.

c) The $800 million operating facility is a five year facility,

expiring April 27, 2012. 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, 2007, $120 million was drawn on this

facility.

d) Each of the Trust's credit facilities is unsecured. These credit

agreements contain typical covenants relating to the restriction

on 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 0.6 to 1.0, or 0.65 to

1.0 in certain circumstances involving acquisitions.


8) LONG-TERM DEBT

On January 15, 2007, the Trust repaid $175 million of 3.95% medium

term notes and $20 million of floating rate medium term notes.



9) INTEREST, NET

Three Months Ended

March 31

2007 2006

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Interest expense on long-term debt $ 25 $ 26

Interest income and other (1) (1)

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Interest expense, net $ 24 $ 25

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10) UNITHOLDER DISTRIBUTIONS

The Consolidated Statements of Unitholder Distributions is provided

to assist Unitholders in reconciling cash from operating activities

to Unitholder distributions.

Pursuant to Section 5.1 of the Trust Indenture, the Trust is required

to distribute all the income received or receivable by the Trust in a

quarter less expenses and any other amounts required by law or under

the terms of the Trust Indenture. The Trust primarily receives income

by way of a royalty and interest on intercompany loans 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 the 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.



CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF UNITHOLDER DISTRIBUTIONS

(unaudited)

Three Months Ended

March 31

2007 2006

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Cash from operating activities $ 202 $ 187

Add (Deduct):

Capital expenditures (33) (137)

Acquisition of additional Syncrude

working interest (231) -

Change in non-cash working capital(1) (6) (27)

Reclamation trust funding (1) (1)

Change in cash and cash equivalents

and financing, net(2) 213 71

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Unitholder distributions $ 144 $ 93

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Unitholder distributions per Trust Unit(3) $ 0.30 $ 0.20

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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.

(3) Unit information has been adjusted to reflect the 5:1 Unit split,

which occurred on May 3, 2006.

11) SUPPLEMENTARY INFORMATION

Three Months Ended

March 31

2007 2006

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Large Corporations Tax and income tax paid $ - $ 3

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Interest charges paid $ 35 $ 33

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Contact Information

  • Canadian Oil Sands Limited
    Marcel Coutu
    President & Chief Executive Officer
    (403) 218-6200
    (403) 218-6201 (FAX)


    or

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


    or

    Canadian Oil Sands Trust
    2500 First Canadian Centre
    350 - 7 Avenue S.W.
    Calgary, Alberta T2P 3N9
    Website: www.cos-trust.com