Canadian Oil Sands Trust
TSX : COS.UN

Canadian Oil Sands Trust

July 24, 2007 23:59 ET

Canadian Oil Sands Trust Announces Second Quarter Results and a Quarterly Distribution of $0.40 Per Trust Unit

CALGARY, ALBERTA--(Marketwire - July 24, 2007) - Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust" or "we") (TSX:COS.UN) today announced second quarter 2007 results and a quarterly distribution of $0.40 per Trust unit ("Unit") for Unitholders of record on August 7, 2007, payable on August 31, 2007. Second quarter 2007 cash from operating activities was $324 million, or $0.68 per Unit, compared to $209 million, or $0.45 per Unit recorded in the same period of 2006. For the six months ended June 30, 2007, cash from operating activities totalled $526 million, or $1.10 per Unit, up 33 per cent from the same period of 2006.

"We are well positioned to increase our average daily production going into the last half of 2007 with Coker 8-3 operating at design rates following maintenance completed during the second quarter," said Marcel Coutu, President and Chief Executive Officer. "Should WTI prices, and in particular synthetic differentials continue to be strong, cash flow performance for the second half of this year could be rewarding for our Unitholders."

Due mainly to the June substantive enactment of Bill C-52 Budget Implementation Act, 2007, which contains legislative provisions to tax publicly traded income trusts in Canada, the Trust recorded a $665 million future income tax expense, resulting in a net loss for the second quarter 2007 of $395 million, or $0.82 per Unit. For the first half of 2007, a net loss of $133 million, or $0.28 per Unit, was recorded. Comparatively, net income for the second quarter and first half of 2006 was $337 million, or $0.72 per Unit, and $428 million, or $0.92 per Unit, respectively. Future income tax is a non-cash item that has no current impact on our cash from operating activities.

"Although we reported strong cash from operating activities for the second quarter, we also reported the only net loss in our history as a result of accounting for a new tax on income trusts that will take effect in 2011," said Mr. Coutu. "The tax has no immediate cash impact and our financial strength and business remain robust. We continue to believe that the trust structure makes sense for mature energy assets because it supports the efficient development of this resource, thereby providing a valuable contribution to the Canadian economy; accordingly, we plan to continue to work towards a better solution with this or future governments."

In response to the income trust tax changes we have adjusted our financial plan by raising our net debt target to $1.6 billion from $1.2 billion, thereby accelerating fuller payout of free cash flow and conserving tax pools. The Trust currently has approximately $2 billion of tax pools, which under current business conditions and capital structure, we estimate will shelter cash taxes for an additional one to two years beyond the January 1, 2011 effective trust tax date. The Trust is moving towards fuller payout of its free cash flow unless capital investment growth opportunities exist that offer Unitholders better value.

Canadian Oil Sands will evaluate our alternatives as to the best structure for our Unitholders, including consideration of a corporate structure. In Alberta where the Trust is registered, a corporation is subject to a lower overall tax rate than the 31.5 per cent tax that will apply to income trusts post-2010. We will also consider other options that may emerge based on further information from the federal government on details of the legislation and the transition rules. Canadian Oil Sands continues to be a long-term value investment in the oil sands and does not rely on the tax efficiency of a flow-through trust model to sustain its business. Our long-life reserves and non-declining production profile provide a solid foundation for future distributions.

Second Quarter and Year-to-Date 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 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 14 per cent, averaging about 98,700 barrels

per day, in the second quarter of 2007 compared to the same 2006

period. Year-to-date, daily sales averaged about 103,800 barrels in

2007 compared to 80,700 barrels in the prior year. The Trust's larger

Syncrude ownership and incremental production from Stage 3

contributed to higher volumes in 2007. Maintenance work on Cokers 8-2

and 8-3 and other units reduced production in 2007 while an extensive

maintenance schedule with turnarounds of several units, including an

extended turnaround of Coker 8-1, reduced production in the first six

months of 2006.

- Operating costs increased $1.65 per barrel to $30.13 per barrel in

the second quarter of 2007 compared with the same quarter last year

mainly due to a higher level of maintenance activity; however, on a

year-to-date basis, operating costs declined more than $7 a barrel to

$26.70 per barrel compared with 2006, principally reflecting lower

relative turnaround and maintenance activity spread over higher

production volumes in the six-month period.

- Net debt at June 30, 2007 was about $1.3 billion for a net debt to

book capitalization of 26 per cent, largely unchanged from the end of

2006.

- The Trust is maintaining its single point estimate for 2007

production of 110 million barrels, or about 40 million barrels net to

the Trust, with a production range of 105 to 115 million barrels, or

39 to 42 million barrels net to the Trust. More information on the

Trust's outlook is provided in the Management's Discussion and

Analysis section of the second quarter 2007 report and the July 24,

2007 guidance document, which is available on the Trust's web site at

www.cos-trust.com under "investor information".



CANADIAN OIL SANDS TRUST

Highlights

(millions of Canadian Three Months Ended Six Months Ended

dollars, except Trust June 30 June 30

unit and volume amounts) 2007 2006 2007 2006

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Net Income (Loss) $ (395) $ 337 $ (133) $ 428

Per Trust unit - Basic $ (0.82) $ 0.72 $ (0.28) $ 0.92

Per Trust unit - Diluted $ (0.82) $ 0.72 $ (0.28) $ 0.92

Cash from Operating

Activities $ 324 $ 209 $ 526 $ 396

Per Trust unit $ 0.68 $ 0.45 $ 1.10 $ 0.85

Unitholder Distributions $ 191 $ 139 $ 335 $ 232

Per Trust unit $ 0.40 $ 0.30 $ 0.70 $ 0.50

Syncrude Sweet Blend

Sales Volumes (1)

Total (MMbbls) 9.0 7.9 18.8 14.6

Daily average (bbls) 98,720 86,394 103,822 80,693

Operating Costs per barrel $ 30.13 $ 28.48 $ 26.70 $ 33.92

Net Realized Selling Price

per barrel

Realized selling price

before hedging $ 76.41 $ 78.33 $ 72.26 $ 74.09

Currency hedging gains 0.40 1.02 0.30 1.04

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Net realized selling

price $ 76.81 $ 79.35 $ 72.56 $ 75.13

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West Texas Intermediate

(average $US per barrel)(2) $ 65.02 $ 70.72 $ 61.68 $ 67.13

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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.


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") was prepared as of July 24, 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 six months ended June 30, 2007 and June 30, 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 expected impact on the Trust from the announced changes to the federal government's taxation of income trusts; the expected timeframe that current tax pools will allow Canadian Oil Sands to shelter income post-2010; the plan to move to fuller payout of free cash flow; the potential alternatives to structure; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2007 for Canadian Oil Sands' product; the potential amount payable in respect of any future income tax liability; 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 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 expectation that the SER project will significantly reduce total sulphur dioxide and other emissions; the intention to refinance the debt coming due in April 2008; the expected cost and impact of Alberta and federal government legislation and proposed environmental legislation on the Trust; 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 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 current and 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. 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. To the extent that changes, including the Bill C-52 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 second quarter of 2007, the Syncrude Joint Venture ("Syncrude") oil production totalled 23.9 million barrels, or an average of 263,000 barrels per day, compared to 21.9 million barrels, or 241,000 barrels per day, during the same period of 2006. Second quarter 2007 production was slightly higher than the 23 million barrel estimate provided in our April 25, 2007 guidance document, which had incorporated maintenance on Coker 8-3 and other units. Net to the Trust, production totalled 8.8 million barrels in the second quarter of 2007 based on our 36.74 per cent working interest compared with 7.8 million barrels in 2006 based on a 35.49 per cent interest.

Syncrude performed maintenance on Coker 8-3 in the second quarter of 2007 to remove coke residue build-up within the vessel that had been constraining production from the unit since late 2006. This coker resumed operations in June and is now producing at design rates, enabling Syncrude to reduce rates on Cokers 8-1 and 8-2, as planned. In addition, Syncrude performed planned maintenance on various other units, including a turnaround of the LC-Finer, which also reduced production in the quarter. During the comparable quarter of 2006, production was affected by an extended Coker 8-1 turnaround, although the impact was somewhat offset by incremental volumes from Coker 8-3 during its initial startup.

Canadian Oil Sands' operating costs were $30.13 per barrel in the second quarter of 2007 compared with $28.48 per barrel in the same quarter last year, mainly reflecting higher production costs and more turnaround and maintenance activity quarter-over-quarter (see the "Operating Costs" section of this MD&A for further discussion).

On a year-to-date basis, Syncrude produced 50.5 million barrels in 2007, an increase of 25 per cent from the same period in 2006. Average daily production of 279,000 barrels in 2007, compared with 223,000 barrels in the prior year, primarily reflects the additional Coker 8-3 volumes. Production in the first half of 2007 was impacted by unplanned maintenance on Cokers 8-2 and 8-3, other planned maintenance work, and constrained production rates from Coker 8-3 prior to its maintenance. Comparatively, in the first half of 2006, Coker 8-3 was operating for only about 10 days before being suspended to perform work on the associated flue gas desulphurization unit. Production from Coker 8-3 did not resume until September and therefore the coker did not contribute significant volumes in the first half of 2006. In addition, an extensive maintenance schedule with turnarounds of several units, including an extended turnaround of Coker 8-1, reduced production in the first six months of 2006.

Operating costs in the first half of 2007 were $26.70 per barrel, a decrease of more than $7 a barrel from the same period in 2006. While costs in both years reflect coker turnarounds, 2007 had less extensive turnaround and maintenance activity and more production, contributing to lower per barrel operating costs relative to 2006. As well, operating costs in 2007 reflect lower Syncrude long-term incentive compensation and lower purchased energy costs, as discussed more fully in the "Operating Costs" section of this MD&A.

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 2007 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) Q2 Q1 Q4 Q3 Q2 Q1

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Revenues(1) $ 690 $ 674 $ 646 $ 689 $ 624 $ 473

Net income (loss) $ (395) $ 262 $ 128 $ 278 $ 337 $ 91

Per Trust Unit,

Basic(2) $ (0.82) $ 0.55 $ 0.27 $ 0.60 $ 0.72 $ 0.20

Per Trust Unit,

Diluted(2) $ (0.82) $ 0.55 $ 0.27 $ 0.59 $ 0.72 $ 0.20

Cash from operating

activities $ 324 $ 202 $ 412 $ 334 $ 209 $ 187

Per Trust

Unit(2) $ 0.68 $ 0.42 $ 0.88 $ 0.72 $ 0.45 $ 0.40

Daily average

sales volumes

(bbls) 98,720 108,981 110,185 95,438 86,394 74,929

Net realized selling

price ($/bbl) $ 76.81 $ 68.69 $ 63.71 $ 78.43 $ 79.35 $ 70.24

Operating costs

($/bbl) $ 30.13 $ 23.56 $ 23.60 $ 19.68 $ 28.48 $ 40.26

Purchased natural

gas price ($/GJ) $ 6.78 $ 6.99 $ 6.51 $ 5.42 $ 5.72 $ 7.42

($ millions, except

per Trust Unit and 2005

volume amounts) Q4 Q3

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Revenues(1) $ 519 $ 612

Net income (loss) $ 174 $ 380

Per Trust Unit,

Basic(2) $ 0.38 $ 0.83

Per Trust Unit,

Diluted(2) $ 0.37 $ 0.83

Cash from operating

activities $ 281 $ 364

Per Trust

Unit(2) $ 0.61 $ 0.79

Daily average

sales volumes

(bbls) 78,318 85,942

Net realized selling

price ($/bbl) $ 72.07 $ 77.43

Operating costs

($/bbl) $ 25.54 $ 23.61

Purchased natural

gas price ($/GJ) $ 10.73 $ 8.31

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

- The substantive enactment in June 2007 of Bill C-52 Budget

Implementation Act, 2007 ("Bill C-52" or "trust taxation") resulted

in a future income tax expense of $665 million in the second quarter

of 2007. Canadian Oil Sands is now required to record future income

tax related to temporary differences at the Trust level, which

represent the differences between the accounting and tax basis of the

Trust's net assets. This is a non-cash expense that has no current

impact on the Trust's cash from operating activities.

- 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 half of 2007. As the transition

occurred in May 2006, Crown royalties in the second quarter of 2006

did not reflect the full impact of the rate increase.

- Starting in 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.

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 second quarter of 2007 and 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.



REVIEW OF FINANCIAL RESULTS

Three Months Ended Six Months Ended

June 30 June 30

($ per bbl) 2007 2006 $ Change 2007 2006 $ Change

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Net realized

selling price 76.81 79.35 (2.54) 72.56 75.13 (2.57)

Operating costs (30.13) (28.48) (1.65) (26.70) (33.92) 7.22

Crown royalties (9.94) (3.82) (6.12) (9.75) (2.37) (7.38)

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Netback 36.74 47.05 (10.31) 36.11 38.84 (2.73)

Non-production costs (1.72) (2.45) 0.73 (1.75) (3.06) 1.31

Administration and

insurance (0.83) (0.68) (0.15) (0.74) (0.85) 0.11

Interest, net (2.50) (3.18) 0.68 (2.49) (3.42) 0.93

Depletion,

depreciation

and accretion (8.51) (7.57) (0.94) (8.50) (7.52) (0.98)

Foreign exchange gain 6.98 5.84 1.14 3.75 3.03 0.72

Future income tax

recovery (expense)

and other (74.06) 4.00 (78.06) (33.46) 2.35 (35.81)

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(80.64) (4.04) (76.60) (43.19) (9.47) (33.72)

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Net income (loss)

per barrel (43.90) 43.01 (86.91) (7.08) 29.37 (36.45)

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Sales volumes

(MMbbls) 9.0 7.9 1.1 18.8 14.6 4.2

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As a consequence of Bill C-52, Canadian Oil Sands recorded a $665 million future income tax expense in the second quarter of 2007, which resulted in a net loss of $395 million, or $0.82 per Trust Unit ("Unit"). Future income taxes and the impact of the tax legislation are more fully discussed later in this MD&A. Comparatively, the Trust recorded net income of $337 million, or $0.72 per Unit in the same period of 2006.

The Trust's cash from operating activities was $324 million, or $0.68 per Unit, an increase of $115 million or $0.23 per Unit relative to the same period of 2006. A reduction in non-cash working capital requirements (primarily accounts receivable) in the second quarter of 2007 relative to the same quarter of 2006 increased cash from operating activities by $172 million quarter-over-quarter, as shown in the table below. In the second quarter of 2007, the decrease in our accounts receivable balance at June 30 relative to March 31, 2007 was attributable to lower June sales volumes as a result of the maintenance activity in that month, offset somewhat by a higher realized selling price. Conversely, a significantly higher accounts receivable balance at June 30, 2006 relative to the prior quarter-end reflected a substantial increase in sales volumes as well as a higher net realized selling price.



Three Months Ended Six Months Ended

June 30 June 30

Change in: 2007 2006 2007 2006

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Accounts receivable $ 31 $ (136) $ (66) $ (99)

Inventories - 7 (11) 14

Prepaid expenses - (1) 4 1

Accounts payable and

accrued liabilities 34 (1) 37 (27)

Less: A/P reclassed to

investing and other (8) 16 (1) 42

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Change in non-cash working

capital $ 57 $ (115) $ (37) $ (69)

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Incremental Stage 3 production and a larger Syncrude working interest in the second quarter of 2007 relative to the prior year contributed to a $66 million increase in revenues (after crude oil purchases and transportation expense) to $690 million in 2007 compared to 2006. Also benefiting earnings before taxes in the second quarter of 2007 was a $17 million increase in foreign exchange gains relative to the same period of 2006, primarily related to unrealized foreign exchange gains on the translation of U.S. dollar denominated long-term debt. The revenue and foreign exchange gain increases were more than offset by higher operating costs, Crown royalties, depreciation, depletion and accretion ("DD&A") expense, and future income tax expense, resulting in lower net income (loss) quarter-over-quarter. Operating costs in the second quarter of 2007 increased to $271 million, or $30.13 per barrel, from $224 million, or $28.48 per barrel, in the comparable period of 2006, as summarized in the previous "Review of Syncrude Operations" section of this MD&A. Crown royalties were $60 million higher in the second quarter of 2007 relative to the same quarter of 2006 as a result of the increase in Crown royalty rates and larger net revenues, which reflected increased production and a larger Syncrude working interest. DD&A expense rose by $17 million quarter-over-quarter as a result of increased production volumes and a higher depreciation and depletion rate. Cash from operating activities was similarly affected, excluding the impacts of the unrealized foreign exchange gains, DD&A and future income tax expense increases as these are non-cash items.

In the first half of 2007, the Trust recorded a net loss of $133 million, or $0.28 per Unit, compared with net income of $428 million, or $0.92 per Unit, in the same six-month period of 2006. Cash from operating activities increased by 33 per cent and totalled $526 million, or $1.10 per Unit, in the six months ended June 30, 2007 relative to the same period of 2006. Changes in non-cash working capital increased cash from operating activities by $32 million year-over-year, as shown in the previous table.

Revenues and foreign exchange gains increased by $267 million and $26 million, respectively, in the first half of 2007 relative to the same period in the prior year. The increase in sales volumes on a year-to-date basis contributed to the substantial rise in revenues, which totaled $1.4 billion in 2007. The higher foreign exchange gains is primarily attributable to an increase in unrealized gains recorded on the revaluation of our U.S. dollar denominated debt. The 2007 revenue and foreign exchange gains increases were more than offset by higher Crown royalties of $149 million, an increase in DD&A expense of $49 million, and a $662 million increase to future income tax expense, resulting in the 2007 net loss. The changes in revenues and Crown royalties also impacted cash from operating activities, unlike the unrealized foreign exchange gains, DD&A expense, and future income tax expense which are all non-cash items.

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 Six Months Ended

June 30 June 30

($ millions) 2007 2006 Variance 2007 2006 Variance

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Sales revenue(1) $ 804 $ 707 $ 97 $ 1,585 $ 1,216 $ 369

Crude oil purchases (109) (80) (29) (208) (114) (94)

Transportation

expense (9) (11) 2 (19) (20) 1

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686 616 70 1,358 1,082 276

Currency hedging

gains(1) 4 8 (4) 6 15 (9)

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$ 690 $ 624 $ 66 $ 1,364 $ 1,097 $ 267

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Sales volumes

(MMbbls)(2) 9.0 7.9 1.1 18.8 14.6 4.2

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

on the Trust's Consolidated Statement of Income (Loss) and

Comprehensive Income (Loss).

(2) Sales volumes, net of purchased crude oil volumes.

($ per barrel)

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Realized selling

price before

hedging(3) $ 76.41 $ 78.33 $ (1.92) $ 72.26 $ 74.09 $ (1.83)

Currency hedging

gains 0.40 1.02 (0.62) 0.30 1.04 (0.74)

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Net realized

selling price $ 76.81 $ 79.35 $ (2.54) $ 72.56 $ 75.13 $ (2.57)

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(3) Sales revenue after crude oil purchases 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 second quarter and first half of 2007 primarily reflects increased sales volumes relative to the comparable periods of 2006. The Trust's larger Syncrude ownership and incremental production from the Stage 3 facilities during the second quarter and first six months of 2007 resulted in the higher 2007 sales volumes.

While 2007 sales volumes increased substantially on both a quarterly and year-to-date basis relative to 2006, the increase to revenues was partially offset by a decrease in our realized SSB selling price in both periods of 2007. Our average realized selling price before currency hedging of $76.41 per barrel in the second quarter of 2007 was $1.92 per barrel lower than the comparable period in 2006. West Texas Intermediate ("WTI") prices, which our SSB pricing has historically closely followed, averaged approximately US$65 per barrel in the second quarter of 2007, a decrease of almost $6 per barrel compared to the same quarter of 2006. This decrease was augmented by a strengthening of the Canadian dollar relative to the U.S. dollar, which averaged $0.91 US/Cdn in the second quarter of 2007 compared to $0.89 US/Cdn in the same quarter of 2006. However, somewhat offsetting the WTI price and exchange rate movements was a significant improvement in our pricing differential relative to WTI. Our SSB product realized a weighted-average premium of $4.85 per barrel compared to average Canadian dollar WTI in the second quarter of 2007 versus a discount of $0.94 per barrel in the same period in 2006. The positive differential in the second quarter of 2007 reflects both the reduced supply of synthetic crude oils in the market from various producers (including Syncrude) undergoing turnarounds, as well as a dislocation of WTI to the price of other light, sweet crude oils traded globally. WTI prices have been lower relative to other light, sweet crudes due to an oversupply of WTI crude in its clearing market at Cushing, Oklahoma and limited pipeline capacity to move it to alternative regions. One of the main factors contributing to the oversupply was unplanned refinery maintenance, which led to high storage levels.

On a year-to-date basis, our net realized selling price before currency hedging gains averaged $72.26 per barrel, $1.83 per barrel lower than the same period in 2006. While average WTI prices were US$5.45 per barrel lower in the first half of 2007 compared to the same period in 2006, averaging US$61.68 per barrel, we realized a premium to average Canadian dollar WTI of $2.28 per barrel in 2007 relative to a discount of $2.53 per barrel in 2006. The pricing in the first half of 2007 substantially reflected the same factors that impacted pricing in the second quarter of 2007. By comparison, in the first half of 2006, primarily in the first quarter, the average discount reflected reduced product demand as a result of refinery outages, increased supply of light crude oil resulting from a pipeline reconfiguration, and downward pressure on SSB prices due to limited pipeline capacity to move crude oil to extended markets. The shift in differentials from discounts to premiums can happen quickly depending on the short-term supply/demand dynamics in the marketplace and pipeline availability for transporting the crude oil.



Operating costs

Three Months Ended Six Months Ended

June 30 June 30

2007 2006 2007 2006

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

Bitumen SSB Bitumen SSB Bitumen SSB Bitumen SSB

Bitumen Costs(1)

Overburden

removal 2.10 2.33 1.88 2.74

Bitumen

production(2) 8.63 7.83 8.52 8.60

Purchased

energy(2,4) 2.53 2.83 2.65 3.28

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13.26 16.43 12.99 15.11 13.05 15.90 14.62 16.97

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Upgrading Costs(3)

Bitumen processing

and upgrading(2) 5.26 4.81 5.04 4.98

Turnaround and

catalysts 2.90 2.19 1.91 4.61

Purchased energy(4) 2.32 3.17 2.59 3.59

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10.48 10.17 9.54 13.18

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Other and research(2) 2.39 2.12 1.15 2.79

Change in treated

and untreated

inventory 0.14 0.52 (0.22) 0.70

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Total Syncrude

operating costs 29.44 27.92 26.37 33.64

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Canadian Oil Sands

adjustments(5) 0.69 0.56 0.33 0.28

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Total operating costs 30.13 28.48 26.70 33.92

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(thousands

of barrels

per day) Bitumen SSB Bitumen SSB Bitumen SSB Bitumen SSB

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Syncrude

production

volumes 325 263 280 241 339 279 259 223

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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) Prior year information has been restated for comparative purposes to

conform to a revised presentation of costs between bitumen, upgrading

and other and research starting in the second quarter of 2007.

(3) 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, all of which are expensed as incurred.

(4) Natural gas costs averaged $6.78/GJ and $5.72/GJ in the second

quarters of 2007 and 2006, respectively. For the first six months of

the year, natural gas costs averaged $6.90/GJ and $6.51/GJ in 2007

and 2006, respectively.

(5) 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 Six Months Ended

June 30 June 30

($/bbl of SSB) 2007 2006 2007 2006

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Production costs 24.68 22.02 20.88 26.52

Purchased energy 5.45 6.46 5.82 7.40

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Total operating costs 30.13 28.48 26.70 33.92

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(GJs/bbl of SSB)

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Purchased energy consumption 0.80 1.13 0.84 1.14

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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. Turnaround and maintenance work performed during the second quarter of 2007 increased per barrel operating costs by $0.71 quarter-over-quarter, mitigated somewhat by an increase in production volumes.

Per barrel natural gas consumption decreased by 28 per cent quarter-over-quarter, resulting in about a $1.00 per barrel decrease in purchased energy costs in the second quarter of 2007 relative to the same period in 2006, despite higher natural gas prices, which averaged $6.78 per gigajoule ("GJ") in the second quarter of 2007 compared with $5.72/GJ in the same quarter of 2006. The considerable improvement in energy consumption quarter-over-quarter highlights the inefficiency of the operations in the second quarter of 2006 as the Stage 3 operations were being commissioned and brought into service without an offsetting increase in SSB production.

On a year-to-date basis, operating costs averaged $26.70 per barrel in 2007, a reduction of $7.22 per barrel compared to the same period in 2006. While coker turnarounds occurred in both years, 2007 experienced less turnaround and maintenance activity and greater production in the first six months relative to the prior year, which reduced operating costs by $2.70 per barrel. A smaller increase in the value of Syncrude's long-term incentive plan relative to 2006 also contributed to lower operating costs in 2007 by almost $1.70 per barrel and is reflected in the "Other and research" line in the operating costs table. 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 half of 2007 relative to the same period in 2006.

Purchased energy costs also fell by $1.58 in the first half of 2007 relative to 2006 due to lower consumption volumes, offset somewhat by higher natural gas prices. Energy consumption decreased by 26 per cent on a per barrel basis in 2007, primarily due to the commissioning of Stage 3 units during the first half of 2006.

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 second quarter of 2007, non-production costs totalled $15 million, a decrease of $5 million from the same quarter in 2006, mainly reflecting the completion of the Stage 3 project, but offset somewhat by a larger working interest ownership and more spending on R&D projects in 2007. On a year-to-date basis, non-production costs totalled $33 million, $12 million lower than the prior year period. Stage 3 contributed $7 million of commissioning and start-up costs in the second quarter of 2006, and $19 million in the first half of that year.

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 $60 million to $89 million, or $9.94 per barrel, in the second quarter of 2007 from $29 million, or $3.82 per barrel, in the comparable 2006 quarter. On a year-to-date basis, Crown royalties increased by $149 million to total $183 million, or $9.75 per barrel in 2007, relative to the prior year which reported $34 million, or $2.37 per barrel. The increase in 2007 Crown royalties reflects a larger Syncrude working interest, in addition to the shift to the higher royalty rate, which occurred in the second quarter of 2006, and higher net revenues as a result of incremental Stage 3 production volumes and lower capital costs eligible for Crown royalty deduction. 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. Alberta's oil sands royalty regime is currently under review by the Provincial Government, as discussed in further detail in the "Review of Alberta Oil Sands Royalty" section of this MD&A.



Three Months Ended Six Months Ended

June 30 June 30

($ millions) 2007 2006 2007 2006

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Depreciation and depletion

expense $ 74 $ 58 $ 154 $ 106

Accretion expense 3 2 5 4

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$ 77 $ 60 $ 159 $ 110

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Depreciation and depletion ("D&D") expense for the second quarter and first half of 2007 rose by $16 million and $48 million, respectively, compared to the same periods of 2006, reflecting an increase in production volumes and a higher per barrel D&D rate. In 2007 our D&D rate increased by about $1 per barrel from the prior year to approximately $8.30 per barrel. The increase reflects the additional assets and reserves acquired in the January acquisition of an additional 1.25 per cent Syncrude working interest, as well as the updated reserve and higher future development cost estimates provided for in the Trust's December 31, 2006 independent reserves report, which reflect a higher cost environment relative to the prior year.

The Trust's reserves report is summarized 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 gain

Three Months Ended Six Months Ended

June 30 June 30

($ millions) 2007 2006 2007 2006

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Unrealized foreign exchange

(gain) $ (76) $ (49) $ (87) $ (48)

Realized foreign exchange loss 13 3 17 4

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Total foreign exchange

(gain) $ (63) $ (46) $ (70) $ (44)

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Foreign exchange rates as at:

($US/$Cdn) 2007 2006 2005

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June 30 $ 0.94 $ 0.90

March 31 $ 0.87 $ 0.86

December 31 $ 0.86 $ 0.86


Foreign exchange ("FX") gains/losses are primarily the result of revaluations of our U.S. dollar denominated long-term debt caused by fluctuations in U.S. and Canadian dollar exchange rates. These resulting unrealized FX gains/losses impact net income, but do not affect cash from operating activities as they are non-cash items. Other FX gains/losses are created through the revaluation of cash, accounts receivable and payable balances denominated in U.S. dollars, which impact both net income and cash from operating activities as these gains/losses are considered realized. Realized FX gains/losses also result from repayment of U.S. dollar denominated balances, such as long-term debt, in which case the resulting FX impacts are included in financing activities on the Trust's Consolidated Statement of Cash Flows.

In the second quarters of 2007 and 2006, Canadian Oil Sands' total FX gains primarily related to the revaluation of our U.S. dollar denominated debt. The debt revaluation in the second quarter of 2007 resulted in an unrealized FX gain of $76 million, reflecting a significant strengthening of the Canadian dollar on June 30, 2007 from March 31, 2007. By comparison, the appreciation of the Canadian dollar was less on June 30, 2006 compared with March 31, 2006, resulting in an unrealized FX gain of $49 million in the second quarter of 2006. Also included in the second quarter of 2007 was an $18 million FX gain realized upon repayment of US$70 million of Senior Notes in May 2007. The debt was originally issued in 1997 when the FX rate was $0.73 US/Cdn and was repaid in 2007 when the Canadian dollar had strengthened considerably to $0.91 US/Cdn. The significant strengthening of the Canadian dollar in the second quarter of 2007 also resulted in a realized loss of $31 million, compared to a $3 million loss in the same period of 2006, primarily attributable to U.S. dollar denominated accounts receivable and cash balances.

In the first half of 2007, FX gains increased by $26 million relative to the same period in 2006. Unrealized foreign exchange gains resulting from debt revaluations accounted for $87 million and $48 million of the total FX gains in each of the first six month periods of 2007 and 2006, respectively, reflecting a stronger Canadian dollar at the end of June relative to December 31 of 2006 and 2005, respectively.

Future Income Tax and other

Canadian Oil Sands recorded a future income tax expense of $665 million in the second quarter of 2007, accounting for the largest change in the Trust's net income (loss) quarter-over-quarter and on a year-to-date basis in 2007 relative to the prior year. The second quarter expense reflects the impact of the trust tax legislation, partially offset by a future income tax recovery at the subsidiary level relating to the federal tax rate reduction to 18.5 per cent in 2011, and changes to taxable temporary differences relative to the comparable quarter in 2006.

With the June 2007 substantive enactment of Bill C-52, a new 31.5 per cent tax will be applied to distributions from Canadian public trusts starting in 2011. As a result, Canadian Oil Sands recorded an additional $701 million future income tax expense and corresponding future income tax liability related to the differences between the accounting and tax basis of the Trust's assets. Prior to this legislation, Canadian Oil Sands' future income taxes reflected only those temporary differences in the Trust's subsidiary. While net income in the second quarter of 2007 was reduced significantly by this future tax adjustment, there was no impact on cash from operating activities.

In response to the income trust tax changes, Canadian Oil Sands has adjusted its financial plan by raising our net debt target to $1.6 billion from $1.2 billion, which accelerates fuller payout of free cash flow and conserves tax pools. The Trust currently has approximately $2 billion of tax pools that, under current business conditions and capital structure, we estimate will shelter cash taxes for an additional one to two years beyond the January 1, 2011 effective trust tax date. The Trust is moving towards fuller payout of its free cash flow unless capital investment growth opportunities exist that offer Unitholders better value.

Canadian Oil Sands will evaluate its alternatives as to the best structure for its Unitholders, including consideration of a corporate structure. In Alberta where the Trust is registered, a corporation is subject to a lower overall tax rate than the 31.5 per cent tax that will apply to income trusts post-2010. We will also consider other options that may emerge based on further information from the federal government on details of the legislation and the transition rules. Canadian Oil Sands continues to be a long-term value investment in the oil sands and does not rely on the tax efficiency of a flow-through trust model to sustain our business. Our long-life reserves and non-declining production profile provide a solid foundation for future distributions.

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 Syncrude 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.

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 second quarter of 2007, capital expenditures totalled $50 million, comparable to expenditures of $59 million in the same quarter of 2006. The Syncrude Emissions Reduction ("SER") project accounted for $19 million of the capital spent in the second quarter of 2007 with the remaining $31 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, costs were still being incurred for the Stage 3 expansion, which comprised approximately 28 per cent of that quarter's capital expenditures. Sustaining capital, including $9 million spent on the SER project, made up the balance of the 2006 quarter's expenditures. Sustaining capital expenditures on a per barrel basis were approximately $5.35 and $4.90 in the second quarters of 2007 and 2006, respectively.

In the first half of 2007, capital expenditures totalled $83 million, less than half of the capital costs incurred in the same period of 2006, as a result of the Stage 3 completion in 2006. In the six months ended June 30, 2006, Stage 3 costs amounted to $114 million. Sustaining capital expenditures on a year-to-date basis were approximately $4.40 per barrel in 2007 and were lower than the same period of 2006, which totalled $5.25 per barrel, primarily as a result of timing of capital expenditures. Canadian Oil Sands' revised capital expenditure guidance as discussed in the Outlook section of this MD&A estimates sustaining capital expenditures in 2007 will total approximately $5.45 per barrel.

Syncrude is undertaking the SER project to retrofit technology into the operation of Syncrude's original two cokers to significantly reduce total sulphur dioxide and other emissions. While expenditures on the SER project are currently estimated at approximately $772 million, or $284 million net to the Trust based on its 36.74 per cent working interest, there are early indications of upward cost pressure on the project. Syncrude is currently performing a fulsome review of the project and will provide updates to cost estimates and timing after the review has been completed. The Trust's share of the SER project expenditures incurred to date, including amounts expensed, is approximately $71 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 approximately $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.

At the end of May 2007, Canadian Oil Sands completed the sale of the remaining conventional properties it acquired in 2006 from Canadian Arctic Gas Ltd, formerly Canada Southern Petroleum Ltd. The conventional properties which the Trust owned up to May 31, 2007 did not generate material income in 2007 and is reflected in "Discontinued operations" on the Trust's Consolidated Statement of Income (Loss) and Comprehensive Income (Loss).

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 2007 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 year 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 June 30, 2007.



LIQUIDITY AND CAPITAL RESOURCES

June 30 December 31

($ millions) 2007 2006

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Long-term debt $ 1,337 $ 1,644

Cash and cash equivalents (33) (353)

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Net debt $ 1,304 $ 1,291

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Unitholders' equity $ 3,752 $ 3,956

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Total capitalization(1) $ 5,056 $ 5,247

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(1) Net debt plus Unitholders' equity

Net debt to total capitalization (%) 26 25

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In January 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 acquisition was followed by the maturity of $195 million of medium term notes on January 15, 2007 and US$70 million of Senior Notes on May 15, 2007, resulting in debt repayments of $272 million in the first half of 2007. The debt repayments were financed by drawing on the Trust's $800 million operating credit facility, of which $202 million was paid down, leaving $70 million drawn at June 30, 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 $87 million, the Trust's long-term debt decreased by $307 million to $1.3 billion at quarter-end, while net debt remained at approximately $1.3 billion because of the reduced cash balance.

As at June 30, 2007, the Trust's unutilized credit facilities amounted to $753 million, including amounts drawn on its $40 million revolving term facility. The Trust has a $150 million medium term note maturing on April 9, 2008, which the Trust currently anticipates refinancing using its available credit facilities when the debt matures.

The Units issued from treasury in January to partially fund the additional Syncrude working interest acquisition 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. Unitholders' equity was reduced by the net loss of $133 million, in addition to the distributions of $335 million recorded on a year-to-date basis.

The $324 million of cash generated by the Trust's operating activities in the second quarter of 2007 was more than adequate to pay distributions of $191 million, or $0.40 per Unit, on May 31 and to fund $40 million of investing activities. As indicated in previous disclosures, 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 $209 million was insufficient to fund distributions of $139 million, or $0.30 per Unit, and investing activities of $77 million. The shortfall was supplemented with DRIP equity financing of $68 million in the quarter.

The Trust's free cash flow rose $123 million to total $272 million, or $0.57 per Unit, in the second quarter of 2007 compared to the same period of 2006. The increase primarily reflects the reduction of the Trust's non-cash working capital requirements quarter-over-quarter, offset somewhat by increased Crown royalties expense.

In the first six months of 2007, the Trust's cash from operating activities of $526 million was more than sufficient to pay distributions of $335 million, or $0.70 per Unit in total, and to fund $80 million of investing activities, excluding the acquisition of the additional Syncrude working interest. Accordingly, the Trust's free cash flow totalled $440 million, or $0.92 per Unit, for the six months ended June 30, 2007. The Trust's cash from operating activities in the first half of 2006 of $396 million, or $0.85 per Unit, was not adequate to fund a $0.50 per Unit distribution, or $232 million, and investing activities of $242 million. The DRIP provided $110 million of additional financing to fund the shortfall. Free cash flow in the first half of 2006 was $198 million, or $0.43 per Unit.

A Unitholder distribution schedule pertaining to the quarter ended June 30 is included in Note 11 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 July 24, 2007, the Trust declared a distribution of $0.40 per Unit for total distributions of $192 million. The distribution will be paid on August 31, 2007 to Unitholders of record on August 7, 2007. The Trust increased its quarterly distribution by 33 per cent to $0.40 per Unit in the first quarter of 2007. The Trust previously indicated it intends to move to fuller payout of its free cash flow while targeting a long-term 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, FX rates and Syncrude operational performance vary from our assumptions. In addition to the current and expected operating conditions, Canadian Oil Sands will continue to monitor WTI prices and differentials in particular, which have become highly variable, for at least another quarter or two before reassessing its distribution level.

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 26 per cent, a significant increase in debt or decrease in equity would be required to negatively impact the Trust's financial flexibility. 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 $26 million and $17 million in the first half of 2007 and 2006, respectively, and approximated the related expense for both pension and reclamation of $22 million in each of the same year-to-date periods. While our share of Syncrude's annual pension funding will increase slightly as a result of the most recent actuarial valuation, we do not anticipate significant reclamation funding increases for many years.

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 $16 billion with 479 million Units outstanding and a closing price of $32.94 per Unit on June 29, 2007.



Second

Canadian Oil Sands Trust - Quarter June May April

Trading Activity 2007 2007 2007 2007

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

Unit price

High $ 33.79 $ 33.09 $ 33.79 $ 30.94

Low $ 27.60 $ 29.52 $ 29.86 $ 27.60

Close $ 32.94 $ 32.94 $ 32.41 $ 30.16

Volume traded (millions) 82.4 29.9 26.0 26.5

Weighted average Trust units

outstanding (millions) 479.2 479.2 479.2 479.1

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CONTRACTUAL OBLIGATIONS AND COMMITMENTS

As of June 30, 2007, the Trust's share of Syncrude's capital expenditure commitments totalled $303 million, increasing by $42 million from December 31, 2006. The incremental capital expenditure commitments are to be incurred over the next two years. Syncrude's pension plan actuarial valuation for December 31, 2006 was completed in the second quarter of 2007, which confirmed an increase to our share of Syncrude's pension funding of approximately $5 million per year for the next five years. There have been no other significant changes to the Trust's contractual obligations and commitments in 2007 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 half of the year and changes in long-term debt.

As previously announced, the Management Services Agreement between Syncrude Canada Ltd. and Imperial Oil Resources is being implemented following approval by Syncrude's owners of the Opportunity Assessment Team's recommendations in April 2007. Secondees from Imperial and ExxonMobil are working closely with Syncrude management and staff to assist in the implementation of these recommendations and Imperial/ExxonMobil's global best practices and systems. The goal is to improve Syncrude's operating and reliability performance.

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 June 30, 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 its growth financing strategies.

Foreign Currency Hedging

As at June 30, 2007, we had US$10 million hedged at an average FX 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 June 30, 2007, we had $70 million drawn on our credit facilities bearing 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 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 financial derivatives outstanding at June 30, 2007.

FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of May 8, 2007, approximately 31 per cent of our Unitholders are non-Canadian residents with the remaining 69 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 August 7, 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.

GREENHOUSE GAS EMISSIONS REDUCTION REQUIREMENTS

Bill 3, the Alberta government's legislation to reduce greenhouse gas ("GHG") emission intensity, came into effect on July 1, 2007. Bill 3 states that facilities emitting more than 100,000 tonnes of GHGs a year ("Large Emitters") must reduce their emissions intensity by 12 per cent over the average emissions intensity 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 for developing infrastructure to reduce emissions or support research into 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 the emission reductions follow quantification protocol established by the province and are independently verified.

Based on the parameters currently outlined in Bill 3 and Syncrude's emissions performance, Canadian Oil Sands expects to begin accruing a cost of about $0.30 per barrel for the second half of 2007, which will be reflected in operating costs. This cost is a preliminary estimate pending clarification from the Alberta government regarding details of the Bill's implementation. No cost estimates are available yet for future years.

On April 27, 2007, the federal government released the Regulatory Framework for Air Emissions (the "Framework") which also sets out new GHG and air pollutant emission reduction targets. The Framework establishes an emission-intensity reduction target for existing facilities of six per cent per year to 2010, resulting in an initial enforceable reduction of 18 per cent from 2006 emission-intensity levels starting in 2010. Every year thereafter, a two per cent continuous emission-intensity improvement will be required. In addition to GHGs, the Framework requires reduction in air pollutants such as nitrogen oxides (NOx), Sulphur Oxides (SOx), Volatile Organic Compounds (VOCs), and Particulate Matter (PM) post 2012.

Compliance with the new requirements would allow contribution to a technology fund until 2017 at a rate of $15 per tonne from 2010 to 2012, increasing to $20 per tonne and escalating by the rate of GDP growth from 2013 to 2017. Maximum compliance can be met through contributions to the technology fund of up to 70 per cent in 2010 declining to 10 per cent by 2017. After 2017, contributions to the technology fund are no longer possible, and an emissions trading market with unlimited inter-firm trading within Canada and the active pursuit of linkages with U.S. and Mexico and possibly international markets is envisioned. The Framework expressly contemplates funding projects including carbon capture and sequestration and a carbon dioxide (CO2) pipeline in Alberta. Syncrude Canada is a member of the Integrated CO2 Network (ICON), a group formed to explore the viability of developing a large scale Canadian CO2 capture, transportation and storage network.

The federal government's Framework forms the basis for consultations with draft regulations anticipated to be released in spring 2008. Specifics regarding implementation of the Framework and harmonization between the Framework and Alberta's Bill 3 remain unresolved, making it difficult for Canadian Oil Sands to provide an accurate estimate of the cost impact for compliance with the proposed federal regulations; however, the Framework is a challenging plan that could have a significant adverse effect on operating costs and/or require significant capital investment.

REVIEW OF ALBERTA OIL SANDS ROYALTY

As previously announced, the Government of Alberta appointed an independent panel of experts to review all aspects of the royalty system, including oil sands, conventional oil and gas, and coalbed methane, as part of the government's examination of Alberta's royalty and tax regime. This panel has completed its public consultation process, and is anticipated to present its final report with recommendations to the Minister of Finance by August 31, 2007. Canadian Oil Sands participated in the process by making a formal presentation at the Royalty Review Panel's public meeting in Fort McMurray on June 5, 2007. At this time, Canadian Oil Sands cannot speculate on the impact of changes, if any, to the royalty regime on its operations.

2007 OUTLOOK

Our single point estimate for 2007 production is unchanged at 110 million barrels, or approximately 40 million barrels net to the Trust with a production range of 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 may be required later this year. The high end of the production range reflects no coker turnaround for the remainder of the year, as currently planned, together with higher than budgeted operational reliability and stability. We estimate production in each of the third and fourth quarters of 2007 to total about 30 million barrels.

Concurrent with the next coker turnaround planned for the first quarter of 2008, Syncrude expects to modify the new hydrogen plant steam generation system, which will enable Syncrude to produce the higher quality Syncrude™ Sweet Premium blend. The transition of Syncrude's production volumes to the higher quality, therefore, is not expected to occur until 2008.

We have increased our WTI crude oil price estimate for the year to average US$65 per barrel with no 2007 price differential between SSB and average Canadian dollar WTI. The improvement to the estimated differential reflects the $2.28 per barrel positive differential realized in the first half of the year and an estimated discount of $2 per barrel for the last half of 2007, reflecting increased synthetic crude oil supply as various oil sands operations return from turnarounds. These estimates, together with a stronger average foreign exchange rate of $0.92 US/Cdn, are expected to result in 2007 revenues totalling $2.9 billion.

Operating costs are estimated at $25.25 per barrel, which includes $6.19 per barrel for purchased energy based on an average AECO natural gas price of $7.00/GJ for 2007. Going forward, we expect to see upward pressure on operating costs as a result of higher inflation in the Fort McMurray region. Although Syncrude had incorporated a higher inflation factor for operating in the Fort McMurray region, recent negotiated wage settlements and negotiations currently underway representing unions critical to the operation, maintenance and construction of oil sands projects are creating intense pressure on labour costs. Strike action is not an immediate threat to the Syncrude project because our operating staff is non-unionized and we are currently not constructing new facilities or undergoing major turnaround work, which normally requires unionized trade workers. Nonetheless, as part of providing a competitive employment package and remaining an employer of choice in the region, Syncrude continues to expect these inflationary labour pressures to impact operating costs over time. Syncrude's focus is to improve operational reliability, which is supported by implementation of performance initiatives under the Management Services Agreement, as this effort has the best potential to contribute to lower per barrel operating costs and mitigate the effect of inflation.

We expect cash from operating activities to total $1,252 million, or $2.62 per Unit, including an increase in operating non-cash working capital of $11 million. We expect Crown royalties expense to total $387 million, or $9.51 per barrel, in 2007. We have also reduced our capital expenditures estimate to $226 million, which is substantially related to sustaining capital, including $74 million for the SER project. Syncrude has deferred spending on some of the Stage 3 completion and modification costs, which we had originally anticipated in 2007. Free cash flow, defined as cash from operating activities less capital expenditures and reclamation trust contributions, is estimated to be $2.13 per Unit in 2007. Free cash flow can fluctuate dramatically from period to period, reflecting operational performance and our unhedged exposure to crude oil prices. We are moving towards fuller payout of our free cash flow, unless capital investment growth opportunities exist that offer Unitholders enhanced value, which could result in more variability in the distribution amount. We will strive to smooth out this variability by taking a longer-term view of distributions in the context of our outlook for our operating and business environment. In that regard, we have kept our distribution for the third quarter at $0.40 per Unit.

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 $/Trust unit

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

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 25 0.05

Syncrude production increase 2 million bbls 30 0.06

Canadian dollar weakening US$0.01/C$ 18 0.04

AECO natural gas price

decrease C$0.50/GJ 14 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 July 24, 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 (LOSS) AND COMPREHENSIVE INCOME (LOSS)

Three Months Ended Six Months Ended

($ millions, except per June 30 June 30

Unit amounts) 2007 2006 2007 2006

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

Revenues $ 808 $ 715 $ 1,591 $ 1,231

Crude oil purchases and

transportation expense (118) (91) (227) (134)

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

690 624 1,364 1,097

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

Expenses:

Operating 271 224 502 495

Non-production 15 20 33 45

Crown royalties 89 29 183 34

Administration 6 4 10 9

Insurance 1 2 4 4

Interest, net (Note 10) 23 25 47 50

Depreciation, depletion

and accretion 77 60 159 110

Foreign exchange gain (63) (46) (70) (44)

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

419 318 868 703

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

Earnings before taxes 271 306 496 394

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

Future income tax expense

(recovery) and other

(Note 9) 665 (31) 628 (34)

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

Net income (loss) from

continuing operations (394) 337 (132) 428

Loss from discontinued

operations (1) - (1) -

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

Net income (loss) (395) 337 (133) 428

Other comprehensive loss,

net of income taxes

Reclassification of

derivative gains to

net income (2) - (4) -

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

Comprehensive income (loss) $ (397) $ 337 $ (137) $ 428

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

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

Weighted average Trust Units

(millions) 479 465 479 464

Trust Units, end of period

(millions) 479 466 479 466

Net income (loss) per

Trust Unit :

Basic $ (0.82) $ 0.72 $ (0.28) $ 0.92

Diluted $ (0.82) $ 0.72 $ (0.28) $ 0.92



CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY

(unaudited)

Three Months Ended Six Months Ended

June 30 June 30

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

($ millions) 2007 2006 2007 2006

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

Retained earnings

Balance, beginning of

period, as previously

reported $ 1,809 $ 1,368 $ 1,692 $ 1,370

Transition adjustment on

adoption of Financial

Instruments standards

(Note 2) - - (1) -

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

Balance, beginning of

period, adjusted 1,809 1,368 1,691 1,370

Net income (loss) (395) 337 (133) 428

Unitholder distributions

(Note 11) (191) (139) (335) (232)

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

Balance, end of period 1,223 1,566 1,223 1,566

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

Accumulated other comprehensive

income

Balance, beginning of period 28 - - -

Transition adjustment on

adoption of Financial

Instruments standards

(Note 2) - - 30 -

Other comprehensive loss (2) - (4) -

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

Balance, end of period 26 - 26 -

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

Unitholders' capital

Balance, beginning of period 2,498 2,053 2,260 2,010

Issuance of Trust Units

(Note 5) 1 68 239 111

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

Balance, end of period 2,499 2,121 2,499 2,121

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

Contributed surplus

Balance, beginning of period 4 3 4 3

Stock-based compensation - - - -

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

Balance, end of period 4 3 4 3

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

Total Unitholders' equity $ 3,752 $ 3,690 $ 3,752 $ 3,690

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



CANADIAN OIL SANDS TRUST

CONSOLIDATED BALANCE SHEETS

(unaudited)

June 30 December 31

($ millions) 2007 2006

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

ASSETS

Current assets:

Cash and cash equivalents $ 33 $ 353

Accounts receivable 310 244

Inventories 95 84

Prepaid expenses 3 7

Derivative assets (Note 2) 4 -

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

445 688

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

Property, plant and equipment, net 6,476 5,739

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

Other assets

Goodwill 52 52

Assets held for sale - 6

Reclamation trust 33 30

Deferred financing charges, net and other (Note 2) - 17

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

85 105

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

$ 7,006 $ 6,532

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

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

LIABILITIES AND UNITHOLDERS' EQUITY

Current liabilities:

Accounts payable and accrued liabilities $ 341 $ 304

Current portion of employee future benefits 18 11

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

359 315

Employee future benefits and other liabilities 99 100

Long-term debt (Note 2) 1,337 1,644

Asset retirement obligation 184 173

Deferred currency hedging gains (Note 2) - 35

Future income taxes (Note 9) 1,275 309

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

3,254 2,576

Unitholders' equity 3,752 3,956

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

$ 7,006 $ 6,532

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



CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

Three Months Ended Six Months Ended

June 30 June 30

($ millions) 2007 2006 2007 2006

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

Cash provided by (used in):

Cash from (used in) operating

activities

Net income (loss) $ (395) $ 337 $ (133) $ 428

Items not requiring outlay

of cash:

Depreciation, depletion

and accretion 77 60 159 110

Foreign exchange on

long-term debt (76) (49) (87) (48)

Future income tax expense

(recovery) 666 (29) 628 (34)

Other (4) 1 (4) 3

Net change in deferred items (1) 4 - 6

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

Funds from operations 267 324 563 465

Change in non-cash

working capital 57 (115) (37) (69)

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

Cash from operating

activities 324 209 526 396

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

Cash from (used in)

financing activities

Repayment of medium term

and Senior Notes (Note 8) (77) - (272) -

Net drawdown (repayment) of

bank credit facilities (50) (40) 70 (62)

Unitholder distributions

(Note 11) (191) (139) (335) (232)

Issuance of Trust Units

(Note 5) 2 68 2 111

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

Cash used in financing

activities (316) (111) (535) (183)

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

Cash from (used in) investing

activities

Capital expenditures (50) (59) (83) (196)

Acquisition of additional

Syncrude working interest

(Note 4) - - (231) -

Disposition of properties 4 - 4 -

Reclamation trust funding (2) (1) (3) (2)

Change in non-cash working

capital 8 (17) 2 (44)

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

Cash used in investing

activities (40) (77) (311) (242)

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

Increase (decrease) in cash

and cash equivalents (32) 21 (320) (29)

Cash and cash equivalents at

beginning of period 65 38 353 88

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

Cash and cash equivalents at

end of period $ 33 $ 59 $ 33 $ 59

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

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

June 30

2007 2006

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

Cash and cash equivalents

consist of:

Cash $ 1 $ 4

Short-term investments 32 55

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

$ 33 $ 59

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


NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE SIX MONTHS ENDED JUNE 30, 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 had 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 was settled on 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 (Loss) and Comprehensive Income

(Loss) includes a new line item for comprehensive income and loss,

which includes both net income/losses and other comprehensive

income/losses. Other comprehensive income/loss 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 objectives, 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.

Inventories

In June 2007, the CICA issued a new accounting standard - Section

3031 Inventories, which replaces the existing standard for

inventories, Section 3030. The main features of the new Section are

as follows:

- Measurement of inventories at the lower of cost and net

realizable value

- Consistent use of either first-in, first-out or a weighted

average cost formula to measure cost

- Reversal of previous write-downs to net realizable value when

there is a subsequent increase to the value of inventories

The new Section is effective for the Trust beginning January 1, 2008.

Application of the new Section is not expected to have a material

impact on the financial statements.

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)

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

$ 476

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

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

Consideration

Cash $ 238

Issuance of Trust Units 237

Acquisition costs 1

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

$ 476

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

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


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 six months ended June 30, 2007, approximately 8.2 million

Units were issued for proceeds of $238 million 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

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

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 0.2 2

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

Balance, June 30, 2007 479.3 $ 2,499

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

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


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 and six months ended

June 30, 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 Six Months Ended

June 30 June 30

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

2007 2006 2007 2006

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

Defined benefit plans:

Pension benefits $ 7 $ 7 $ 14 $ 15

Other benefit plans 1 1 2 2

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

$ 8 $ 8 $ 16 $ 17

Defined contribution plans 1 - 1 1

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

Total Benefit cost $ 9 $ 8 $ 17 $ 18

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

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

7) BANK CREDIT FACILITIES

Credit facility

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

Extendible revolving term facility(a) $ 40

Line of credit(b) 45

Operating credit facility(c) 800

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

$ 885

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

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 first 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 $61 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 June 30, 2007, $70 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. On

May 15, 2007, the Trust repaid US$70 million of 7.625% Senior Notes

and realized a foreign exchange gain of $18 million on repayment.

9) FUTURE INCOME TAXES

On June 12, 2007, Bill C-52 Budget Implementation Act, 2007 was

substantively enacted by the Canadian federal government, which

contains legislation to tax publicly traded trusts in Canada. As a

result, a new 31.5 per cent tax will be applied to distributions from

Canadian public income trusts. The new tax is not expected to apply

to Canadian Oil Sands until 2011 as a transition period applies to

publicly traded trusts that existed prior to November 1, 2006. As a

result of this substantive enactment of trust taxation, Canadian Oil

Sands recorded an additional $0.7 billion future income tax expense

and increased its future income tax liability in the second quarter

of 2007. The future income tax adjustment represents the taxable

temporary differences of Canadian Oil Sands Trust tax-effected at

31.5 per cent, which is the rate that will be applicable in 2011

under the current legislation and Canadian Oil Sands' current

corporate structure.



10) INTEREST, NET

Three Months Ended Six Months Ended

June 30 June 30

2007 2006 2007 2006

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

Interest expense on

long-term debt $ 24 $ 25 $ 49 $ 51

Interest income and other (1) - (2) (1)

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

Interest expense, net $ 23 $ 25 $ 47 $ 50

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

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


11) 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 Six Months Ended

June 30 June 30

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

2007 2006 2007 2006

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

Cash from operating

activities $ 324 $ 209 $ 526 $ 396

Add (Deduct):

Capital expenditures (50) (59) (83) (196)

Acquisition of additional

Syncrude working interest - - (231) -

Disposition of properties 4 - 4 -

Change in non-cash

working capital(1) 8 (17) 2 (44)

Reclamation trust funding (2) (1) (3) (2)

Change in cash and cash

equivalents and financing,

net(2) (93) 7 120 78

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

Unitholder distributions $ 191 $ 139 $ 335 $ 232

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

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

Unitholder distributions

per Trust Unit(3) $ 0.40 $ 0.30 $ 0.70 $ 0.50

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

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

(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.

12) SUPPLEMENTARY INFORMATION

Three Months Ended Six Months Ended

June 30 June 30

2007 2006 2007 2006

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

Income tax paid $ 1 $ 2 $ 1 $ 5

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

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

Interest charges paid $ 19 $ 18 $ 54 $ 51

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

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

Contact Information




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


    or

    Canadian Oil Sands Limited
    Rob Dawson, Treasurer
    (403) 218-6225
    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