Canadian Oil Sands Trust
TSX : COS.UN

Canadian Oil Sands Trust

January 30, 2008 23:59 ET

Canadian Oil Sands Trust Raises Its Quarterly Distribution 36 Per Cent to $0.75 Per Trust Unit

CALGARY, ALBERTA--(Marketwire - January 30, 2008) - Canadian Oil Sands Trust (TSX:COS.UN) ("Canadian Oil Sands", the "Trust" or "we") today announced that 2007 cash from operating activities increased 21 per cent to $1.4 billion, or $2.87 per Trust unit ("Unit"), over 2006. Net income decreased to $743 million ($1.55 per Unit) in 2007 from $834 million ($1.79 per Unit) last year. The decline reflects a $701 million future income tax expense recorded in the second quarter of 2007 as a result of the enactment of income trust taxation that takes effect in 2011. Earnings before taxes increased by $469 million to $1,321 million in 2007 compared to 2006. Future income tax is a non-cash item that has no current impact on our cash from operating activities.

The increase in both cash from operating activities and earnings before taxes is largely attributable to a 22 percent increase in year-over-year sales volumes, which averaged 112,000 barrels per day during 2007, and a higher 2007 realized selling price.

The Trust has declared a 36 per cent increase in the quarterly distribution amount to $0.75 per Unit from $0.55 per Unit for Unitholders of record on February 12, 2008, payable on February 29, 2008.

"In 2007 we reported strong financial results, met our annual production forecast, and substantially increased distributions," said Marcel Coutu, President and Chief Executive Officer. "For 2008, Syncrude is planning a heavy maintenance program, which is expected to result in only a modest production increase over last year. Syncrude remains focused on achieving design capacity, which is about 10 per cent above where we are producing today. The distribution increase this quarter reflects the financial plan we established to enhance investor returns prior to trust taxation taking effect in 2011. Based on current circumstances regarding this taxation, we most likely will convert to a corporate structure."

During the fourth quarter of 2007, cash from operating activities decreased 11 per cent to $367 million ($0.77 per Unit) compared with the same 2006 period. Excluding working capital changes, cash from operating activities increased in the fourth quarter of 2007 compared with 2006, principally due to an increase in our net realized selling price and modestly higher sales volumes quarter-over-quarter. Net income in the fourth quarter of 2007 was $515 million ($1.07 per Unit), up from $128 million ($0.27 per Unit) in the fourth quarter of 2006.



CANADIAN OIL SANDS TRUST

Highlights

Three Months Ended Twelve Months Ended

(millions of Canadian December 31 December 31

dollars, except Trust unit

and volume amounts) 2007 2006 2007 2006

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Net Income $ 515 $ 128 $ 743 $ 834

Per Trust unit - Basic $ 1.07 $ 0.27 $ 1.55 $ 1.79

Per Trust unit - Diluted $ 1.07 $ 0.27 $ 1.54 $ 1.78

Cash from Operating

Activities $ 367 $ 412 $ 1,377 $ 1,142

Per Trust unit $ 0.77 $ 0.88 $ 2.87 $ 2.45

Unitholder Distributions $ 264 $ 140 $ 791 $ 512

Per Trust unit $ 0.55 $ 0.30 $ 1.65 $ 1.10

Sales Volumes(1)

Total (MMbbls) 10.7 10.1 41.0 33.5

Daily average (bbls) 116,368 110,185 112,298 91,844

Operating Costs per barrel $ 27.38 $ 23.60 $ 25.23 $ 27.07

Net Realized Selling Price

per barrel

Realized selling price

before hedging $ 88.50 $ 63.47 $ 79.02 $ 71.96

Currency hedging gains 0.23 0.24 0.27 0.60

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Net realized selling price $ 88.73 $ 63.71 $ 79.29 $ 72.56

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West Texas Intermediate

(average $US per barrel)(2) $ 90.50 $ 60.16 $ 72.36 $ 66.25

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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.


2008 Outlook

On January 29, 2008 production from the Syncrude facility was suspended following several instrument freeze-ups as a result of extremely cold weather conditions. Operation of a number of units was disrupted. Syncrude has advised that it is focusing efforts on the safe and reliable restart of affected units, and expects that it will take several days to fully restore operations. At this time, investigations are too preliminary to know the impact, if any, on our 2008 Outlook; accordingly, we have not adjusted our current Outlook for this operational incident.

The Trust is estimating Syncrude production to total 115 million barrels in 2008 with a range of 110 to 120 million barrels (net to the Trust, equivalent to 42 million barrels with a range of 40 to 44 million barrels). The single point production estimate incorporates Syncrude's extensive 2008 maintenance program, an allowance for unplanned outages and recognition that Syncrude is still working to establish reliable Stage 3 design rates. During 2008, Syncrude plans to perform turnarounds of Coker 8-1 (second quarter) and Coker 8-2 (third quarter) as well as associated maintenance work on other units. The production range reflects our current best estimate of the upside and downside in volumes Syncrude could experience, depending on operational reliability, in 2008.

More information on the Trust's Outlook is provided in the MD&A section of this report and the January 30, 2008 guidance document, which is available on the Trust's web site at www.cos-trust.com under "investor information".

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") was prepared as of January 30, 2008 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 twelve months ended December 31, 2007 and December 31, 2006, as well as the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2006.

ADVISORY- in the interest of providing the Trust's Unitholders and potential investors with information regarding the Trust, including management's assessment of the Trust's future production and cost estimates, plans and operations, certain statements throughout this MD&A contain "forward-looking statements" under applicable securities law. Forward-looking statements in this M&DA include, but are not limited to, statements with respect to: the preliminary estimate for repair costs of the December fire; the expectation that increased inflationary costs in Alberta will negatively impact Syncrude's costs in 2008; expectations regarding depreciation and depletion rates and expense, accretion expense and asset retirement obligations in 2008 and beyond; the expected structure to be assumed given the Federal government's tax changes in 2011; plans regarding the refinancing of the $150 million medium term note maturity in April 2008; expectations regarding future distribution levels; the expectation that there will not be any material funding increases relative to Syncrude's future reclamation costs or pension funding for the next several years; the belief that the Trust will not be restricted by its net debt to total capitalization financial covenant; the expectation that no crude oil hedges will be entered into in the future; the expected impact on the Trust from announced changes by the Alberta government regarding its royalty regime; any expectations regarding the enforceability of legal rights; 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 cash from operating activities; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2008 for Canadian Oil Sands' product; the potential amount payable in respect of any future income tax liability; the expected increased reliability and other benefits from the Management Services Agreement between Syncrude Canada Ltd. and Imperial Oil Resources; 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 2008 and beyond; the expectation that the SER project will significantly reduce total sulphur dioxide and other emissions; capital expenditures for 2008; the anticipated cost and completion date for the SER project; the level of natural gas consumption in 2008 and beyond; the expectations regarding discussions with the Alberta government over Crown royalties applicable to Syncrude; the expected price for crude oil and natural gas in 2008; the expected production, revenues and operating costs for 2008; 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 impacts of regulatory changes especially as such relate to royalties, taxation, and environmental charges; the impact of technology on operations and processes and how new complex technology may not perform as expected, 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 fourth quarter of 2007, crude oil production from the Syncrude Joint Venture ("Syncrude") totalled 28.8 million barrels, or an average of about 313,000 barrels per day, compared with 27.8 million barrels, or approximately 302,700 barrels per day, during the same period of 2006. Net to the Trust, production totalled 10.6 million barrels in the fourth quarter of 2007 based on our 36.74 per cent working interest compared with 9.9 million barrels in 2006 based on a 35.49 percent interest.

Fourth quarter production in both 2007 and 2006 reflected incremental volumes from the expanded Stage 3 facilities; however, volumes in the 2007 period were reduced by Coker 8-3 outages. The first disruption suspended production from the coker for approximately one week at the beginning of the quarter and the second disruption occurred in early December following a fire in the environmental section of Coker 8-3. There were no injuries as a result of the fire but the electro-static precipitators ("ESP"), which remove fine dust particles from the coker flue gas, were damaged. Following repairs to certain of the ESPs, operation of Coker 8-3 resumed in mid-December. The preliminary cost estimate of the damage is $50 million ($18 million net to the Trust). However, Syncrude continues to perform a fulsome analysis of the necessary repair costs, which may change our current estimate. Canadian Oil Sands will provide an update on the costs following Syncrude's review, should they differ materially from our current estimation. Canadian Oil Sands has property insurance with a $50 million deductible, which applies at the Syncrude level. The two operational incidents involving Coker 8-3 were unrelated events. In comparison, fourth quarter 2006 volumes were reduced by unplanned maintenance late in the quarter on Coker 8-2.

Canadian Oil Sands' operating costs were $27.38 per barrel in the fourth quarter of 2007, up $3.78 per barrel from the same quarter last year (see the "Operating costs" section of this MD&A for further discussion).

Syncrude's annual production in 2007 totaled 111.3 million barrels, or approximately 305,000 barrels per day, compared with 94.3 million barrels, or about 258,400 barrels per day, during 2006. Net to the Trust, production totalled 40.9 million barrels in 2007 based on our 36.74 per cent working interest compared with 33.5 million barrels in 2006 based on a 35.49 per cent interest. Production in 2007 exceeded the original budget estimate of 110 million barrels Canadian Oil Sands provided on December 7, 2006. The Trust revised its estimate for annual Syncrude production to 111 million barrels on October 31, 2007 to reflect better than anticipated operational reliability during the first nine months of the year.

The increase in year-over-year volumes primarily reflects Stage 3 volumes along with a higher working interest in 2007. Aside from a brief initial startup in May 2006, Stage 3 production commenced at the end of August 2006, thereby contributing volumes for only the last four months of the 2006 year. In comparison, the 2007 year benefited more from Stage 3 production with the new facilities operating throughout the year, partially offset by Coker 8-3 constrained production rates and downtime. Production in 2007 was further reduced by unplanned maintenance on Coker 8-2 during the first quarter and planned maintenance on other units, including a turnaround of the LC-Finer. Production in 2006 was reduced by an extensive maintenance program, including an extended turnaround of Coker 8-1.

Operating costs during 2007 averaged $25.23 per barrel, down $1.84 a barrel from 2006, largely as a result of less turnaround and maintenance activity and more production in 2007 relative to 2006 (discussed more fully in the "Operating costs" section of this MD&A).

Syncrude's entire production volumes during the fourth quarter of 2007 reflect the higher quality Syncrude™ Sweet Premium ("SSP") blend, a transition that occurred in the third quarter of 2007. The transition occurred earlier than the revised 2008 timeframe as Syncrude was able to access the required hydrogen capacity by identifying and removing hydrogen constraints on various units. Syncrude still plans to perform repairs to the new hydrogen plant in 2008 in order to secure additional hydrogen feedstock to enable the continued production of SSP at design capacity rates.

Commencing in the 2007 third quarter report, we started using the term "synthetic crude oil", or "SCO", to refer to Syncrude's production and our sales volumes in the current and prior periods in lieu of the terms SSB and SSP.

Syncrude's facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. 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 operational and 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". Syncrude is still lining out the Stage 3 facilities, and therefore is not producing at design rates on a consistent basis. All references to Syncrude's productive capacity in this report refer to barrels per calendar day, unless stated otherwise.

The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes. These in-transit volumes vary with current production. The growth in production from the Stage 3 facilities also has required Canadian Oil Sands to access more distant markets on additional pipelines to sell its volumes, which generally increases pipeline inventory 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 2007

and volume amounts) Q4 Q3 Q2 Q1

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Revenues(1) $ 950 $ 936 $ 690 $ 674

Net income (loss) $ 515 $ 361 $ (395) $ 262

Per Trust Unit, Basic(2) $ 1.07 $ 0.75 $ (0.82) $ 0.55

Per Trust Unit, Diluted(2) $ 1.07 $ 0.75 $ (0.82) $ 0.55

Cash from operating activities $ 367 $ 484 $ 324 $ 202

Per Trust Unit(2) $ 0.77 $ 1.01 $ 0.68 $ 0.42

Unitholder distributions $ 264 $ 192 $ 191 $ 144

Per Trust Unit(2) $ 0.55 $ 0.40 $ 0.40 $ 0.30

Daily average sales

volumes (bbls) 116,368 124,904 98,720 108,981

Net realized selling

price ($/bbl)(3) $ 88.73 $ 81.48 $ 76.81 $ 68.69

Operating costs ($/bbl) $ 27.38 $ 20.84 $ 30.13 $ 23.56

Purchased natural gas

price ($/GJ) $ 5.84 $ 4.99 $ 6.78 $ 6.99

West Texas Intermediate

(avg. US$/bbl)(4) $ 90.50 $ 75.15 $ 65.02 $ 58.23

Foreign exchange rates

(US$/Cdn$):

Average $ 1.02 $ 0.96 $ 0.91 $ 0.85

Quarter-end $ 1.01 $ 1.00 $ 0.94 $ 0.87

($ millions, except per Trust Unit 2006

and volume amounts) Q4 Q3 Q2 Q1

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

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

Per Trust Unit, Basic(2) $ 0.27 $ 0.60 $ 0.72 $ 0.20

Per Trust Unit, Diluted(2) $ 0.27 $ 0.59 $ 0.72 $ 0.20

Cash from operating activities $ 412 $ 334 $ 209 $ 187

Per Trust Unit(2) $ 0.88 $ 0.72 $ 0.45 $ 0.40

Unitholder distributions $ 140 $ 140 $ 139 $ 93

Per Trust Unit(2) $ 0.30 $ 0.30 $ 0.30 $ 0.20

Daily average sales

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

Net realized selling

price ($/bbl)(3) $ 63.71 $ 78.43 $ 79.35 $ 70.24

Operating costs ($/bbl) $ 23.60 $ 19.68 $ 28.48 $ 40.26

Purchased natural gas

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

West Texas Intermediate

(avg. US$/bbl)(4) $ 60.16 $ 70.60 $ 70.72 $ 63.48

Foreign exchange rates

(US$/Cdn$):

Average $ 0.88 $ 0.89 $ 0.89 $ 0.87

Quarter-end $ 0.86 $ 0.90 $ 0.90 $ 0.86

(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.

(3) Net realized selling price after foreign currency hedging.

(4) Pricing obtained from Bloomberg.

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The following 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

the recording of 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. In addition to the Bill C-52 impact,

corporate tax rate reductions enacted in the second and fourth

quarters of 2007 and in the second quarter of 2006 resulted in future

income tax recoveries and accordingly increased net income by $38

million, $153 million and $29 million in each quarter, respectively.

Future income tax is a non-cash item 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 pro-rata impact on the Trust's revenues,

operating costs, and depletion, depreciation and accretion ("DD&A")

expense.

- 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 that had applied since January 1, 2002,

increasing Crown royalties expense and somewhat offsetting the revenue

increase impact on net income and cash from operating activities in

the latter half of 2006 and all 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 change.

- 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.

- During 2007, the Canadian dollar strengthened considerably relative to

the U.S. dollar, which resulted in significant unrealized foreign

exchange gains on the revaluation of our U.S. dollar denominated debt

and related interest payable. The unrealized foreign exchange gains

related to our long-term debt are non-cash and therefore only impact

net income.

- In the last six months, and in particular the last quarter of 2007,

U.S. dollar West Texas Intermediate ("WTI") prices, which our sales

are priced relative to, have increased significantly and reached

record highs in the quarter. The significant increase in this

benchmark pricing has boosted our revenues; however, the revenue

increase has been mitigated somewhat as a result of the strengthening

Canadian dollar relative to the U.S. dollar.

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

In the fourth quarter of 2007, net income of $515 million, or $1.07 per Trust unit ("Unit"), exceeded net income of $128 million, or $0.27 per Unit, recorded in the comparable quarter in 2006, primarily as a result of higher revenues, foreign exchange gains compared to losses in 2006, and a future income tax recovery rather than an expense in 2006, offset somewhat by an increase in operating costs, Crown royalties, and DD&A expenses. Revenues (after crude oil purchases and transportation expense) totalled $950 million, an increase of $304 million, in the fourth quarter of 2007 relative to 2006. This significant increase was substantially attributable to a $25 per barrel increase in our net realized selling price with a modest contribution from increased sales volumes quarter-over-quarter. In the fourth quarter of 2007, the Trust recorded a foreign exchange gain of $5 million compared with a loss of $40 million in the same quarter of 2006, primarily related to unrealized foreign exchange gains on the translation of U.S. dollar denominated long-term debt. Also in the fourth quarter of 2007, future income taxes resulted in a $157 million increase to net income quarter-over-quarter, primarily reflecting the revaluation of future tax balances from a 3.5 per cent decrease in federal corporate tax rates substantively enacted in the fourth quarter of 2007.

The positive revenue, foreign exchange and future income tax impacts in the fourth quarter of 2007 were somewhat offset by higher operating costs, which increased to $293 million from $239 million in the last quarter of 2006. On a per barrel basis, operating costs in the fourth quarter of 2007 increased by $3.78 to average $27.38 compared to the same quarter of 2006. Crown royalties also increased by $54 million quarter-over-quarter as a result of the increase in net revenues. DD&A expense rose by $16 million quarter-over-quarter, mainly reflecting a higher depreciation and depletion rate.

Cash from operating activities decreased by $45 million quarter-over-quarter and totalled $367 million in the fourth quarter of 2007; however, this decrease was driven by a $258 million increase in operating working capital requirements, as shown in the table below. Excluding the non-cash increases to unrealized foreign exchange gains, DD&A expense and future income tax recoveries, cash from operating activities was affected by the same variables as net income, as described above.



Three Months Ended Twelve Months Ended

December 31 December 31

2007 2006 Variance 2007 2006 Variance

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Cash from (used in)

changes in:

Accounts

receivable $ (37) $ 73 $ (110) $ (135) $ (47) $ (88)

Inventories (22) 7 (29) (18) 3 (21)

Prepaid expenses 3 - 3 1 (4) 5

Accounts payable

and accrued

liabilities (82) 39 (121) (15) 23 (38)

Less: A/P reclassed

to investing and

other (4) (3) (1) 2 47 (45)

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Change in operating

non-cash working

capital $ (142) $ 116 $ (258) $ (165) $ 22 $ (187)

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The two most significant components of the $258 million operating working capital increase quarter-over-quarter were a $110 million and $121 million change in accounts receivable and accounts payable and accrued liabilities ("A/P"), respectively. Given the nature of the oil and gas industry whereby accounts receivable from customers are typically settled in the following month, working capital can fluctuate significantly resulting from volume and price changes relative to each period end. Canadian Oil Sands' cash from operating activities is also impacted by changes in its A/P balance, which can reflect the timing of significant accruals and payments, such as Crown royalties, operating costs, and interest payments on long-term debt.

On a year-to-date basis in 2007, the Trust recorded net income of $743 million, or $1.55 per Unit, compared with net income of $834 million, or $1.79 per Unit, in 2006. Net income year-over-year was significantly reduced by the $665 million future income tax expense recorded in the second quarter of 2007. On an earnings before taxes basis, the Trust's results improved by $469 million year-over-year, primarily reflecting the net positive contributions of the incremental Stage 3 volumes combined with robust crude oil prices, and larger foreign exchange gains, partially offset by higher operating, Crown royalties and DD&A expenses. Revenues (after crude oil purchases and transportation expense) increased by $818 million and foreign exchange gains increased by $112 million in 2007 relative to the prior year. The substantial rise in revenues was attributable to both an increase in sales volumes and a higher realized selling price, resulting in total revenues in 2007 of $3.3 billion. The larger foreign exchange gains are primarily attributable to an increase in unrealized gains recorded on the revaluation of our U.S. dollar denominated debt, reflecting the strengthening Canadian dollar relative to the U.S. dollar. The 2007 revenue and foreign exchange gains increases were offset somewhat by higher operating expenses of $127 million, Crown royalties of $253 million, and DD&A expense of $96 million year-over-year.

Cash from operating activities increased 21 per cent in 2007 relative to 2006 and totalled $1,377 million, or $2.87 per Unit. Changes in non-cash working capital decreased cash from operating activities by $187 million year- over-year, with the main factors being changes in accounts receivable and A/P balances. Relative to our October 31, 2007 guidance for 2007, actual cash from operating activities was lower than expected by $49 million, or $0.11 per Unit, and was impacted by the significant change in non-cash working capital (guidance estimate of $nil), offset somewhat by higher actual revenues.

The changes in revenues, operating expenses 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.



Three Months Ended Twelve Months Ended

December 31 December 31

($ per bbl) 2007 2006 Variance 2007 2006 Variance

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Net realized

selling price 88.73 63.71 25.02 79.29 72.56 6.73

Operating costs (27.38) (23.60) (3.78) (25.23) (27.07) 1.84

Crown royalties (12.81) (8.23) (4.58) (11.83) (6.93) (4.90)

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Netback 48.54 31.88 16.66 42.23 38.56 3.67

Non-production costs (1.33) (1.40) 0.07 (1.54) (2.08) 0.54

Administration and

insurance (0.76) (0.39) (0.37) (0.69) (0.65) (0.04)

Interest, net (1.63) (2.35) 0.72 (2.08) (2.93) 0.85

Depletion, depreciation

and accretion (8.47) (7.39) (1.08) (8.56) (7.61) (0.95)

Foreign exchange gain 0.53 (3.97) 4.50 2.86 0.16 2.70

Future income tax

recovery (expense)

and other 11.00 (3.94) 14.94 (14.12) (0.53) (13.59)

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(0.66) (19.44) 18.78 (24.13) (13.64) (10.49)

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Net income per

barrel 47.88 12.44 35.44 18.10 24.92 (6.82)

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Sales volumes

(MMbbls) 10.7 10.1 0.6 41.0 33.5 7.5

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Non-GAAP Financial Measures

Prior to the third quarter of 2007, we referred to free cash flow as an indicator of the Trust's ability to repay debt and pay distributions to its Unitholders. It was a measure that did not have any standardized meaning under Canadian generally accepted accounting principles ("GAAP"). Commencing in the third quarter of 2007, we discontinued our discussions of free cash flow, and now refer to the GAAP measure of cash from operating activities, which is derived from our Consolidated Statements of Cash Flows. We also refer to the Trust's cash from operating activities on a per Unit basis, which does not have any standardized meaning under Canadian GAAP. Cash from operating activities per Unit is derived from cash from operating activities reported on the Trust's Consolidated Statement of Cash Flows divided by the weighted- average number of Units outstanding in the period, as used in the Trust's net income per Unit calculations. Cash from operating activities on a per Unit basis determines the Trust's capacity to fund capital expenditures, distributions, and other investing activities without incremental financing. In addition, the Trust refers to various per barrel figures, such as net realized selling prices, operating costs and Crown royalties, which are also considered non-GAAP measures, but provide meaningful information on the operational performance of the Trust. We derive per barrel figures by dividing the relevant revenue or cost figure by our sales net of purchased crude oil volumes in a period. Cash from operating activities per Unit and per barrel figures 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 Twelve Months Ended

December 31 December 31

($ millions) 2007 2006 Variance 2007 2006 Variance

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Sales revenue(1) $ 1,004 $ 734 $ 270 $ 3,622 $ 2,672 $ 950

Crude oil purchases (49) (78) 29 (348) (219) (129)

Transportation

expense (8) (12) 4 (35) (41) 6

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947 644 303 3,239 2,412 827

Currency hedging

gains(1) 3 2 1 11 20 (9)

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$ 950 $ 646 $ 304 $ 3,250 $ 2,432 $ 818

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Sales volumes

(MMbbls)(2) 10.7 10.1 0.6 41.0 33.5 7.5

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

on the Trust's Consolidated Statement of Income and Comprehensive

Income. Sales revenue includes revenue from the sale of purchased

crude oil.

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

($ per barrel)

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Realized selling

price before

hedging(3) $ 88.50 $ 63.47 $ 25.03 $ 79.02 $ 71.96 $ 7.06

Currency hedging

gains 0.23 0.24 (0.01) 0.27 0.60 (0.33)

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

Net realized

selling price $ 88.73 $ 63.71 $ 25.02 $ 79.29 $ 72.56 $ 6.73

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

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

(3) Sales revenue after crude oil purchases and transportation expense

divided by sales volumes, net of purchased crude oil volumes.


Sales revenue after crude oil purchases and transportation expense and before currency hedging in the fourth quarter of 2007 primarily reflects a significantly higher realized selling price relative to the same period in 2006. Our average realized selling price before currency hedging of $88.50 per barrel in the fourth quarter of 2007 was $25.03 per barrel higher than the comparable period in 2006. WTI prices, which our SCO pricing has historically closely followed, averaged US$90.50 per barrel in the fourth quarter of 2007, an increase of 50 per cent, or $30.34 per barrel, compared to the same quarter of 2006. However, this increase was diluted by a strengthening of the Canadian dollar relative to the U.S. dollar, which averaged $1.02 US/Cdn in the fourth quarter of 2007 compared to $0.88 US/Cdn in the same quarter of 2006. Also contributing to the higher realized selling price before hedging quarter-over- quarter was a $4.28 per barrel improvement in our pricing differential relative to Canadian dollar WTI (the "price differential"). In the fourth quarter of 2007 our SCO realized a weighted-average discount of $0.54 per barrel compared to average Canadian dollar WTI versus a discount of $4.82 per barrel in the same period in 2006. We believe the improvement in the 2007 fourth quarter differential relative to the same period in 2006 reflected the following factors:

- An increase in demand for our SCO product in the fourth quarter of

2007 from two major refineries, due to upgrading and refinery unit

processing issues at those refineries; and

- An unusually deep discount in the fourth quarter of 2006 relative to

other quarters, including the last quarter of 2007, reflecting

increased supply in the market of light, sweet synthetics and lower

demand for our product. We believe higher inventory levels at

refineries, lower refinery margins and turnarounds by refiners all

served to reduce demand in the last quarter of 2006.

On a year-to-date basis, both the increase in sales volumes and a higher realized selling price before currency hedging gains contributed to the 34 per cent increase in revenues before currency hedging relative to the prior year. The incremental production from the Stage 3 facilities, less coker downtime, and the Trust's larger Syncrude ownership during 2007 resulted in the higher 2007 sales volumes. Our net realized selling price before currency hedging gains averaged $79.02 per barrel, an increase of $7.06 per barrel compared to 2006. The 10 per cent increase in average realized selling price year-over- year reflected the US$6.11 per barrel increase in WTI prices, which averaged US$72.36 per barrel in 2007, and an improved price differential. We realized a premium to average Canadian dollar WTI of $1.63 per barrel in 2007 relative to a discount of $2.57 per barrel in 2006. Foreign exchange rates averaged $0.93 US/Cdn and $0.88 US/Cdn in 2007 and 2006, respectively. Actual revenue exceeded our October 31, 2007 annual guidance for 2007 by $146 million as a result of a higher average WTI price, a slightly higher price differential, and a weaker Canadian dollar relative to the U.S. dollar, as illustrated in the following table:



Actual Guidance(1)

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

Syncrude production (MMbbls) 111 111

West Texas Intermediate

(average $US per barrel) $ 72.36 $ 70.00

Premium (Discount) to average C$ WTI prices

(C$/bbl) $ 1.63 $ 1.50

Average foreign exchange rates (US$/Cdn$): $ 0.93 $ 0.94

(1) As at October 31, 2007.


The positive price differential in 2007 primarily reflected the disconnect of the relationship between WTI and other benchmark light, sweet crude oils during the second and third quarters of 2007. In addition to more demand for our product in the third and fourth quarters of 2007 by certain major refineries, a stronger differential relative to the prior year was supported by reduced synthetic crude oil supply as a result of operational issues and turnarounds experienced by various synthetic crude oil producers during 2007, including Syncrude. By comparison, in 2006, primarily in the first quarter, the discount from Canadian dollar WTI 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 SCO prices due to limited pipeline capacity to move crude oil to extended markets, in addition to the factors which impacted the fourth quarter 2006 differential. 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 Twelve Months Ended

December 31 December 31

2007 2006 2007 2006

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

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

Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO

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

Bitumen Costs(1)

Overburden

removal 2.14 1.65 1.82 2.09

Bitumen

production(2) 9.90 6.44 8.82 7.60

Purchased

energy(2,4) 2.33 2.22 2.19 2.64

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

14.37 17.49 10.31 12.54 12.83 15.26 12.33 14.58

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

Upgrading Costs(3)

Bitumen

processing and

upgrading(2) 3.63 4.74 4.35 4.78

Turnaround and

catalysts 0.45 0.47 1.05 2.20

Purchased

energy(4) 2.77 3.15 2.55 2.98

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

6.85 8.36 7.95 9.96

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

Other and

research(2) 2.54 2.29 1.43 1.92

Change in treated

and untreated

inventory (0.37) (0.01) (0.02) 0.25

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

Total Syncrude

operating costs 26.51 23.18 24.62 26.71

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

Canadian Oil Sands

adjustments(5) 0.87 0.42 0.61 0.36

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

Total operating

costs 27.38 23.60 25.23 27.07

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

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

(thousands of

barrels per day) Bitumen SCO Bitumen SCO Bitumen SCO Bitumen SCO

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

Syncrude

production

volumes 380 313 369 303 363 305 305 258

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

(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 SCO based on the effective yield of

SCO 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 SCO. It also

includes the costs of major refining equipment turnarounds and

catalyst replacement, all of which are expensed as incurred.

(4) Natural gas prices averaged $5.84/GJ and $6.51/GJ in the fourth

quarters of 2007 and 2006, respectively. For the year, natural gas

prices averaged $6.14/GJ and $6.26/GJ in 2007 and 2006, respectively.

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

pension costs, opportunity assessment team costs and contract fees

related to the Management Services Agreement between Syncrude Canada

Ltd. and Imperial Oil Resources, 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 Twelve Months Ended

December 31 December 31

($/bbl of SCO) 2007 2006 2007 2006

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

Production costs 21.78 17.75 20.08 20.97

Purchased energy 5.60 5.85 5.15 6.10

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

Total operating costs 27.38 23.60 25.23 27.07

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

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

(GJs/bbl of SCO)

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

Purchased energy

consumption 0.96 0.90 0.84 0.98

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


In the fourth quarter of 2007, operating costs averaged $27.38 per barrel, an increase of $3.78 per barrel quarter-over-quarter, primarily as a result of the following:

- Additional waste and oil sand moved during the fourth quarter of

2007. Syncrude supplemented its own material movement activities

with contracted equipment and operators to increase exposed mineable

ore and corresponding lead-time to meet operational needs and

enhance operational flexibility.

- Inflation and retroactive adjustments for third party contract

settlements with the building trades group related to prior years.

The building trades group encompasses trades such as welders and

electrical workers, which Syncrude uses for a significant amount of

its work. Inflationary cost pressures, which have significantly

impacted the entire upstream oil and gas industry in Alberta, are

expected to continue to negatively impact Syncrude's (and other

producers) material and labour costs in 2008.

- Various other factors, including an increased Syncrude workforce and

additional maintenance costs from employing more equipment (Syncrude

and contracted) and running the equipment at higher rates as a

result of the additional Stage 3 processing capacity.

On an annual basis, operating costs averaged $25.23 per barrel in 2007, a reduction of $1.84 per barrel compared to 2006. Actual per barrel operating costs were in-line with our October 31, 2007 annual 2007 guidance of $24.87. While coker turnarounds occurred in both years, 2007 experienced less turnaround and maintenance activity and more production relative to the prior year, which reduced operating costs by $1.15 per barrel and is reflected in the decrease in "Turnaround and catalysts" costs in the Operating Costs table.

Purchased energy costs fell by almost $1 per barrel in 2007 relative to 2006 due to lower per barrel consumption volumes and slightly lower natural gas prices. Energy consumption decreased by 14 per cent on a per barrel basis in 2007, primarily due to improved operational efficiency. In part, such improvements were because Stage 3 units were being commissioned during the first nine months of 2006, increasing energy requirements without an offsetting production increase as Stage 3 production did not commence until September 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 under way and the status of the projects. Non-production costs totalled $14 million in each of the fourth quarters of 2007 and 2006. However, on an annual basis, non-production costs totalled $63 million in 2007, a decrease of $7 million compared to 2006. More spending was incurred in 2007 related to R&D activities, such as drilling for further delineation of current and new mines, as well as Canadian Oil Sands' larger working interest ownership. However, non-production costs in the same period of 2006 included $20 million of Stage 3 commissioning and start-up costs.

Crown Royalties

Under Alberta's current 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 $54 million to $137 million, or $12.81 per barrel, in the fourth quarter of 2007 from $83 million, or $8.23 per barrel, in the comparable 2006 quarter. On an annual basis, Crown royalties increased by $253 million to total $485 million, or $11.83 per barrel in 2007, relative to the prior year, which reported $232 million, or $6.93 per barrel. Compared with our most recent 2007 guidance, actual Crown royalties exceeded our anticipated expense by $31 million, or $0.69 per barrel, primarily as a result of higher actual revenues, as discussed earlier in this MD&A. The increase in 2007 Crown royalties relative to 2006 reflects a shift to the higher 25 per cent royalty rate, which occurred in the second quarter of 2006, higher net revenues, and a larger Syncrude working interest. The shift to the higher Crown royalty 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. See the "Crown Royalty Changes" section of this MD&A for more information.



Interest, Net

Three Months Ended Twelve Months Ended

December 31 December 31

2007 2006 2007 2006

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

Interest expense on

long-term debt $ 20 $ 25 $ 91 $ 102

Interest income and other (3) (1) (6) (4)

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

Interest expense, net $ 17 $ 24 $ 85 $ 98

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

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


The Trust's net interest expense recorded in the quarter and year-ended December 31, 2007 decreased relative to the comparable periods in 2006, primarily reflecting the repayments of $195 million of medium term notes in January 2007 and US$70 million Senior Notes in May 2007.



Depreciation, depletion and accretion expense

Three Months Ended Twelve Months Ended

December 31 December 31

($ millions) 2007 2006 2007 2006

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

Depreciation and depletion

expense $ 88 $ 73 $ 340 $ 246

Accretion expense 3 2 11 9

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

$ 91 $ 75 $ 351 $ 255

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

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


Depreciation and depletion ("D&D") expense for the fourth quarter and year-ended 2007 rose by $15 million and $94 million, respectively, compared to the same periods of 2006, reflecting a higher per barrel D&D rate and an increase in production volumes. 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 December 31, 2006 reserve report is summarized in our 2006 Annual Information Form and can be found at www.sedar.com, or on our website at www.cos-trust.com under "investor information".

We anticipate the Trust's D&D rate will increase to approximately $11 per barrel in 2008, based on preliminary 2007 reserve report estimates, which include updated reserve and future development cost figures. While the Trust does not expect any material revisions to our reserve figures in our December 31, 2007 reserve report, future development costs have continued to increase, mainly as a result of higher projected sustaining capital expenditures, consistent with recent experience. We expect to provide our updated 2008 D&D rate in our first quarter 2008 MD&A.

The Trust recorded a $37 million increase to its asset retirement obligation ("ARO") liability and corresponding asset at December 31, 2007, which primarily reflects the Trust's share of increased cost estimates to comply with new material handling requirements under the Alberta Environmental Protection and Enhancement Act Approval. The new requirements resulted in higher cost estimates for soil salvage, soil placement thickness and soil layering. The increased ARO liability is expected to marginally increase total accretion expense to $14 million in 2008 from 2007 levels of $11 million.



Foreign exchange loss (gain)

Three Months Ended Twelve Months Ended

December 31 December 31

($ millions) 2007 2006 2007 2006

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

Unrealized foreign exchange

loss (gain) $ (7) $ 47 $ (153) $ (1)

Realized foreign exchange loss

(gain) 2 (7) 36 (4)

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

Total foreign exchange loss

(gain) $ (5) $ 40 $ (117) $ (5)

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

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

Foreign exchange rates as at:

($US/$Cdn) 2007 2006 2005

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

December 31 $ 1.01 $ 0.86 $ 0.86

September 30 $ 1.00 $ 0.90

June 30 $ 0.94 $ 0.90

March 31 $ 0.87 $ 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. The 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 A/P 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 fourth quarter of 2007, Canadian Oil Sands' total FX gains mainly related to the revaluation of our U.S. dollar denominated debt. The debt revaluation in the fourth quarter of 2007 resulted in an unrealized FX gain of $7 million, reflecting continued strengthening of the Canadian dollar on December 31, 2007 from September 30, 2007. By comparison, the value of the Canadian dollar relative to the U.S. dollar weakened on December 31, 2006 compared with September 30, 2006, resulting in an unrealized FX loss of $47 million in the fourth quarter of 2006.

On an annual basis, total FX gains increased by $112 million in 2007 relative to 2006. Unrealized foreign exchange gains resulting from debt revaluations accounted for $153 million and $1 million of the total FX gains in each of 2007 and 2006, respectively, reflecting a stronger Canadian dollar at the end of each year relative to the prior year December 31 rate. Also included in the year ended December 31, 2007 was an FX gain of $18 million 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. Excluding the realized gains on debt repayment, the significant strengthening of the Canadian dollar in 2007 resulted in a realized loss of $54 million, compared to a $4 million gain in the same period of 2006, primarily attributable to U.S. dollar denominated accounts receivable and cash balances.

Future Income Tax and other

Canadian Oil Sands' future income taxes on its Consolidated Balance Sheet represent the net difference between tax values and accounting values, referred to as temporary differences, tax-effected at substantively enacted tax rates expected to apply when the differences reverse. A $118 million future income tax recovery was recorded in the fourth quarter of 2007 and was primarily the result of corporate tax rate reductions, partially offset by increases in our taxable temporary differences. In December 2007, the federal government substantively enacted tax rate reductions, which lowered the corporate tax rates for the years 2008 to 2012 and beyond. The corporate tax rates were reduced from 20.5 per cent in 2008 to an ultimate rate of 15 per cent in 2012 and future years. These rate reductions also lower the trust taxation rate from 31.5 per cent, as enacted by the federal government in the second quarter of 2007 for years commencing in 2011, to 29.5 per cent and 28 per cent in 2011 and 2012 (and future years), respectively. As a result of these rate changes, Canadian Oil Sands recorded a future income tax recovery of $153 million in the fourth quarter of 2007. Somewhat offsetting this large future income tax recovery in the fourth quarter of 2007 was a $35 million future income tax expense, primarily attributable to having increased Canadian Oil Sands' taxable temporary differences by utilizing more tax pools to shelter current quarter taxable income compared to deductions taken for accounting purposes. Conversely in the same quarter of 2006, the Trust recorded a future income tax expense of $39 million, which was comprised of $16 million expense related to changes in temporary differences and a $23 million expense adjustment pertaining to tax rates applied to certain temporary differences.

In addition to the fourth quarter net recovery amount, the Trust's annual 2007 future income tax and other expense of $579 million includes an additional $701 million future income tax expense and corresponding future income tax liability related to the Trust's temporary differences, reflecting the substantive enactment of Bill C-52 in June 2007. Prior to this legislation, which introduces a new tax on distributions from Canadian public trusts starting in 2011, Canadian Oil Sands' future income taxes reflected only those temporary differences in the Trust's subsidiaries. While net income in 2007 was reduced significantly by this future tax adjustment, there was no impact on cash from operating activities. This significant expense was partially offset by a future income tax recovery of approximately $40 million recorded in the second quarter of 2007 at the subsidiary level relating to the federal tax rate reduction from 19 per cent to 18.5 per cent in 2011. The remaining $34 million of future income tax and other expense recorded in 2007 primarily relates to changes to taxable temporary differences. In the prior year, the Trust recorded an $18 million future income tax expense, which was comprised of a $29 million future income tax recovery related to substantively enacted reductions to future federal and provincial tax rates and the elimination of the federal surtax, offset by an expense of $47 million related to changes in temporary differences.

In response to the income trust tax changes, Canadian Oil Sands continues to evaluate alternatives as to the best structure for its Unitholders in the future. In Alberta where the Trust is registered, a corporation is subject to a lower overall tax rate than the rate that will apply to income trusts post- 2010. The federal government has confirmed that it intends to allow corporate conversions to occur on a tax-deferred basis, so given current conditions, we will most likely convert to a corporate structure. However, the rules of transitioning to a corporate structure have yet to be established. Until 2011, the Trust plans to retain the flow-through advantages of its trust structure, unless circumstances arise that favour a faster transition to an alternate structure. 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 to generate cash from operating activities.

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.

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 December 31, 2007.



LIQUIDITY AND CAPITAL RESOURCES

December 31

($ millions) 2007 2006

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

Long-term debt $ 1,218 $ 1,644

Cash and cash equivalents (268) (353)

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

Net debt $ 950 $ 1,291

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

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

Unitholders' equity $ 4,172 $ 3,956

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

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

Total capitalization(1) $ 5,122 $ 5,247

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

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

(1) Net debt plus Unitholders' equity

Net debt to total capitalization (%) 19 25

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


In January 2007, Canadian Oil Sands paid $237.5 million in cash and issued 8.2 million Units valued at $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 drawings on the Trust's $800 million operating credit facility, which were subsequently repaid. 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. Including an unrealized foreign exchange gain of $153 million, the Trust's long-term debt decreased by $426 million to $1.2 billion at December 31, 2007 and net debt dropped to $950 million.

As at December 31, 2007, the Trust's unutilized credit facilities amounted to $808 million, net of letters of credit issued against its $40 million revolving term facility and an additional $45 million line of credit. The Trust has a $150 million medium term note maturing on April 9, 2008, which the Trust currently anticipates refinancing on maturity using its available credit facilities.

In response to the income trust tax changes, Canadian Oil Sands adjusted its financial plan by raising its long-term net debt target to $1.6 billion by 2010 from $1.2 billion, which supports fuller payout of cash from operating activities and conserves tax pools. 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, Syncrude operational performance, and the timing of distribution changes vary from our assumptions.

The Units issued from treasury in January 2007 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 increased by net income of $743 million, but reduced by distributions of $791 million recorded on a year-to-date basis.



UNITHOLDER DISTRIBUTIONS

Three Months Ended Twelve Months Ended

December 31 December 31

($ millions) 2007 2006 2007 2006

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

Cash from operating

activities $ 367 $ 412 $ 1,377 $ 1,142

Net income $ 515 $ 128 $ 743 $ 834

Unitholder distributions $ 264 $ 140 $ 791 $ 512

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

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

Excess (shortfall) of cash from

operating activities over

Unitholder distributions(1) $ 103 $ 272 $ 586 $ 630

Excess (shortfall) of net

income over Unitholder

distributions(2) $ 251 $ (12) $ (48) $ 322

(1) Cash from operating activities less Unitholder distributions.

(2) Net income less Unitholder distributions.

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


Cash from operating activities and net income can fluctuate dramatically from period to period, reflecting variability in operational performance, WTI prices, SCO differentials and FX rates. Given these risks, we strive to smooth out the variability of distributions by taking a longer-term view in the context of our outlook for our operating and business environment, including monitoring of our net debt relative to our target and assessing our capital expenditure commitments. In that regard, we may distribute more or less in a period than we generate in cash from operating activities or net income. The distribution depends on numerous factors including our financial and operational performance, working capital requirements and future capital expenditures. Despite management's goal to strive for relative distribution stability, the highly variable nature of these considerations introduces risk in our ability to sustain or stabilize distributions. Therefore, unwarranted expectations in the stability or sustainment of distributions should not be implied. In addition, the taxation of income trusts commencing January 1, 2011 likely will materially alter our cash from operating activities and consequently distribution levels.

A Unitholder distributions schedule pertaining to the quarter ended December 31 is included in Note 12 to the unaudited Consolidated Financial Statements. The Trust uses debt and equity financing to the extent that cash from operating activities is insufficient to fund distributions, capital expenditures, reclamation trust contributions, acquisitions and working capital changes from financing and investing activities. Cash from operating activities exceeded distributions by $103 million in the fourth quarter of 2007. This excess amount was sufficient to pay the Trust's capital expenditures and reclamation funding of $58 million. On a year-to-date basis, the $586 million excess of cash from operating activities over Unitholder distributions exceeded capital expenditures and reclamation funding totalling $190 million and debt repayments of $272 million. Capital expenditures are discussed more fully in the "Capital Expenditures" section of this MD&A.

Net income also exceeded distributions in the fourth quarter of 2007. However, on an annual basis, distributions exceeded net income in 2007 as a result of the $701 million future income tax expense recorded in the second quarter related to the enactment of Bill C-52. The future income tax expense is a non-cash item that does not affect the Trust's cash from operating activities or its balance sheet strength and ability to pay distributions over the next several years. As a result, the Trust paid the distribution despite the lower net income. As indicated in previous disclosures, the Trust suspended its Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan ("DRIP") and, as such, the DRIP did not provide additional equity financing in 2007.

In determining the Trust's distributions, Canadian Oil Sands also considers funding for its significant operating obligations, which are included in cash from operating activities. Such obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to approximately $38 million and $30 million in 2007 and 2006, respectively, and approximated the related expense for both pension and reclamation of $41 million and $42 million in each of the years, respectively. While our share of Syncrude's annual pension funding has increased modestly as a result of the most recent actuarial valuation and our share of Syncrude's future reclamation costs has also increased, we currently do not anticipate any material funding increases related to these items for at least the next few years.

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-book capitalization at an amount less than 55 per cent. With a current net debt-to-book capitalization of approximately 19 per cent, a significant increase in debt or decrease in equity would be required to negatively impact the Trust's financial flexibility.

On January 30, 2008, the Trust declared a 36 per cent increase to its quarterly distribution to $0.75 per Unit for total distributions of $359 million. The distribution will be paid on February 29, 2008 to Unitholders of record on February 12, 2008. With the completion of the Stage 3 project, robust crude oil prices and our current net debt level relative to our long- term target, the Trust has more than doubled its quarterly distribution since the first quarter of 2007. The rise in the Trust's distribution levels is consistent with our previous indications that we would be moving to a fuller payout of cash from operating activities unless capital investment or acquisition opportunities exist that we believe offer Unitholders enhanced value. With Syncrude's existing productive capacity, we are targeting a long- term net debt level of about $1.6 billion by the end of 2010 and will reconsider this target in light of future Syncrude growth and other acquisition opportunities.

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. The productive capacity of Syncrude's operations was defined previously in the "Review of Syncrude Operations" section of this MD&A.

In the last quarter of 2007, capital expenditures totalled $55 million, comparable to expenditures of $57 million in the same quarter of 2006. The Syncrude Emissions Reduction ("SER") project accounted for $18 million and $13 million of the capital spent in the fourth quarters of 2007 and 2006, respectively, with the remaining amounts in each quarter pertaining to the maintenance of Syncrude's existing plant and facilities, all of which are considered sustaining capital. Sustaining capital expenditures on a per barrel basis were approximately $5.00 in each of the fourth quarters of 2007 and 2006.

On a year-to-date basis, capital expenditures totalled $183 million in 2007, a decrease of $117 million compared to 2006, as a result of the Stage 3 completion in 2006. Actual capital expenditures were slightly lower than our anticipated spending of $199 million provided in our October 31, 2007 guidance for 2007, reflecting a deferral in actual spending for maintenance of business/other capital. In 2006, Stage 3 costs accounted for $121 million of the $300 million in total capital expenditures. Annual sustaining capital expenditures in 2007 were $4.46 per barrel compared with $5.01 per barrel recorded in the same period in 2006.

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 ($284 million net to the Trust based on its 36.74 per cent working interest), as previously disclosed, there are indications of upward cost pressure on the project. Syncrude is currently performing a full review of the project and will provide updates to cost estimates and timing after such review has been completed. The Trust's share of the SER project expenditures incurred to date is approximately $106 million, with the remaining costs to be incurred in the next three years to coordinate with equipment turnaround schedules.

Our sustaining capital expenditures, including the SER project, are estimated at approximately $7 per barrel in 2008. The increase in projected 2008 sustaining capital costs relative to 2007 actual costs of $4.46 per barrel reflects an escalation in material and labour costs for most capital projects. Recent labour settlements in Alberta for construction workers will add to hourly wage rates and increase sustaining capital costs over the coming several years. As well, we expect the cost of construction materials, such as fabricated steel, electrical components and mechanical equipment to continue to rise.

In addition to inflationary cost pressures that will continue to impact our longer-term average sustaining capital expenditures estimate of about $5 per barrel, we expect to incur costs for large environmental and infrastructure projects. These are projects that are required to support the on-going operation, but do not add to production volumes. In addition to the SER project, Syncrude expects to proceed with other environmental and infrastructure projects. These projects include the relocation of certain mining trains and tailings systems, which is required as mining operations progress across the active leases. Tailings system projects also include initiatives to improve and supplement the effectiveness of systems used to separate water from sand and clay so that the water can be recycled back to the operation and solids can be incorporated into the final reclamation landscapes. These infrastructure projects, including SER, are expected to add about $2 to $5 per barrel annually to sustaining capital expenditures over the next few years. Our per barrel estimates are based on estimated annual Syncrude production, which increases from 115 million barrels in 2008, or 42 million barrels net to the Trust, to 128 million barrels, or 47 million barrels net to the Trust, at design capacity.

Syncrude's next significant growth stage is anticipated to be the Stage 3 debottleneck. We estimate the project will increase Syncrude productive capacity by 30,000 to 50,000 barrels per day. Based on the current business environment, this incremental production is expected to be achieved by 2012. Following the Stage 3 debottleneck, the Stage 4 expansion is planned to grow Syncrude capacity by a further 100,000 barrels per day, resulting in total productive capacity of approximately 500,000 barrels per day post-2016. Spending on each of these respective projects is expected to commence several years prior to the incremental production coming on-stream. The plans for these projects are preliminary and have not been approved by the Syncrude owners, and as such, may change. No cost estimates have been provided for either of these projects because they are still in the early planning stages.

At the end of May 2007, Canadian Oil Sands completed the sale of the remaining conventional properties that 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 Statements of Income and Comprehensive Income.

UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY

The Trust's Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $19 billion with 479 million Units outstanding and a closing price of $38.71 per Unit on December 31, 2007.



Canadian Oil Sands Trust - Trading Activity

Fourth

Quarter December November October

2007 2007 2007 2007

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

Unit price

High $ 38.88 $ 38.88 $ 38.45 $ 35.82

Low $ 30.70 $ 34.81 $ 33.57 $ 30.70

Close $ 38.71 $ 38.71 $ 36.24 $ 34.70

Volume traded (millions) 91.2 23.3 29.1 38.8

Weighted average Trust units

outstanding (millions) 479 479 479 479

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

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


CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The following table outlines the significant financial obligations that are known as of January 30, 2008, which represent future cash payments that the Trust is required to make under existing contractual agreements that it has entered into either directly, or as a 36.74 per cent owner in the Syncrude Joint Venture:



Payments due by period

less than After

($ millions) Total 1 year 1-3 years 4-5 years 5 years

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

Long-term debt(1) 1,229 166 447 296 320

Capital expenditure

commitments(2) 250 84 166 - -

Pension plan solvency

deficiency payments(3) 122 14 42 17 49

Management services

agreement(4) 153 17 51 34 51

Pipeline commitments(5) 575 25 59 40 451

Other obligations(6) 288 166 81 9 32

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

2,617 472 847 396 903

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

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

(1) Actual payments differ from the carrying value, which is stated at

amortized cost. While there is approximately $150 million of debt

maturing in 2008, Canadian Oil Sands' intention is to refinance such

debt.

(2) Capital expenditure commitments are primarily comprised of our

36.74 per cent share of Syncrude's Emissions Reduction project.

(3) We are responsible for funding our 36.74 per cent share of Syncrude

Canada's registered pension plan solvency deficiency, which was

confirmed in the December 31, 2006 actuarial valuation that was

completed in 2007.

(4) Reflects our 36.74 per cent share of Syncrude Canada's annual fixed

service fees under the agreement.

(5) Reflects our 36.74 per cent share of the AOSPL pipeline commitment as

a Syncrude Joint Venture owner, and various other Canadian Oil Sands

pipeline commitments for transportation access beyond Edmonton.

(6) These obligations primarily include our 36.74 per cent share of the

minimum payments required under Syncrude's commitments for natural

gas purchases and employee retention program. Other items include,

but are not limited to, annual disposal fees for the flue gas

desulphurization unit and capital and operating lease obligations.


In total, the Trust's financial obligations have decreased by approximately $1.0 billion relative to the prior year-end. The two most significant changes are: (1) a reduction in long-term debt of $415 million, as discussed in the "Liquidity and Capital Resources" section of this MD&A, and (2) a $475 million payment, comprised of cash and Units, to Talisman on January 2, 2007 for the additional 1.25 per cent Syncrude working interest acquisition. Natural gas purchase commitments have also decreased by approximately $60 million, mainly reflecting timing of natural gas contract renewals. 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 year.

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 December 31, 2007 and, based on current expectations, the Trust remains unhedged on its crude oil price exposure. However, we may hedge our crude oil production in the future as part of our growth financing strategies.

Foreign Currency Hedging

As at December 31, 2007, we no longer had any foreign currency hedges in place. 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. On December 31, 2007, we drew $16 million on our credit facilities, which bear interest at a floating market-based rate. The year-end draw was repaid on January 2, 2008; therefore we had minimal interest rate exposure at year-end. The Trust's other floating rate debt was repaid in January 2007.

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 financial derivatives outstanding at December 31, 2007.

FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of November 16, 2007, approximately 32 per cent of our Unitholders are non-Canadian residents with the remaining 68 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 regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of February 12, 2008. The Trust posts its foreign ownership levels and describes its steps for managing these levels on its web site (www.cos- rust.com under "investor information", "frequently asked questions"). These steps are also described in the Trust's 2007 Annual Information Form.

CROWN ROYALTY CHANGES

The Alberta government has announced that it plans to introduce new Crown royalty terms, effective January 1, 2009, for the energy sector. The new royalty regime for oil sands projects is to be based on a sliding scale royalty rate ranging from one to nine per cent pre-payout and 25 to 40 per cent post-payout that responds to WTI price levels. The pre-payout rate is proposed to start at one per cent of revenue and increase for every dollar oil is priced above $55 per barrel, to a maximum of nine per cent of revenue when oil is priced at $120 per barrel or higher. The net royalty applied post- payout will start at 25 per cent of net revenue and increase for every dollar oil is priced above $55 per barrel up to a maximum of 40 per cent of net revenue when oil reaches $120 per barrel or higher.

The Syncrude Joint Venture owners have a Crown Agreement with the Alberta government that codifies the current royalty terms of 25 per cent of net SCO revenues to December 31, 2015. The Agreement also provides Syncrude with the option to convert to a bitumen-based royalty, consistent with the rest of the industry, prior to 2010. Canadian Oil Sands, as one of the Syncrude owners, is currently in discussions with the Alberta government regarding both the conversion to a bitumen-based royalty and an equitable solution to offset Syncrude's transition to the higher generic royalty rate prior to 2016. Canadian Oil Sands is of the view that any transition to the new generic royalty terms must recognize and preserve our legal rights to the embedded value in Syncrude's contract with the government.

GREENHOUSE GAS EMISSIONS REDUCTION REQUIREMENTS

In 2007, the Alberta government introduced legislation ("Bill 3") to reduce greenhouse gas ("GHG") emission intensity. Bill 3 states that facilities emitting more than 100,000 tonnes of GHGs a year ("Large Emitters") must reduce their emissions intensity (emissions per unit of production) by 12 per cent over the average emissions intensity levels of 2003, 2004 and 2005; if they are unable 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.

In the last six months of 2007, Syncrude has accrued approximately $0.19 per barrel for compliance with the Alberta government's Bill 3 legislation, which is reflected in the Trust's operating costs. The cost estimate remains preliminary pending Syncrude's actual C02 emission intensity level and clarification from the Alberta government regarding details of the Bill 3 implementation. No cost estimates are available yet for future years.

The federal government also released new GHG and air pollutant emission reduction targets on April 27, 2007 in its Regulatory Framework for Air Emissions (the "Framework"). The Framework forms the basis for consultations, with draft regulations anticipated to be released in spring 2008. Until further detail is provided regarding the specifics of any new federal regulation, Canadian Oil Sands is unable to provide information on the potential impact.

2008 OUTLOOK

Canadian Oil Sands Trust's Outlook for 2008 is similar to our Budget announced on December 14, 2007, other than an increase to operating expenses to reflect currently estimated repair costs of $50 million ($18 million, net to the Trust) for the ESPs damaged in the December fire. Other minor changes to the budget are a result of adjusting estimated December 31, 2007 amounts to actual.

On January 29, 2008 production from the Syncrude facility was suspended following several instrument freeze-ups as a result of extremely cold weather conditions. Operation of a number of units was disrupted. Syncrude has advised that it is focusing efforts on the safe and reliable restart of affected units, and expects that it will take several days to fully restore operations. At this time, investigations are too preliminary to know the impact, if any, on our 2008 Outlook; accordingly, we have not adjusted our current Outlook for this operational incident.

Annual 2008 Syncrude production is estimated to total 115 million barrels with a range of 110 to 120 million barrels (net to the Trust, equivalent to 42 million barrels with a range of 40 to 44 million barrels). The single point production estimate incorporates Syncrude's extensive 2008 maintenance program, an allowance for unplanned outages, and recognition that Syncrude is still working to establish reliable Stage 3 design rates. During 2008, Syncrude plans to perform turnarounds of Coker 8-1 (second quarter) and Coker 8-2 (third quarter) as well as associated maintenance work on other units. The production range reflects our current best estimate of the upside and downside in volumes Syncrude could experience, depending on operational reliability, in 2008.

For the anticipated 2008 production target, purchased bitumen should not be required; however, Syncrude has decided to increase its flexibility in its SCO production by arranging for the purchase of incremental bitumen in 2008 when internal bitumen supply shortfalls may occur. During the year, productivity of the mining operations may be reduced due to maintenance or extreme weather conditions, resulting in temporary decreases of internally produced bitumen. This additional purchased bitumen supply will support increased production during times when excess upgrading capacity is available. Syncrude is focused on improving reliability in the mining operations to meet the rising needs of the upgrader as we ramp up production to design capacity rates. We currently estimate imported bitumen volumes in 2008 will be less than five per cent of total supply at Syncrude and, therefore we do not anticipate such purchases to have a material impact on Syncrude's production, and correspondingly, our financial results.

We expect the Trust's revenues in 2008 to total $3.3 billion, based on an average WTI price of US$80 per barrel, an average foreign exchange rate of $1.00 US/Cdn, and an average SCO discount to Canadian dollar WTI of $2.50 per barrel. We are budgeting operating costs of $26.83 per barrel, which includes $6.48 per barrel for purchased energy based on an average AECO natural gas price of $7.00 per gigajoule for 2008. We anticipate Crown royalties expense to total $443 million, or $10.49 per barrel, in 2008.

We anticipate our cash from operating activities to total $1.6 billion, or $3.24 per Unit. We are estimating our share of Syncrude's capital expenditures to total $279 million with approximately 82 per cent of the 2008 capital expenditures directed to maintenance of operations and the remaining 18 per cent to the SER project.

Distributions paid in 2007 and 2008 are expected to be 99 per cent and 100 per cent taxable, respectively, as other income. The actual taxability of the distributions will be determined and reported to Unitholders prior to the end of the first quarters of 2008 and 2009, respectively.

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 SCO relative to crude benchmarks; however, these factors are difficult to predict.



2008 Outlook Sensitivity Analysis

Cash from Operating

Activities

Annual(2) Increase

Variable(1) Sensitivity $ millions $/Trust unit

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

Syncrude operating costs decrease C$1.00/bbl 32 0.07

Syncrude operating costs decrease C$50 million 14 0.03

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

Syncrude production increase 2 million bbls 39 0.08

Canadian dollar weakening US$0.01/C$ 23 0.05

AECO natural gas price decrease C$0.50/GJ 15 0.03

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

opposite cash from operating activities impacts.

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

result in the annual impact.



CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(unaudited)

Three Months Ended Twelve Months Ended

($ millions, except December 31 December 31

per Unit amounts) 2007 2006 2007 2006

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

Revenues $ 1,007 $ 736 $ 3,633 $ 2,692

Crude oil purchases and

transportation expense (57) (90) (383) (260)

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

950 646 3,250 2,432

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

Expenses:

Operating 293 239 1,034 907

Non-production 14 14 63 70

Crown royalties 137 83 485 232

Administration 6 5 20 17

Insurance 2 1 8 6

Interest, net (Note 11) 17 24 85 98

Depreciation, depletion and

accretion 91 75 351 255

Foreign exchange loss (gain) (5) 40 (117) (5)

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

555 481 1,929 1,580

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

Earnings before taxes from

continuing operations 395 165 1,321 852

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

Future income tax expense

(recovery) and other (Note 10) (118) 39 579 17

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

Net income from continuing

operations 513 126 742 835

Income (loss) from discontinued

operations 2 2 1 (1)

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

Net income 515 128 743 834

Other comprehensive loss, net

of income taxes

Reclassification of derivative

gains to net income - - (6) -

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

Comprehensive income $ 515 $ 128 $ 737 $ 834

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

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

Weighted average Trust Units

(millions) 479 469 479 466

Trust Units, end of period

(millions) 479 471 479 471

Net income per Trust Unit(1):

Basic $ 1.07 $ 0.27 $ 1.55 $ 1.79

Diluted $ 1.07 $ 0.27 $ 1.54 $ 1.78

(1) Discontinued operations did not have a material impact on basic or

diluted net income per Trust Unit.



CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY

(unaudited)

Three Months Ended Twelve Months Ended

December 31 December 31

($ millions) 2007 2006 2007 2006

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

Retained earnings

Balance, beginning of period,

as previously reported $ 1,392 $ 1,704 $ 1,692 $ 1,370

Transition adjustment on

adoption of Financial

Instruments standards (Note 2) - - (1) -

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

Balance, beginning of period,

adjusted 1,392 1,704 1,691 1,370

Net income 515 128 743 834

Unitholder distributions

(Note 12) (264) (140) (791) (512)

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

Balance, end of period 1,643 1,692 1,643 1,692

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

Accumulated other comprehensive

income

Balance, beginning of period 24 - - -

Transition adjustment on

adoption of Financial

Instruments standards (Note 2) - - 30 -

Other comprehensive loss - - (6) -

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

Balance, end of period 24 - 24 -

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

Unitholders' capital

Balance, beginning of period 2,499 2,190 2,260 2,010

Issuance of Trust Units

(Note 5) 1 70 240 250

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

Balance, end of period 2,500 2,260 2,500 2,260

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

Contributed surplus

Balance, beginning of period 5 3 4 3

Stock-based compensation - 1 1 1

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

Balance, end of period 5 4 5 4

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

Total Unitholders' equity $ 4,172 $ 3,956 $ 4,172 $ 3,956

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

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



CANADIAN OIL SANDS TRUST

CONSOLIDATED BALANCE SHEETS

AS AT DECEMBER 31

(unaudited)

($ millions) 2007 2006

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

ASSETS

Current assets:

Cash and cash equivalents $ 268 $ 353

Accounts receivable 379 244

Inventories 102 84

Prepaid expenses 6 7

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

755 688

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

Property, plant and equipment, net 6,427 5,739

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

Other assets

Goodwill 52 52

Assets held for sale - 6

Reclamation trust 37 30

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

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

89 105

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

$ 7,271 $ 6,532

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

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

LIABILITIES AND UNITHOLDERS' EQUITY

Current liabilities:

Accounts payable and accrued liabilities $ 289 $ 304

Current portion of employee future benefits 16 11

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

305 315

Employee future benefits and other liabilities 128 100

Long-term debt (Notes 2,8) 1,218 1,644

Asset retirement obligation (Note 9) 226 173

Deferred currency hedging gains (Note 2) - 35

Future income taxes (Note 10) 1,222 309

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

3,099 2,576

Unitholders' equity 4,172 3,956

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

$ 7,271 $ 6,532

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

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



CANADIAN OIL SANDS TRUST

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

Three Months Ended Twelve Months Ended

December 31 December 31

($ millions) 2007 2006 2007 2006

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

Cash provided by (used in):

Cash from (used in) operating

activities

Net income $ 515 $ 128 $ 743 $ 834

Items not requiring outlay

of cash:

Depreciation, depletion

and accretion 91 75 351 255

Foreign exchange on

long-term debt (7) 47 (153) (1)

Future income tax expense

(recovery) (118) 39 578 18

Other - 1 (3) 4

Net change in deferred items 28 6 26 10

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

Funds from operations 509 296 1,542 1,120

Change in non-cash working

capital (142) 116 (165) 22

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

Cash from operating

activities 367 412 1,377 1,142

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

Cash from (used in) financing

activities

Repayment of medium term and

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

Net drawdown (repayment) of

bank credit facilities 16 - 16 (92)

Unitholder distributions

(Note 12) (264) (140) (791) (512)

Issuance of Trust Units

(Note 5) 2 70 3 250

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

Cash used in financing

activities (246) (70) (1,044) (354)

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

Cash from (used in) investing

activities

Capital expenditures (55) (57) (183) (300)

Acquisition of additional

Syncrude working interest

(Note 4) - - (231) -

Acquisition of Canadian

Arctic Gas Ltd. - (48) - (199)

Disposition of properties - 28 4 28

Reclamation trust funding (3) (1) (7) (5)

Change in non-cash working

capital 4 3 (1) (47)

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

Cash used in investing

activities (54) (75) (418) (523)

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

Increase (decrease) in cash and

cash equivalents 67 267 (85) 265

Cash and cash equivalents at

beginning of period 201 86 353 88

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

Cash and cash equivalents at

end of period $ 268 $ 353 $ 268 $ 353

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

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

Cash and cash equivalents

consist of:

Cash $ 4 $ 8

Short-term investments 264 345

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

$ 268 $ 353

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


NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2007

(Tabular amounts expressed in millions of Canadian dollars, except where

otherwise noted.)

1) BASIS OF PRESENTATION

The interim consolidated financial statements include the accounts of

Canadian Oil Sands Trust and its subsidiaries (collectively, the

"Trust" or "Canadian Oil Sands"), and are presented in accordance

with Canadian generally accepted accounting principles ("GAAP"). The

interim consolidated financial statements have been prepared

following the same accounting policies and methods of computation as

the consolidated financial statements for the year ended December 31,

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

are incremental to those included with the annual consolidated

financial statements. The interim consolidated financial statements

should be read in conjunction with the consolidated financial

statements and the notes thereto in the Trust's annual report for the

year ended December 31, 2006.

2) CHANGES IN ACCOUNTING POLICIES

Effective January 1, 2007, Canadian Oil Sands adopted the

requirements of the Canadian Institute of Chartered Accountants

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

framework, which encompasses the following new CICA Handbook

sections: 3855 Financial Instruments - Recognition and Measurement,

1530 Comprehensive income, and 3861 Financial Instruments -

Disclosure and Presentation. The CICA Handbook section 3865 Hedges is

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

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

has only applied the transitional provisions of this Handbook

section.

These new Handbook sections provide comprehensive requirements for

the recognition and measurement of financial instruments, and

introduce a new component of equity referred to as accumulated other

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

provisions of all of the new sections, the comparative interim

consolidated financial statements have not been restated.

Under these new standards, all financial instruments, including

derivatives, are recognized on the Trust's Consolidated Balance

Sheet. Derivatives are measured at fair value with unrealized gains

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

measured at fair value with unrealized gains and losses reported in

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

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

using the effective interest rate method. Transaction costs are added

to the amount of the associated financial instrument and amortized

accordingly.

Several adjustments to the Trust's consolidated financial statements

were required upon transition to the new financial instruments

framework, which were the following:

Deferred currency hedging gains

In 1996, Canadian Oil Sands entered into currency hedging contracts

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

Sands unwound various positions and exchanged the resulting gains for

adjustments to other existing currency contracts. These gains were

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

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

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

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

hedging contracts would have expired had they not been unwound.

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

were reclassified to opening AOCI. The related future income tax

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

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

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 was settled

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 May 15, 2007.

Determination of fair value

The fair value of the Trust's long-term debt is determined based on

market price indications. In fair valuing its derivatives, the Trust

utilizes a valuation technique using available market prices.

Comprehensive income

The Consolidated Statement of Income and Comprehensive Income

includes a new line item for comprehensive income, which includes

both net income and other comprehensive income. Other comprehensive

income includes recognition of unrealized gains and losses on

derivatives and hedging gains that were previously deferred, net of

the related future income tax on those items.

3) FUTURE CHANGES IN ACCOUNTING POLICIES

Capital disclosures

The CICA issued a new accounting standard, Section 1535 Capital

Disclosures, which requires the disclosure of both qualitative and

quantitative information that provides users of financial statements

with information to evaluate the entity's 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 an 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

$238 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 twelve months ended December 31, 2007, approximately

8.2 million Units were issued for proceeds of $237 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 0.3 3

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

Balance, December 31, 2007 479.4 $ 2,500

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


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 twelve months ended

December 31, 2007 and 2006 is based on its 36.74 per cent and 35.49

per cent working interests in each of 2007 and 2006, respectively.



The costs have been recorded in operating expense as follows:

Three Months Ended Twelve Months Ended

December 31 December 31

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

2007 2006 2007 2006

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

Defined benefit plans:

Pension benefits $ 7 $ 7 $ 27 $ 30

Other benefit plans - 1 3 3

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

$ 7 $ 8 $ 30 $ 33

Defined contribution plans 1 - 2 2

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

Total Benefit cost $ 8 $ 8 $ 32 $ 35

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

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

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 of 2007 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 December 31, 2007, $16 million was drawn on

this facility (2006 - nil).

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.

Canadian Oil Sands intends to refinance on a long-term basis the

5.75% medium term notes that are maturing in 2008. The Trust has

$808 million of unutilized operating credit facilities at

December 31, 2007 to draw on to refinance these obligations, and

$800 million of these facilities do not expire until April 27, 2012.

In accordance with EIC-122, debt maturing in 2008 has not been

reclassified to current liabilities.



9) ASSET RETIREMENT OBLIGATION ("ARO")

Three Months Ended Twelve Months Ended

December 31 December 31

2007 2006 2007 2006

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

Asset retirement

obligation, beginning

of period $ 186 $ 153 $ 173 $ 148

Acquired(1) - - 6 -

Liabilities settled - - (1) (2)

Accretion expense 3 2 11 9

Asset retirement obligation

increases 37 18 37 18

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

Asset retirement obligation,

end of period $ 226 $ 173 $ 226 $ 173

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

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

(1) Canadian Oil Sands assumed the asset retirement obligation

relating to the additional 1.25 per cent working interest

acquired on January 2, 2007.


The Trust and each of the other Syncrude owners are liable for their

share of ongoing environmental obligations for the ultimate

reclamation of the Syncrude Joint Venture and the ARO represents the

present value estimate of Canadian Oil Sands' share of the cost to

reclaim the mines. The total undiscounted estimated future cash flows

required to settle the Trust's 36.74% (2006 - 35.49%) share of the

Syncrude obligation increased to $743 million (2006 - $595 million),

which primarily reflects the Trust's share of increased cost

estimates to comply with Syncrude's new Alberta Environmental

Protection and Enhancement Act Approval. The new requirements

resulted in higher cost estimates for soil salvage, soil placement

thickness and soil layering. Discounting these incremental cash flows

resulted in a $37 million increase in the asset retirement obligation

at December 31, 2007.

10) FUTURE INCOME TAX

On June 12, 2007, the new Trust taxation rules previously announced

by the government on October 31, 2006 became substantively enacted.

As a result, the future income tax payable and corresponding future

income tax expense on the Trust's temporary differences between the

accounting basis and the tax basis of its assets and liabilities was

recorded in the second quarter of 2007, which totalled $701 million.

During 2007, the federal government substantively enacted various tax

rate reductions, which lowered the corporate tax rates for the years

2008 to 2012 and beyond. The corporate tax rates were reduced from

20.5% in 2008 to an ultimate rate of 15% in 2012 and future years.

These federal rate reductions also reduce the taxation rate

applicable to trusts from 31.5% to 29.5% starting in 2011 and to 28%

in 2012 and beyond. Canadian Oil Sands applied these rate reductions

to its future income tax calculations in 2007, resulting in a total

future income tax recovery of approximately $193 million, of which

$153 million was recorded in the fourth quarter.



11) INTEREST, NET

Three Months Ended Twelve Months Ended

December 31 December 31

2007 2006 2007 2006

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

Interest expense on

long-term debt

Interest income and other $ 20 $ 25 $ 91 $ 102

(3) (1) (6) (4)

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

Interest expense, net $ 17 $ 24 $ 85 $ 98

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

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


12) 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 to be withheld

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 Twelve Months Ended

December 31 December 31

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

2007 2006 2007 2006

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

Cash from operating

activities $ 367 $ 412 $1,377 $1,142

Add (Deduct):

Capital expenditures (55) (57) (183) (300)

Acquisition of additional

Syncrude working interest - - (231) -

Acquisition of

Canadian Arctic Gas Ltd. - (48) - (199)

Disposition of properties - 28 4 28

Change in non-cash working

capital (1) 4 3 (1) (47)

Reclamation trust funding (3) (1) (7) (5)

Change in cash and cash

equivalents and financing,

net (2) (49) (197) (168) (107)

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

Unitholder distributions $ 264 $ 140 $ 791 $ 512

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

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

Unitholder distributions

per Trust Unit (3) $ 0.55 $ 0.30 $ 1.65 $ 1.10

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

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

(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.



13) SUPPLEMENTARY INFORMATION

Three Months Ended Twelve Months Ended

December 31 December 31

2007 2006 2007 2006

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

Income tax paid $ - $ - $ 1 $ 5

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

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

Interest charges paid $ 13 $ 18 $ 94 $ 100

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

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


Contact Information

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

    or

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

    or

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