Canadian Oil Sands Trust
TSX : COS.UN

Canadian Oil Sands Trust

October 28, 2009 17:42 ET

Canadian Oil Sands Trust Announces 2009 Third Quarter Results

CALGARY, ALBERTA--(Marketwire - Oct. 28, 2009) -

All financial figures are unaudited and in Canadian dollars unless otherwise noted.

Canadian Oil Sands Trust ("Canadian Oil Sands", the "Trust" or "we") (TSX:COS.UN) today announced cash from operating activities of $213 million ($0.44 per Trust unit ("Unit")) for the third quarter of 2009 compared with cash from operating activities of $921 million ($1.91 per Unit) for the same period last year. Year-to-date cash from operating activities decreased to $219 million ($0.45 per Unit) for 2009 from about $1.8 billion ($3.69 per Unit) recorded for the same period of 2008. The decrease in cash from operating activities largely reflects the significant decline in crude oil prices in 2009 over 2008 and increases in non-cash working capital, partially offset by lower Crown royalties.

Net income for the third quarter of 2009 was $247 million, or $0.51 per Unit, compared with net income of $604 million, or $1.25 per Unit, for the 2008 third quarter. Year-to-date, net income in 2009 totaled $336 million, or $0.69 per Unit, down from net income of $1,399 million, or $2.91 per Unit, in 2008. The decline in net income in 2009 reflects the impact of lower crude oil prices and production, partially offset by lower Crown royalties and foreign exchange gains.

The Trust has declared a quarterly distribution amount of $0.35 per Unit for Unitholders of record on November 20, 2009, payable on November 30, 2009; a $0.10 per Unit increase from the distribution paid in the prior quarter.

"Our decision to raise the distribution reflects the increase in crude oil prices and higher Syncrude production volumes, which averaged 312,000 barrels per day during the third quarter," said Marcel Coutu, President and Chief Executive Officer. "Now that the heavy maintenance planned for 2009 is essentially behind us, production should remain strong for the rest of the year."

Mr. Coutu added: "As a pure oil sands investment with all of our production currently un-hedged, our distributions are largely determined by crude oil prices, but also by operating performance and sustaining and expansion capital at Syncrude. Following our transition to a corporate structure in late 2010 or early 2011, we expect to continue paying a dividend that varies according to the impact of crude oil price movements, sustaining and expansion capital at Syncrude and the project's operating performance; simply put, dividend amounts will likely vary, similar to our history of distribution payments."

Sales volumes averaged 115,000 barrels per day during the third quarter of 2009 compared with 117,000 barrels per day during the same period in 2008. Production volumes in the third quarter of 2009 were impacted by unplanned maintenance in Syncrude's vacuum distillation unit.

Year-to-date, sales volumes were lower, averaging 98,000 barrels per day in 2009 compared with 105,000 barrels per day in 2008. Syncrude production in 2009 was reduced by extended turnaround and modification work on Coker 8-3 and related units, and by reliability issues that affected both bitumen production and upgrading. By comparison, production in the first three quarters of 2008 was impacted by the planned turnarounds of Cokers 8-2 and 8-1, bitumen production constraints and a disruption in operations during the first quarter.

Operating costs per barrel during the third quarter of 2009 were $27.80 per barrel, down approximately $4 per barrel compared with the 2008 period as a result of less maintenance activity and lower natural gas prices. Year-to-date, operating costs were $37.39 per barrel in 2009 compared with $36.37 per barrel in 2008, reflecting the impact of lower volumes in 2009.

Capital expenditures year-to-date in 2009 were $308 million compared with $195 million in the same period of 2008, reflecting expenditures for the Syncrude Emissions Reduction project, equipment purchases to improve bitumen production, modifications to the Coker 8-3 complex, construction of tailings facilities, and other infrastructure projects.



CANADIAN OIL SANDS TRUST
Highlights

Three Months Ended Nine Months Ended
September 30 September 30
(millions of Canadian dollars,
except Trust unit and volume
amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------

Net Income $ 247 $ 604 $ 336 $ 1,399
Per Trust unit- Basic & Diluted $ 0.51 $ 1.25 $ 0.69 $ 2.91

Cash from (used in) Operating
Activities $ 213 $ 921 $ 219 $ 1,775
Per Trust unit $ 0.44 $ 1.91 $ 0.45 $ 3.69

Unitholder Distributions $ 121 $ 602 $ 266 $ 1,443
Per Trust unit $ 0.25 $ 1.25 $ 0.55 $ 3.00

Sales Volumes (1)
Total (MMbbls) 10.6 10.8 26.7 28.7
Daily average (bbls) 114,544 116,656 97,684 104,571

Operating Costs per barrel $ 27.80 $ 32.15 $ 37.39 $ 36.37

Net Realized SCO Selling Price per
barrel $ 73.31 $ 127.55 $ 65.67 $ 120.19

West Texas Intermediate (average
$US per barrel) (2) $ 68.24 $ 118.22 $ 57.32 $ 113.52
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(1) The Trust's sales volumes differ from its production volumes due to
changes in inventory, which are primarily in-transit pipeline volumes,
and are net of purchased crude oil volumes.
(2) Pricing obtained from Bloomberg.


2009 Outlook

On October 28, 2009, the Trust revised its 2009 outlook. The 2009 single point production estimate for Syncrude remains 104 million barrels with a narrower 101 to 105 million barrel range.

The 104 million barrel estimate incorporates actual production volumes for the first nine months of 2009 and reliable operations for the remainder of the year. With the planned 2009 maintenance program substantially complete, the Trust expects production volumes and per barrel operating costs in the second half of 2009 to improve relative to the first half of the year. To achieve the outlook production, we are estimating that Syncrude will average approximately 350,000 barrels per day in the last quarter of 2009, which can be achieved in the absence of significant unplanned outages.

We are estimating cash from operating activities of $593 million, or $1.23 per Unit, in 2009. After deducting anticipated capital expenditures of $455 million, the remaining cash from operating activities is $138 million. Revised annual operating costs are estimated at $1,322 million, or about $34.60 per barrel, consisting of $30.30 per barrel of production costs and $4.30 per barrel of purchased energy costs.

For 2009, we are assuming a weighted average WTI crude oil price of U.S. $62 per barrel, an $0.895 U.S./Cdn weighted average foreign exchange rate, and a weighted average $1.15 per barrel SCO discount to Cdn dollar WTI.

More information on the Trust's outlook is provided in the Management's Discussion and Analysis section of this report and the October 28, 2009 guidance document, which is available on the Trust's web site at www.cos-trust.com under "investor information".

Canadian Oil Sands speaks with Canadians about the oil sands

Marcel Coutu, President and Chief Executive Officer, of Canadian Oil Sands was in Hamilton and Toronto on October 15th and 16th to speak with Canadians about the oil sands. Mr. Coutu provided frank insights into how the oil sands are meeting the challenge of improving their environmental performance, the impact of the oil sands on the economy of Canada and local communities, and what all this means to Canadians. To read a copy of his speech and view video clips, please visit www.OilSandsNow.ca.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following Management's Discussion and Analysis ("MD&A") was prepared as of October 28, 2009 and should be read in conjunction with the unaudited interim consolidated financial statements of Canadian Oil Sands Trust ("Canadian Oil Sands" or the "Trust") for the three and nine months ended September 30, 2009 and September 30, 2008, and the audited consolidated financial statements and MD&A of the Trust for the year ended December 31, 2008 and the Trust's Annual Information Form ("AIF") dated March 13, 2009. Additional information on the Trust, including its AIF, is available on SEDAR at www.sedar.com or on the Trust's website at www.cos-trust.com.

ADVISORY- in the interest of providing the Trust's Unitholders and potential investors with information regarding the Trust, including management's assessment of the Trust's future production and cost estimates, plans and operations, certain statements throughout this MD&A and the related press release contain "forward-looking statements" under applicable securities law. Forward-looking statements in this MD&A include, but are not limited to, statements with respect to expectations regarding the impact on future costs as a result of the economic downturn; the cost estimate for the SER project and the expectation that the SER project will significantly reduce total sulphur dioxide and other emissions; the completion date for the SER project; future distributions and any increase or decrease from current payment amounts; the Trust's plans with regard to its net debt level by the end of 2010; plans regarding crude oil hedges and currency hedges in the future; the expected production, revenues and operating costs for 2009 and 2010; the belief that operational reliability will improve over time and with that improvement that operating costs will be reduced; the expected level of sustaining capital for the next few years and longer term; the expectations regarding capital expenditures and operating costs; the expected impact of any current and future environmental legislation, including without limitation, regulations relating to tailings; the expectation that there will not be any material funding increases relative to Syncrude's future reclamation costs or pension funding for the next year; the expected realized selling price, which includes the anticipated differential to WTI, to be received in 2009 for Canadian Oil Sands' product; the potential amount payable in respect of any future income tax liability; the plans regarding future expansions of the Syncrude project and in particular all plans regarding future development; the level of energy consumption in 2009 and beyond; capital expenditures for 2009; the level of natural gas consumption in 2009 and beyond;
the expected price for crude oil and natural gas in 2009 and 2010, and the anticipated impact that certain factors such as natural gas and oil prices, foreign exchange and operating costs have on the Trust's cash from operating activities and net income. You are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although the Trust believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks and other factors which could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A include, but are not limited to: the impacts of regulatory changes especially as such relate to royalties, taxation, and environmental charges; the impact of technology on operations and processes and how new complex technology may not perform as expected; skilled labour shortages and the productivity achieved from labour in the Fort McMurray area; the supply and demand metrics for oil and natural gas; the impact that pipeline capacity and refinery demand have on prices for our products; the unanimous joint venture owner approval for major expansions; the variances of stock market activities generally; global economic environment/volatility of markets; normal risks associated with litigation, general economic, business and market conditions; regulatory change, and such other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by the Trust. You are cautioned that the foregoing list of important factors is not exhaustive. No assurance can be given that the final legislation implementing the federal tax changes regarding income trusts will not be further changed in a manner which adversely affects the Trust and its Unitholders. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and unless required by law, the Trust does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this MD&A are expressly qualified by this cautionary statement.


REVIEW OF SYNCRUDE OPERATIONS

During the third quarter of 2009, crude oil production from the Syncrude Joint Venture ("Syncrude") totaled 28.7 million barrels, or 312,000 barrels per day, compared with 29.1 million barrels, or 316,000 barrels per day, during the same period of 2008. Net to the Trust, production totaled 10.5 million barrels in the third quarter of 2009 compared with 10.7 million barrels in 2008, based on our 36.74 per cent working interest.

Production volumes in the third quarter of 2009 were impacted by unplanned maintenance in Syncrude's vacuum distillation unit. By comparison, production during the third quarter of 2008 was impacted by a planned turnaround of Coker 8-2, which commenced in September 2008.

Year-to-date, Syncrude produced 72.1 million barrels in 2009, or 264,000 barrels per day, compared with 77.5 million barrels, or 283,000 barrels per day in 2008. On a year-to-date basis Syncrude production in 2009 was negatively affected by an extended turnaround and modifications on Coker 8-3 and related units, which began in mid-March and was completed in early June. As well, operational reliability issues, including: unplanned outages in the mining operations, coke circulation difficulties in Coker 8-1 and maintenance on the vacuum distillation unit reduced production. By comparison, production in the first three quarters of 2008 was impacted by the planned turnarounds of Coker 8-2 during the third quarter and Coker 8-1 during the second quarter, bitumen production constraints and a disruption in operations during the first quarter.

Syncrude's facilities have the design capability to produce approximately 375,000 barrels per day when operating at full capacity under optimal conditions and with no downtime for maintenance or turnarounds. Under normal operating conditions, scheduled downtime is required for maintenance and turnaround activities and unscheduled downtime will occur as a result of operational and mechanical problems, unanticipated repairs and other slowdowns. When allowances for such downtime are included, the daily design productive capacity of Syncrude's facilities is approximately 350,000 barrels per day on average and is referred to as "barrels per calendar day". All references to Syncrude's productive capacity in this report refer to barrels per calendar day, unless stated otherwise.

Operating costs decreased to $27.80 per barrel in the third quarter of 2009, down $4.35 per barrel from the same quarter of 2008. Year-to-date operating costs were $37.39 per barrel in 2009 versus $36.37 per barrel in 2008 (see the "Operating costs" section of this MD&A for further discussion).

The Trust's production volumes differ from its sales volumes due to changes in inventory, which are primarily in-transit pipeline volumes. The impact of Syncrude's 2009 operations on Canadian Oil Sands' financial results is more fully discussed later in this MD&A.

BUSINESS ENVIRONMENT

During 2009, U.S. dollar West Texas Intermediate ("WTI") oil prices have improved, averaging U.S. $68.24 per barrel in the third quarter versus U.S. $43.31 per barrel and U.S. $59.79 per barrel during the first and second quarters of 2009, respectively. Partially offsetting the oil price increase, the Canadian dollar averaged $0.91 U.S./Cdn in the third quarter versus $0.83 U.S./Cdn for the first six months of 2009. Compared to the prior year, however, commodity prices during 2009 were substantially lower than 2008 with U.S. dollar WTI prices averaging $57.32 per barrel for the first nine months of 2009 versus $113.52 per barrel in the same period of 2008.

The deterioration of economic conditions during late 2008 and early 2009 resulted in the deferral or cancellation of several development projects, including oil sands projects in the Fort McMurray region. However, recent announcements indicate that some projects may resume development, reflecting improved market conditions. While it is reasonable to expect any continued industry slowdown to contribute to lower costs over time through more competitive access to labour and materials, we have yet to experience significant production cost declines to date. A significant portion of costs in the oil sands industry are associated with labour, and these costs respond much slower to changing market conditions, particularly as industry-wide labour agreements exist that stipulate wage increases for at least another year. Syncrude continues to explore ways to reduce its cost structure, however, we cannot yet determine if a continued economic slowdown would result in any long-term reductions in Syncrude's costs. We continue to believe the most significant factor in reducing costs is better operational reliability.

During the second quarter of 2009, capital markets improved and the Trust issued U.S. $500 million of Senior Notes. Proceeds from the debt issue were used to repay $200 million of Medium Term Notes and U.S. $250 million Senior Notes that matured during 2009, and for general corporate purposes. With increasing oil prices, the substantial completion of our 2009 maintenance program, and our debt issuance, the Trust's liquidity position has improved significantly relative to the beginning of 2009 and the Trust is well positioned to execute its strategies.



SUMMARY OF QUARTERLY RESULTS
2009
($ millions, except per Trust Unit and volume
amounts) Q3 Q2 Q1
----------------------------------------------------------------------------
Revenues (1) $ 773 $ 467 $ 512

Net income (loss) $ 247 $ 46 $ 43
Per Trust Unit, Basic & Diluted $ 0.51 $ 0.10 $ 0.09

Cash from operating activities $ 213 $ (44) $ 50
Per Trust Unit (2) $ 0.44 $ (0.09) $ 0.10

Unitholder distributions $ 121 $ 73 $ 72
Per Trust Unit $ 0.25 $ 0.15 $ 0.15

Daily average sales volumes (bbls) (3) 114,544 75,553 102,825

Net realized SCO selling price ($/bbl) (4) $ 73.31 $ 67.92 $ 55.32


Operating costs ($/bbl) (5) $ 27.80 $ 50.23 $ 38.78

Purchased natural gas price ($/GJ) $ 2.90 $ 3.09 $ 4.96

West Texas Intermediate (avg. US$/bbl) (6) $ 68.24 $ 59.79 $ 43.31

Foreign exchange rates (US$/Cdn$):
Average $ 0.91 $ 0.86 $ 0.80
Quarter-end $ 0.93 $ 0.86 $ 0.79


2008 2007
Q4 Q3 Q2 Q1 Q4
----------------------------------------------------------------------------
Revenues (1) $ 704 $ 1,381 $ 1,177 $ 907 $ 950

Net income (loss) $ 124 $ 604 $ 497 $ 298 $ 515
Per Trust Unit, Basic &
Diluted $ 0.26 $ 1.25 $ 1.04 $ 0.62 $ 1.07

Cash from operating
activities $ 466 $ 921 $ 413 $ 441 $ 367
Per Trust Unit (2) $ 0.97 $ 1.91 $ 0.86 $ 0.92 $ 0.77

Unitholder distributions $ 361 $ 602 $ 481 $ 360 $ 264
Per Trust Unit $ 0.75 $ 1.25 $ 1.00 $ 0.75 $ 0.55

Daily average sales
volumes (bbls) (3) 110,197 116,656 97,744 99,181 116,368

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

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

Purchased natural gas price
($/GJ) $ 6.41 $ 7.86 $ 9.38 $ 7.30 $ 5.84

West Texas Intermediate
(avg. US$/bbl) (6) $ 59.08 $ 118.22 $ 123.80 $ 97.82 $ 90.50

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

(1) Revenues after crude oil purchases and transportation expense.
(2) Cash from operating activities per Trust Unit is a non-GAAP measure
that is derived from cash from operating activities reported on the
Trust's Consolidated Statements of Cash Flows divided by the weighted-
average number of Trust Units outstanding in the period, as used in the
Trust's net income per Unit calculations.
(3) Daily average sales volumes after crude oil purchases.
(4) Net realized SCO selling price after foreign currency hedging.
(5) Derived from operating costs, as reported on the Trust's Consolidated
Statements of Income and Comprehensive Income, divided by the sales
volumes during the period.
(6) Pricing obtained from Bloomberg.


During the last eight quarters, the following items have had a significant impact on the Trust's financial results:

- Fluctuations in U.S. dollar WTI oil prices have impacted the Trust's revenues, Crown royalties, net income and cash from operating activities;

- Planned and unplanned maintenance activities as well as turnarounds have impacted quarterly production volumes, sales revenues and operating costs;

- U.S. to Canadian dollar exchange rate fluctuations have resulted in foreign exchange gains and losses on the revaluation of U.S. dollar denominated debt and have impacted commodity pricing; and

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

Quarterly variances in revenues, net income, and cash from operating activities are caused mainly by fluctuations in crude oil prices, production and sales volumes, operating costs and natural gas prices. Net income also is impacted by unrealized foreign exchange gains and losses and by future income tax amounts. A large proportion of operating costs are fixed and, as such, per barrel operating costs are variable to production volumes. While the supply/demand balance for crude oil affects selling prices, the impact of this equation is difficult to predict and quantify and has not displayed significant seasonality. Natural gas prices are typically higher in winter months as heating demand rises, but this seasonality is influenced by weather conditions and North American natural gas inventory levels. In addition, production levels may not display seasonable patterns or trends. While maintenance and turnaround activities are typically scheduled to avoid the winter months, the exact timing of unit shutdowns cannot be precisely scheduled, and unplanned outages may occur.

Maintenance and turnaround activities impact both production volumes and operating costs. The costs associated with these activities are expensed in the period they are incurred, which can lead to significant increases in operating costs. The effect on per barrel operating costs of these maintenance activities is amplified, as the facility is generally producing at reduced rates when maintenance work is occurring.

REVIEW OF FINANCIAL RESULTS

In the third quarter of 2009, the Trust reported net income of $247 million, or $0.51 per Unit, compared with net income of $604 million, or $1.25 per Unit, recorded in the third quarter of 2008. The decrease in net income was primarily the result of lower revenues, net of lower Crown royalties and foreign exchange gains.

Net income for the first nine months of 2009 totaled $336 million, or $0.69 per Unit compared with net income of $1,399 million, or $2.91 per Unit, recorded in 2008. The decline in net income primarily reflects lower revenues, net of lower Crown royalties in 2009.

Revenues after crude oil purchases and transportation costs totaled $773 million in the third quarter of 2009 versus $1,381 million in the third quarter of 2008. On a year-to-date basis, revenues after crude oil purchases and transportation costs totaled $1,752 million in 2009 versus $3,465 million in 2008. The decrease in revenues was due to lower commodity prices and production volumes in 2009 (see "Revenues after Crude Oil Purchases and Transportation Expense" section of this MD&A for further discussion).

Cash from operating activities was $213 million for the third quarter of 2009 versus $921 million for the third quarter of 2008. Year-to-date cash from operating activities decreased to $219 million for 2009 versus $1,775 million for 2008. The decrease in cash from operating activities was due to the decrease in revenues, reflecting lower crude oil prices, lower production, and increases in non-cash working capital, partially offset by lower Crown royalties.

Non-cash working capital decreased cash from operating activities by $83 million in the third quarter of 2009, primarily as a result of higher accounts receivable, reflecting higher oil production and prices for September 2009 compared to June 2009. In the third quarter of 2008, non-cash working capital increased cash from operating activities by $164 million, primarily as a result of lower accounts receivable at September 30, 2008 relative to June 30, 2008.

In the first nine months of 2009, non-cash working capital decreased cash from operating activities by $169 million, primarily as a result of higher accounts receivable and higher inventory levels at September 30, 2009 relative to December 31, 2008. In the same period of 2008, non-cash working capital increased cash from operating activities by $28 million, primarily as a result of higher accounts payable at September 30, 2008 relative to December 31, 2007.

Non-cash working capital and changes therein can vary significantly on a period-by-period basis as a result of the timing and settlements of accounts receivable and accounts payable balances, and are impacted by a number of factors including changes in: revenue, operating expenses, Crown royalties, capital expenditures, inventory fluctuations, and the timing of payments.

Non-GAAP Financial Measures

In this MD&A we refer to financial measures that do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles ("GAAP"). These non-GAAP financial measures include cash from operating activities on a per Unit basis, net debt, total capitalization and certain per barrel measures. These non-GAAP financial measures provide additional information that we believe is meaningful regarding the Trust's operational performance, its liquidity and its capacity to fund distributions, capital expenditures and other investing activities. Users are cautioned that non-GAAP financial measures presented by the Trust may not be comparable with measures provided by other entities.



Net Income per Barrel

Three Months Ended Nine Months Ended
September 30 September 30
($ per bbl) (1) 2009 2008 Variance 2009 2008 Variance
----------------------------------------------------------------------------

Revenues after crude
oil purchases and
transportation
expense 73.31 128.66 (55.35) 65.67 120.93 (55.26)
Operating costs (27.80) (32.15) 4.35 (37.39) (36.37) (1.02)
Crown royalties (10.25) (21.50) 11.25 (5.07) (18.83) 13.76
----------------------------------------------------------------------------
35.26 75.01 (39.75) 23.21 65.73 (42.52)
----------------------------------------------------------------------------

Non-production
costs (3.19) (1.95) (1.24) (3.95) (1.87) (2.08)
Administration and
insurance (0.83) (0.44) (0.39) (0.91) (0.70) (0.21)
Interest, net (2.40) (1.52) (0.88) (2.63) (1.73) (0.90)
Depletion,
depreciation and
accretion (11.62) (11.35) (0.27) (11.60) (11.36) (0.24)
Foreign exchange
gain (loss) 8.57 (2.99) 11.56 5.18 (1.85) 7.03
Future income tax
(expense) recovery
and other (2.35) (0.52) (1.83) 3.30 0.64 2.66
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(11.82) (18.77) 6.95 (10.61) (16.87) 6.26
----------------------------------------------------------------------------
Net income per
barrel 23.44 56.24 (32.80) 12.60 48.86 (36.26)
----------------------------------------------------------------------------
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Sales volumes
(MMbbls) (2) 10.6 10.8 (0.2) 26.7 28.7 (2.0)
----------------------------------------------------------------------------
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(1) Unless otherwise specified, net income and other per barrel measures in
this MD&A have been derived by dividing the relevant revenue or cost
item by the sales volumes in the period.
(2) Sales volumes, net of purchased crude oil volumes.


Revenues after Crude Oil Purchases and Transportation Expense

Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2009 2008 Variance 2009 2008 Variance
----------------------------------------------------------------------------

Sales revenue (1) $ 808 $ 1,462 $ (654) $ 1,881 $ 3,772 $ (1,891)
Crude oil purchases (28) (73) 45 (109) (283) 174
Transportation
expense (8) (9) 1 (23) (27) 4
----------------------------------------------------------------------------
772 1,380 (608) 1,749 3,462 (1,713)

Currency hedging
gains (1) 1 1 - 3 3 -
----------------------------------------------------------------------------
$ 773 $ 1,381 $ (608) $ 1,752 $ 3,465 $ (1,713)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Sales volumes
(MMbbls) (2) 10.6 10.8 (0.2) 26.7 28.7 (2.0)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The sum of sales revenue and currency hedging gains equals Revenues on
the Trust's Consolidated Statements of Income and Comprehensive Income.
Sales revenue includes revenue from the sale of purchased crude oil and
sulphur revenue.
(2) Sales volumes, net of purchased crude oil volumes.


($ per barrel)
----------------------------------------------------------------------------
Realized SCO
selling price
before
hedging(3) $73.22 $127.46 $(54.24) $65.57 $120.09 $(54.52)
Currency hedging
gains 0.09 0.09 - 0.10 0.10 -
----------------------------------------------------------------------------
Net realized SCO
selling price $73.31 $127.55 $(54.24) $65.67 $120.19 $(54.52)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(3) SCO sales revenue after crude oil purchases and transportation expense
divided by sales volumes, net of purchased crude oil volumes.


The decrease in sales revenue on both a quarterly and a year-to-date basis for 2009 versus 2008 primarily reflects a lower realized selling price for our synthetic crude oil ("SCO") as well as slightly lower sales volumes. During the third quarter of 2009, WTI averaged U.S. $68.24 per barrel compared to U.S. $118.22 per barrel in the third quarter of 2008. The impact of the lower U.S. dollar WTI price in the third quarter of 2009 was offset somewhat by a weaker Canadian dollar, which averaged $0.91 U.S./Cdn for the third quarter of 2009 versus $0.96 U.S./Cdn for the third quarter of 2008. Year-to-date, WTI averaged U.S. $57.32 per barrel in 2009 versus U.S. $113.52 per barrel in 2008.

The Trust's SCO price is also affected by the premium or discount realized relative to Canadian dollar WTI (the "differential"). In the third quarter of 2009, the Trust realized a weighted-average SCO discount of $1.66 per barrel versus a premium of $3.78 per barrel for the same period of 2008. Year-to-date in 2009, the Trust realized a weighted-average SCO discount of $0.83 per barrel relative to the average Canadian dollar WTI price versus a premium of $3.21 per barrel in the same period of 2008. The differential is dependent upon the supply and demand for SCO and accordingly can change quickly depending upon the short-term supply and demand dynamics in the market and pipeline availability for transporting crude oil.

The Trust's sales volumes for the third quarter averaged 115,000 barrels per day and 117,000 barrels per day in 2009 and 2008, respectively. Year-to-date sales volumes averaged 98,000 barrels per day in 2009 versus an average of 105,000 barrels per day in 2008. Sales volumes for 2009 were impacted by the planned turnaround and modifications on the Coker 8-3 complex, reliability issues in mining and upgrading operations, and by constrained bitumen production during the first quarter. Sales volumes in 2008 were impacted by the disruption of several operating units in January, the scheduled turnaround of Coker 8-2 in the third quarter, the scheduled turnaround of Coker 8-1 during the first quarter and bitumen production constraints.

From time to time the Trust purchases crude oil from third parties to support the sales of internally produced SCO by fulfilling sales commitments with customers when there are shortfalls in Syncrude's production and by facilitating certain transportation arrangements and operations. The decrease in value of crude oil purchases during 2009 was primarily due to the decrease in commodity prices.



Operating Costs
Three Months Ended
September 30
2009 (1) 2008 (1)
----------------------------------------------------------------------------
$/bbl $/bbl $/bbl $/bbl
Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Bitumen production (2) $ 15.26 $ 17.61 $ 18.09 $ 20.10
Internal fuel allocation (4) 2.08 2.40 4.41 4.90
----------------------------------------------------------------------------
Total produced bitumen costs 17.34 20.01 22.50 25.00

Upgrading costs (3) 9.77 11.87
Less: Internal fuel allocation to
bitumen (4) (2.40) (4.90)
Bitumen purchases 0.28 -
----------------------------------------------------------------------------
Total Syncrude operating costs 27.66 31.97
Canadian Oil Sands' adjustments (5) 0.14 0.18
----------------------------------------------------------------------------

Total operating costs 27.80 32.15
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(thousands of barrels per day) Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Syncrude production volumes (6) 360 312 351 316
----------------------------------------------------------------------------

Nine Months Ended
September 30
2009 (1) 2008 (1)
----------------------------------------------------------------------------
$/bbl $/bbl $/bbl $/bbl
Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Bitumen production (2) $ 20.46 $ 24.30 $ 19.46 $ 22.59
Internal fuel allocation (4) 2.31 2.74 4.22 4.89
----------------------------------------------------------------------------
Total produced bitumen costs 22.77 27.04 23.68 27.48

Upgrading costs (3) 13.20 12.33
Less: Internal fuel allocation to
bitumen (4) (2.74) (4.89)
Bitumen purchases 0.45 1.41
----------------------------------------------------------------------------
Total Syncrude operating costs 37.95 36.33
Canadian Oil Sands' adjustments (5) (0.56) 0.04
----------------------------------------------------------------------------

Total operating costs 37.39 36.37
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(thousands of barrels per day) Bitumen SCO Bitumen SCO
----------------------------------------------------------------------------
Syncrude production volumes (6) 314 264 328 283
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Information shown above allocates costs to bitumen production and
upgrading based on deductibility for bitumen royalty purposes. In order
for time to fully develop an allocation methodology for common costs,
the Syncrude Royalty Amending Agreement provides for allowed bitumen
costs to be 64.5 per cent of Syncrude total operating costs until
December 31, 2010. Prior year information has been reclassified to
conform to the new format.
(2) Bitumen production costs relate to the removal of overburden, oil sands
mining, bitumen extraction, tailings dyke construction and disposal
costs and purchased energy. The costs are expressed on a per barrel of
bitumen production basis and converted to a per barrel of SCO based on
the effective yield of SCO from the processing and upgrading of bitumen.
(3) Upgrading costs include the production, ongoing maintenance, and
purchased energy costs associated with processing and upgrading of
bitumen to SCO. They also include the costs of major upgrading equipment
turnarounds and catalyst replacement, all of which are expensed as
incurred.
(4) Estimate of internal fuel produced in upgrading operations and consumed
in bitumen production. Allocation is based on the Syncrude Royalty
Amending Agreement.
(5) Canadian Oil Sands' adjustments mainly pertain to asset retirement
costs, Syncrude-related pension costs, as well as the inventory impact
of moving from production to sales as Syncrude reports per barrel costs
based on production volumes and the Trust reports based on sales
volumes.
(6) Syncrude SCO production volumes include the impact of processed
purchased bitumen volumes. Bitumen production volumes exclude the impact
of purchased bitumen.


Three Months Ended Nine Months Ended
September 30 September 30
($/bbl of SCO) 2009 2008 2009 2008
----------------------------------------------------------------------------

Production costs 25.28 25.64 33.43 28.72
Purchased energy 2.52 6.51 3.96 7.65
----------------------------------------------------------------------------
Total operating costs 27.80 32.15 37.39 36.37
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(GJs/bbl of SCO)
----------------------------------------------------------------------------
Purchased energy consumption 0.87 0.83 1.03 0.94
----------------------------------------------------------------------------


In the third quarter of 2009, operating costs were $293 million, averaging $27.80 per barrel, a decrease of $52 million from third quarter 2008 operating costs of $345 million. Year-to-date operating costs were $997 million in 2009, averaging $37.39 per barrel, a decrease of $45 million from 2008 amounts.

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

- Lower energy costs as a result of a decline in natural gas prices to $3.84 per gigajoule ("GJ") in the first nine months of 2009 compared with $7.30 per GJ in the same period of 2008; and

- A decrease in the value of bitumen purchased by Syncrude to $33 million in 2009 ($12 million net to the Trust) compared with $110 million during the same period of 2008 ($40 million net to the Trust).

These cost reductions were partially offset by:

- Additional maintenance activities at Syncrude on mining, upgrading, utilities and extraction facilities in 2009 relative to 2008;

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

- Increased costs for contractors and wages for Syncrude staff; and

- An increase in the value of Syncrude's long-term incentive plans in 2009 versus 2008. A portion of Syncrude's long-term incentive plans is based on the market return performance of several Syncrude owners' shares and units, the market performance of which was stronger in the third quarter of 2009 relative to 2008.

Operating costs in 2009 and 2008 were also impacted by turnarounds on Syncrude's cokers. In 2009 Syncrude performed significant maintenance on Coker 8-3, which began in mid-March and was completed in mid-June. In 2008 Syncrude performed turnarounds on Coker 8-1 during the first quarter and Coker 8-2 during the third quarter. On a year-to-date basis the cost of the single 2009 turnaround was similar to the 2008 turnarounds as a result of the larger 2009 scope.

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

Non-Production Costs

Non-production costs totaled $34 million and $21 million in the third quarters of 2009 and 2008, respectively. Year-to-date non-production costs totaled $106 million for 2009 and $54 million for 2008. The increase in non-production costs over 2008 was due to additional development activities undertaken with respect to future mine train relocations, initiatives to manage tailings ponds, ESP fire repairs and planning for growth initiatives.

Non-production costs consist primarily of development expenditures relating to capital programs, such as: pre-feasibility engineering, technical and support services, research and development, and regulatory and stakeholder consultation expenditures. Non-production costs can vary on a periodic basis depending on the number of projects underway and the status of the projects.

Crown Royalties

Pursuant to an agreement reached with the Alberta government (the "Amended Royalty Agreement"), Syncrude's Crown royalties after 2008 are based on deemed bitumen revenues and allowed bitumen operating, non-production and capital costs.

In the third quarter of 2009, Crown royalties decreased to $108 million, or $10.25 per barrel, from $231 million, or $21.50 per barrel, in the comparable 2008 quarter. Year-to-date Crown royalties decreased to $135 million, or $5.07 per barrel, in 2009 from $540 million, or $18.83 per barrel in 2008. The decrease in Crown royalties was primarily due to lower revenues and higher operating and capital costs. For 2009 Syncrude is subject to royalties based on a net 25 per cent bitumen royalty rate. Syncrude also has recorded an additional $22 million, net to the Trust, of royalties in respect of upgrader growth capital recapture under its Amended Royalty Agreement.



Interest Expense, Net
Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Interest expense on long-term debt $ 25 $ 18 $ 71 $ 56
Interest income and other - (2) (1) (7)
----------------------------------------------------------------------------
Interest expense, net $ 25 $ 16 $ 70 $ 49
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The increase in interest expense on long-term debt was mainly due to the refinancing of 2009 debt maturities with the U.S. $500 million 7.75 per cent Senior Notes issue in the second quarter of 2009.



Depreciation, Depletion and Accretion Expense

Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Depreciation and depletion expense $ 119 $ 118 $ 299 $ 315
Accretion expense 4 3 11 10
----------------------------------------------------------------------------
$ 123 $ 121 $ 310 $ 325
----------------------------------------------------------------------------


The change in depreciation and depletion ("D&D") expense was due to lower production volumes offset by a slight increase in the per barrel D&D rate for 2009. The D&D rate per barrel of production increased to $11.27 in 2009 from $11.07 in 2008.



Foreign Exchange (Gain) Loss

Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Foreign exchange (gain) loss-long term
debt $(120) $ 36 $(172) $ 62
Foreign exchange (gain) loss-other 30 (4) 34 (9)
----------------------------------------------------------------------------
Total foreign exchange (gain) loss $ (90) $ 32 $(138) $ 53
----------------------------------------------------------------------------


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 FX gains on long term debt in 2009 were due to a strengthening in the value of the Canadian dollar relative to the U.S. dollar to $0.93 U.S./Cdn at September 30, 2009 from $0.86 U.S./Cdn at June 30, 2009 and $0.82 U.S./ Cdn at December 31, 2008. The FX gains and losses in 2008 were due to the weakening of the Canadian dollar relative to the U.S. dollar to $0.94 U.S./Cdn at September 30, 2008 from $0.98 U.S./Cdn at June 30, 2008 and $1.01 U.S./Cdn at December 31, 2007.

In addition to the foreign exchange gain on long-term debt, Canadian Oil Sands also reported a foreign exchange loss of $30 million on other items during the third quarter of 2009. This loss was primarily due to a foreign exchange loss of $19 million on U.S. cash received by Canadian Oil Sands on its financing in May 2009 that was held to retire the U.S. $250 million debt in August 2009.

Future Income Tax and Other

In the third quarter of 2009, a future income tax expense of $25 million was recorded versus a future income tax expense of $6 million in the same period of 2008. On a year-to-date basis, a future income tax recovery of $88 million was recorded in 2009 versus a future income tax recovery of $18 million in 2008. In addition to the future income taxes recorded on changes in temporary differences between accounting and tax values of Canadian Oil Sands' assets and liabilities, a future income tax recovery of $63 million was recorded during the first quarter of 2009 on the substantive enactment of tax rate reductions.

CAPITAL EXPENDITURES

Canadian Oil Sands' expansion-related capital expenditures have declined in recent years and capital costs for 2009 and 2008 were mainly related to sustaining capital. We define expansion capital expenditures as costs incurred to grow the productive capacity of the operation while sustaining capital is effectively all other capital. Capital expenditures may fluctuate considerably year-to-year due to the timing of expansions, equipment replacement and other factors. The productive capacity of Syncrude's operations was previously described in the "Review of Syncrude Operations" section of this MD&A.

In the third quarter of 2009, capital expenditures totaled $85 million compared with expenditures of $94 million in the same quarter of 2008. The Syncrude Emissions Reduction ("SER") project accounted for $31 million and $18 million of the capital spent in the third quarters of 2009 and 2008, respectively, with the remaining third quarter expenditures related to other sustaining capital activities, including the purchase of trucks and shovels, construction of tailings facilities, and other infrastructure projects.

Year-to-date capital expenditures totaled $308 million in 2009 versus $195 million in 2008. The SER project accounted for $87 million and $56 million of the capital spent in 2009 and 2008, respectively. The remaining expenditures related to other sustaining capital activities, including the purchase of trucks and shovels, modifications to Coker 8-3 and related units, construction of tailings facilities, and other infrastructure projects. Sustaining capital expenditures on a per barrel basis were $11.67 and $6.78 on a year-to-date basis in 2009 and 2008, respectively. Sustaining capital on a per barrel basis is also affected by the Trust's sales volumes, which were lower in 2009 relative to 2008.

Syncrude is undertaking the SER project to retrofit technology into the operation of Syncrude's original two cokers by the end of 2011 in order to reduce total sulphur dioxide and other emissions. The estimate of the total cost of the SER project remains at $1.6 billion ($590 million net to the Trust) and the Trust's share of SER expenditures to date is approximately $269 million.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

Contractual obligations are summarized in the Trust's 2008 annual MD&A, and include future cash payments that the Trust is required to make under existing contractual arrangements that it has entered into directly or as a 36.74 per cent owner in Syncrude.

During the first nine months of 2009, Syncrude entered into new natural gas purchase commitments that expire between 2009 and 2011. The value of this commitment will fluctuate with changes to natural gas prices. Based on an estimated AECO price of $6.00/GJ, the remaining commitment to the Trust for these contracts at September 30, 2009 is approximately $144 million.

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

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

During the third quarter of 2009, the Trust increased its estimated asset retirement obligation as a result of revisions to cost estimates, the expected timing of reclamation expenditures, and revised material movement assumptions to reflect mine plan changes. The estimated present value of the obligation increased to $386 million at September 30, 2009 ($235 million at December 31, 2008), while the estimated undiscounted cash flows associated with the obligation have increased to $906 million at September 30, 2009 ($774 million at December 31, 2008).

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



UNITHOLDER DISTRIBUTIONS
Three Months Ended Nine Months Ended
September 30 September 30
----------------------------------------------------------------------------
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash from operating activities $ 213 $ 921 $ 219 $ 1,775

Net income $ 247 $ 604 $ 336 $ 1,399

Unitholder distributions $ 121 $ 602 $ 266 $ 1,443
----------------------------------------------------------------------------

Excess (shortfall) of cash from
operating activities over Unitholder
distributions $ 92 $ 319 $ (47) $ 332

Excess (shortfall) of net income over
Unitholder distributions $ 126 $ 2 $ 70 $ (44)
----------------------------------------------------------------------------


In the first nine months of 2009, Unitholder distributions exceeded cash from operating activities by $47 million. As a result, opening cash balances, equity issued by the Trust's Premium Distribution, Distribution Re-Investment and Optional Unit Purchase Plan ("DRIP"), and the U.S. $500 million second quarter Senior Note issue funded the Trust's capital expenditures, debt repayments, reclamation trust fund contributions, and distributions.

The Trust may use debt and equity financing in addition to cash from operating activities and existing cash balances to fund capital expenditures, reclamation trust contributions, debt repayments, acquisitions, distributions and working capital changes from financing and investing activities.

In early 2009, Canadian Oil Sands reinstated its DRIP to help preserve balance sheet equity during a time of lower crude oil prices, higher maintenance activities, and tight credit markets. Effective July 25, 2009, we suspended the DRIP as a result of strengthening crude oil prices, the U.S. $500 million Senior Notes issue, and stabilized capital markets. For the first and second quarters of 2009, participation in the DRIP was about 46 per cent and 41 per cent, respectively, and a total of 2.9 million Units were issued in 2009.

In establishing its distribution levels, the Trust considers its outlook for crude oil prices and Syncrude's operational performance, the Trust's obligations, and access to capital markets. We also consider funding for other operating obligations that are included in cash from operating activities. These obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to $54 million and $38 million on a year-to-date basis in 2009 and 2008, respectively.

The Senior Note issue in the second quarter of 2009 significantly improved the Trust's liquidity position and its balance sheet remains strong. In addition, crude oil prices have improved during 2009 and Syncrude has substantially completed its 2009 planned maintenance program. These factors, and the resulting estimated production and revenue, provided the basis for distribution levels in excess of cash from operating activities in the first nine months of 2009, as well as the fourth quarter distribution increase.

On October 28, 2009 the Trust declared a quarterly distribution of $0.35 per Unit in respect of the fourth quarter of 2009 for a total distribution of $170 million. The distribution will be paid on November 30, 2009 to Unitholders of record on November 20, 2009. Quarterly distributions are approved by our Board of Directors after considering the current and expected economic conditions, ensuring financing capacity for Canadian Oil Sands' capital requirements and with the objective of maintaining an investment grade credit rating.

Cash from operating activities and net income can fluctuate from period to period due to Syncrude's operating performance, WTI pricing, SCO differentials to WTI, FX rates and other factors. The Trust strives to reduce the impact of these fluctuations on distributions by taking a longer-term view of the operating and business environment, our net debt level relative to our target, and our capital expenditure and other commitments. In that regard, the Trust may distribute more or less in a period than is generated in cash from operating activities or net income. The variable nature of cash from operating activities introduces risk in the ability to sustain or provide stability in distributions. Expectations regarding the stability or sustainability of distributions are unwarranted. Further, the taxation of income trusts commencing January 1, 2011 will alter future cash from operating activities and distribution levels.



LIQUIDITY AND CAPITAL RESOURCES

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

Long-term debt 1,191 1,258
Cash and cash equivalents (74) (279)
----------------------------------------------------------------------------
Net debt (1) $ 1,117 $ 979
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholders' equity $ 4,043 $ 3,910
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total capitalization (2) $ 5,160 $ 4,889
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

(1) Non-GAAP measure

(2) Net debt plus Unitholders' equity


During the second quarter of 2009, the Trust issued U.S. $500 million of Senior Notes. The notes have an annual interest rate of 7.75 per cent payable semi-annually and mature May 15, 2019. Proceeds from the notes were used to repay $200 million of Medium Term Notes that matured during the second quarter of 2009, U.S. $250 million of Senior Notes that matured during the third quarter of 2009, and for general corporate purposes. The next debt maturity occurs in 2013.

Net debt has increased to $1.1 billion from $1.0 billion at December 31, 2008. This increase reflects investing activities and distributions in excess of cash from operating activities, partially offset by approximately $170 million in foreign exchange gains on our U.S. dollar denominated debt.

During the first quarter of 2009, the Trust's $67 million line of credit was increased to $70 million and the term on the Trust's $40 million bilateral credit facility was extended to April 22, 2010.

With the refinancing of the 2009 debt maturities, the Trust's liquidity position has significantly improved. While we believe a slightly higher leverage level may provide a more efficient capital structure and conserve tax pools prior to trust taxation, the Trust must also consider a prudent liquidity position, access to capital markets, and future investing and financing requirements. Currently, we have a net debt target of approximately $1.6 billion by the end of 2010, compared to current net debt of $1.1 billion as at September 30, 2009. Achievement of the net debt target will depend on actual operating results, economic conditions, future investing activities, foreign exchange rates and distribution payments based on these expectations. As a result, actual net debt levels may vary from the net debt target and the net debt target may also change if a more conservative balance sheet is deemed prudent.

UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY


The Trust's Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $15 billion with 484 million Units outstanding and a closing price of $30.75 per Unit on September 30, 2009.



Canadian Oil Sands Trust - Trading Activity

Third
Quarter September August July
2009 2009 2009 2009
----------------------------------------------------------------------------

Unit price
High $ 30.87 $ 30.87 $ 29.82 $ 27.87
Low $ 24.45 $ 26.50 $ 26.53 $ 24.45
Close $ 30.75 $ 30.75 $ 27.50 $ 27.12

Volume of Trust units traded
(millions) 83.0 26.9 25.2 30.9
Weighted average Trust units
outstanding (millions) 484.4 484.4 484.4 484.4
----------------------------------------------------------------------------


FOREIGN OWNERSHIP

Based on information from the statutory declarations by Unitholders, we estimate that, as of August 17, 2009 approximately 72 per cent of our Units were held by Canadian residents with the remaining 28 per cent of Units being held by non-Canadian residents. Canadian Oil Sands' Trust Indenture provides that not more than 49 per cent of its Units can be held by non-Canadian residents.

The Trust regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of November 20, 2009. The Trust posts its foreign ownership levels on its web site at www.cos-trust.com under "Investor/Unit Information". The steps to manage foreign ownership levels are described in the Trust's AIF.

CORPORATE CONVERSION

In 2009, legislation for the conversion of income and royalty trusts into corporations was enacted. This legislation is designed to permit income and royalty trusts to convert into public corporations without triggering adverse Canadian tax consequences to the trusts or their unitholders. A number of income and royalty trusts in Canada have either converted or announced their intention to convert to a corporate structure.

Canadian Oil Sands is planning for conversion to a corporate structure on or about December 31, 2010. As part of its conversion to a corporate structure, Canadian Oil Sands is reviewing its distribution/dividend strategies. Based on current conditions, Canadian Oil Sands expects to pay dividends on a similar basis as its current approach to distributions. Accordingly, future dividends are expected to vary depending on Syncrude's operational performance, Canadian Oil Sands' operating and investing obligations, crude oil prices and access to capital markets.

FINANCIAL RISK MANAGEMENT

The Trust did not have any financial derivatives outstanding at September 30, 2009.

Crude Oil Price Risk

Canadian Oil Sands' revenues are impacted by changes in both the U.S. dollar denominated crude oil prices and U.S./Cdn FX rates. The Trust did not have any crude oil price hedges in place during 2009 and 2008, and we do not currently intend to enter into any crude oil hedge positions. The Trust may hedge this exposure in the future, however, depending on the business environment and our growth opportunities.

Foreign Currency Hedging

Canadian Oil Sands' results are affected by fluctuations in the U.S./Cdn currency exchange rates, as revenues generated are based on a U.S. dollar WTI benchmark price while certain obligations are denominated in Canadian dollars. The Trust did not have any foreign currency hedges in place during 2009 or 2008, and we do not currently intend to enter into any new currency hedge positions. The Trust may, however, hedge foreign currency exchange rates in the future, depending on the business environment and growth opportunities.

Interest Rate Risk

Canadian Oil Sands' net income and cash from operating activities are impacted by interest rate changes based on the amount of floating rate debt outstanding or upon the refinancing of maturing long-term debt at prevailing interest rates. As at September 30, 2009 there was no floating interest rate debt outstanding.

Liquidity Risk

Liquidity risk is the risk that Canadian Oil Sands will not be able to meet its financial obligations as they fall due. Canadian Oil Sands actively manages its liquidity risk through its cash, debt and equity strategies. As a result of the U.S. $500 million 7.75 per cent Senior Note issue in the second quarter of 2009, the Trust's liquidity position has improved significantly.

Credit Risk

Canadian Oil Sands is exposed to credit risk primarily through customer accounts receivable balances and financial counterparties with whom the Trust has invested its cash or purchased term deposits from. The maximum exposure to any one customer or financial counterparty is controlled through a credit policy that limits exposure based on credit ratings.

The financial condition of some of our U.S. based refinery customers has come under pressure recently, reflecting low refinery margins during the economic downturn. Canadian Oil Sands carries credit insurance to help mitigate the impact should a loss occur and continues to transact primarily with investment grade customers, with the vast majority of accounts receivable at September 30, 2009 being due from investment grade energy producers and refinery based customers.

At September 30, 2009, our cash and cash equivalents were held in either cash or term deposits with high-quality senior Canadian banks. As of October 28, 2009, there are no financial assets that are past their maturity or impaired due to credit risk-related defaults.

CHANGES IN ACCOUNTING POLICIES

Goodwill and Intangible Assets

In February 2008, the Canadian Institute of Chartered Accountants ("CICA") issued a new accounting standard, Section 3064 - Goodwill and Intangible Assets, which replaces Section 3062 - Goodwill and Other Intangible Assets, and Section 3450 - Research and Development costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. The section is effective for the Trust beginning January 1, 2009. Application of the new section did not have a material impact on the Trust's financial statements.

NEW ACCOUNTING PRONOUNCEMENTS

There were no new accounting pronouncements by the CICA during 2009 that are expected to have a material impact on the Trust.

The Trust is continuing with its conversion to international financial reporting standards ("IFRS"), which will replace Canadian GAAP starting in 2011. Assessments of the impacts of conversion to IFRS, including the adoption of potential IFRS standards under development that might impact the Trust, have not been finalized. In addition to existing IFRS standards, new or revised IFRS standards are being developed by the International Accounting Standards Board ("IASB") and may impact the Trust on adoption. These standards include Joint Ventures, Income Taxes, Financial Instruments, Emissions Trading Schemes, and Extractive Industries. Pursuant to earlier IASB work plans, a number of these standards were expected to be finalized prior to 2011. Recent IASB information suggests the development of certain standards has been delayed or postponed by the IASB. As part of its implementation, the Trust continues to monitor the developments within IFRS which might impact its conversion. The final impacts to the Trust's consolidated financial statements upon the adoption of IFRS will depend on IFRS standards existing in 2011, as well as the accounting policy choices made by Canadian Oil Sands.



2009 OUTLOOK

(millions of Canadian dollars, except volume
and per barrel amounts) October 28, 2009 July 27, 2009
----------------------------------------------------------------------------

Syncrude production (MMbbls) 104 104
Canadian Oil Sands Sales (MMbbls) 38.2 38.2
Revenues, net of crude oil purchases
and transportation 2,606 2,360
Operating costs 1,322 1,338
Operating costs per barrel 34.61 35.01
Crown royalties 219 100
Capital expenditures 455 460
Cash from operating activities 593 519

Business environment assumptions
---------------------------------
West Texas Intermediate (US$/bbl) $ 62 $ 55
Premium (Discount) to average C$ WTI
prices (C$/bbl) $ (1.15) $ (1.50)
Foreign exchange rate (US$/Cdn$) $ 0.90 $ 0.87
AECO natural gas (Cdn$/GJ) $ 4.25 $ 4.50


On October 28, 2009, the Trust revised its 2009 outlook. The 2009 single point production estimate for Syncrude remains 104 million barrels with a narrower 101 to 105 million barrel range.

The 104 million barrel estimate incorporates actual production volumes for the first nine months of 2009 and reliable operations for the remainder of the year. With the planned 2009 maintenance program substantially complete, the Trust expects production volumes and per barrel operating costs in the second half of 2009 to improve relative to the first half of the year. To achieve the outlook production, we are estimating that Syncrude will average approximately 350,000 barrels per day in the last quarter of 2009, which can be achieved in the absence of significant unplanned outages.

The outlook has been revised to reflect results to date as well as current commodity price and foreign exchange rate estimates. For 2009, we are assuming a weighted average WTI crude oil price of U.S. $62 per barrel, an $0.895 U.S./Cdn weighted average foreign exchange rate, and a weighted average $1.15 per barrel SCO discount to Cdn dollar WTI, resulting in estimated revenues of $2,606 million, or $68 per barrel for the year.



October 28, 2009 (2) July 27, 2009 (3)
Cdn $ Per US$ Per Cdn $ Per US$ Per
2009 Cost Estimates (1) Bbl Bbl Bbl Bbl
----------------------------------------------------------------------------
Syncrude Costs
Operating expenses $ 34.61 $ 30.98 $ 35.01 $ 30.46
Non-production costs $ 3.87 $ 3.46 $ 3.60 $ 3.13
-----------------------------------------
$ 38.48 $ 34.44 $ 38.61 $ 33.59
Capital expenditures $ 11.91 $ 10.66 $ 12.05 $ 10.48
-----------------------------------------
Total Syncrude costs $ 50.39 $ 45.10 $ 50.66 $ 44.07
-----------------------------------------

Canadian Oil Sands Costs
Interest $ 2.41 $ 2.16 $ 2.43 $ 2.11
Administration, Insurance and
Other $ 1.57 $ 1.41 $ 1.36 $ 1.18
-----------------------------------------
Total Canadian Oil Sands Costs $ 3.98 $ 3.57 $ 3.79 $ 3.29
-----------------------------------------

Total Syncrude and Canadian Oil
Sands Costs $ 54.37 $ 48.67 $ 54.45 $ 47.36

Crown Royalties $ 5.72 $ 5.12 $ 2.63 $ 2.29
-----------------------------------------
Total Costs $ 60.09 $ 53.79 $ 57.08 $ 49.65
-----------------------------------------
-----------------------------------------

(1) This table updates the cost estimate outlook section provided in the
Trust's 2008 annual MD&A.
(2) The October 28, 2009 per barrel cost estimates are based on 104 million
barrels of Syncrude production and an $0.895 U.S./Cdn exchange rate.
(3) The July 27, 2009 per barrel cost estimates are based on 104 million
barrels of Syncrude production and an $0.87 U.S./Cdn exchange rate.


Revised annual operating costs are estimated at $1,322 million, or about $34.60 per barrel, consisting of $30.30 per barrel of production costs and $4.30 per barrel of purchased energy costs. When combined with non-production costs and capital expenditures, total Syncrude costs per our 2009 outlook are estimated at $50 per barrel. Crown royalty estimates have risen to $219 million, or $5.70 per barrel, mainly reflecting the higher revenue assumptions.

Based on the above assumptions, our 2009 outlook cash from operating activities is $593 million, or $1.23 per Unit. After deducting forecast 2009 capital expenditures of $455 million, we are estimating $138 million of remaining cash from operating activities, or $0.29 per Unit.

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

Changes in certain factors and market conditions could potentially impact Canadian Oil Sands' outlook. The following table provides a sensitivity analysis of the key factors affecting the Trust's performance. In addition to the factors described in the table, the supply/demand equation and pipeline access for synthetic crude oil in North American markets could impact the differential for SCO relative to crude benchmarks; however, these factors are difficult to predict.



2009 Outlook Sensitivity Analysis (October 28, 2009)

Cash from Operating
Activities Increase
Annual
Variable (1) Sensitivity $ millions $/Trust unit
----------------------------------------------------------------------------

Syncrude operating costs decrease C$1.00/bbl 32 0.07
Syncrude operating costs decrease C$50 million 15 0.03
WTI crude oil price increase US$1.00/bbl 31 0.06
Syncrude production increase 2 million bbls 37 0.08
Canadian dollar weakening US$0.01/C$ 21 0.04
AECO natural gas price decrease C$0.50/GJ 16 0.03

(1) An opposite change in each of these variables will result in the
opposite cash from operating activities impacts.
Canadian Oil Sands may become subject to minimum Crown royalties at a
rate of one per cent of gross bitumen revenue. The sensitivities
presented herein assume royalties are paid at 25 per cent of net bitumen
revenue.


2010 BUDGET

On October 28, 2009, Canadian Oil Sands released its budget for 2010. Canadian Oil Sands is budgeting Syncrude production of 115 million barrels (42.3 million barrels net to the Trust) with a 110 to 120 million barrel production range. The 115 million barrel production estimate incorporates a scheduled turnaround of Coker 8-1 in the second half of 2010 and an allowance for unplanned maintenance work.

Canadian Oil Sands' operating costs are estimated at $1,479 million, or $35 per barrel, with capital expenditures of $541 million mainly related to sustaining the Syncrude operation.

The budget incorporates an estimated U.S. $70 per barrel WTI price, a $0.95 U.S./Cdn foreign exchange rate, and a $3 per barrel SCO discount to Cdn dollar WTI, resulting in estimated revenues of $2,986 million, or $71 per barrel in 2010.

Based on the above assumptions, our budgeted 2010 cash from operating activities is $969 million or $2 per Unit. After deducting budgeted 2010 capital expenditures of $541 million, we are estimating $428 million of remaining cash from operating activities, or $0.88 per Unit.



CANADIAN OIL SANDS TRUST
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
($ millions, except per Unit
amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------

Revenues $ 809 $ 1,463 $ 1,884 $ 3,775
----------------------------------------------------------------------------

Expenses:
Operating 293 345 997 1,042
Non-production 34 21 106 54
Crude oil purchases and
transportation expense 36 82 132 310
Crown royalties 108 231 135 540
Administration 6 3 18 16
Insurance 2 2 6 5
Interest, net (Note 8) 25 16 70 49
Depreciation, depletion and
accretion 123 121 310 325
Foreign exchange loss (gain) (90) 32 (138) 53
----------------------------------------------------------------------------
537 853 1,636 2,394
----------------------------------------------------------------------------
Earnings before taxes 272 610 248 1,381
Future income tax expense
(recovery) and other (Note 9) 25 6 (88) (18)
----------------------------------------------------------------------------
Net income 247 604 336 1,399
Other comprehensive loss, net of
income taxes
Reclassification of derivative
gains to net income (1) (1) (2) (2)
----------------------------------------------------------------------------
Comprehensive income $ 246 $ 603 $ 334 $ 1,397
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

Net income per Trust Unit:
Basic & Diluted $ 0.51 $ 1.25 $ 0.69 $ 2.91


See Notes to Unaudited Consolidated Financial Statements



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


Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------
Retained earnings
Balance, beginning of period $ 1,306 $ 1,597 $ 1,362 $ 1,643
Net income 247 604 336 1,399
Unitholder distributions (Note 11) (121) (602) (266) (1,443)
----------------------------------------------------------------------------
Balance, end of period 1,432 1,599 1,432 1,599
----------------------------------------------------------------------------
Accumulated other comprehensive
income
Balance, beginning of period 20 23 21 24
Other comprehensive loss (1) (1) (2) (2)
----------------------------------------------------------------------------
Balance, end of period 19 22 19 22
----------------------------------------------------------------------------
Unitholders' capital
Balance, beginning of period 2,587 2,524 2,524 2,500
Issuance of Trust Units (Note 4) - - 63 24
----------------------------------------------------------------------------
Balance, end of period 2,587 2,524 2,587 2,524
----------------------------------------------------------------------------
Contributed surplus
Balance, beginning of period 4 3 3 5
Exercise of employee stock options - - - (3)
Stock-based compensation 1 - 2 1
----------------------------------------------------------------------------
Balance, end of period 5 3 5 3
----------------------------------------------------------------------------
Total Unitholders' equity $ 4,043 $ 4,148 $ 4,043 $ 4,148
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements

CANADIAN OIL SANDS TRUST

CONSOLIDATED BALANCE SHEETS
AS AT
(unaudited)

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

ASSETS
Current assets:
Cash and cash equivalents $ 74 $ 279
Accounts receivable 325 184
Inventories 123 93
Prepaid expenses 7 5
----------------------------------------------------------------------------
529 561

Property, plant and equipment, net 6,443 6,277
Goodwill 52 52
Reclamation trust 46 43
----------------------------------------------------------------------------

$ 7,070 $ 6,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 291 $ 284
Current portion of employee future benefits 17 17
----------------------------------------------------------------------------
308 301

Employee future benefits and other liabilities 102 99
Long-term debt (Note 7) 1,191 1,258
Asset retirement obligation (Note 12) 386 235
Future income taxes 1,040 1,130
----------------------------------------------------------------------------
3,027 3,023

Unitholders' equity 4,043 3,910
----------------------------------------------------------------------------

$ 7,070 $ 6,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See Notes to Unaudited Consolidated Financial Statements


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


Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Cash from (used in) operating
activities
Net income $ 247 $ 604 $ 336 $ 1,399
Items not requiring outlay of cash:
Depreciation, depletion and accretion 123 121 310 325
Foreign exchange loss (gain) on
long-term debt (120) 36 (172) 62
Future income tax expense (recovery) 25 6 (88) (18)
Net change in deferred items and other 21 (10) 2 (21)
----------------------------------------------------------------------------
296 757 388 1,747
Change in non-cash working capital (83) 164 (169) 28
----------------------------------------------------------------------------
Cash from (used in) operating
activities 213 921 219 1,775
----------------------------------------------------------------------------

Cash from (used in) financing
activities
Issuance of Senior Notes (Note 7) - - 574 -
Repayment of medium term and Senior
Notes (Note 7) (271) - (471) (150)
Net drawdown (repayment) of bank
credit facilities - - - (16)
Unitholder distributions (Note 11) (121) (602) (203) (1,443)
Issuance of Trust Units (Note 4) - - - 21
----------------------------------------------------------------------------
Cash from (used) in financing
activities (392) (602) (100) (1,588)
----------------------------------------------------------------------------

Cash from (used in) investing
activities
Capital expenditures (85) (94) (308) (195)
Reclamation trust funding (1) (1) (3) (4)
Change in non-cash working capital (8) 22 6 22
----------------------------------------------------------------------------
Cash used in investing activities (94) (73) (305) (177)
----------------------------------------------------------------------------

Foreign exchange loss on Cash and Cash
equivalents held in foreign currency (19) - (19) -
----------------------------------------------------------------------------

Increase (decrease) in cash and cash
equivalents (292) 246 (205) 10

Cash and cash equivalents at beginning
of period 366 32 279 268
----------------------------------------------------------------------------

Cash and cash equivalents at end of
period $ 74 $ 278 $ 74 $ 278
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Cash and cash equivalents consist of:
Cash $ 27 $ 10
Short-term investments 47 268
----------------------------------------------------------------------------
$ 74 $ 278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information (Note 14)


See Notes to Unaudited Consolidated Financial Statements


NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2009

(Tabular amounts expressed in millions of Canadian dollars, except where otherwise noted.)

1) BASIS OF PRESENTATION

The interim consolidated financial statements include the accounts of Canadian Oil Sands Trust and its subsidiaries (collectively, the "Trust" or "Canadian Oil Sands"), and are presented in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2008, except as discussed in Note 2. Certain disclosures that are normally required to be included in the notes to the annual audited consolidated financial statements have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in the Trust's annual report for the year ended December 31, 2008.

2) CHANGES IN ACCOUNTING POLICIES

In 2009 the Trust adopted the requirements of the Canadian Institute of Chartered Accountants ("CICA") - Section 3064 Goodwill and Intangible Assets, which replaced Section 3062 Goodwill and Other Intangible Assets, and Section 3450 Research and Development Costs. The new section establishes standards for the recognition, measurement and disclosure of goodwill and intangible assets. Application of the new section did not have a material impact on the Trust's financial statements.

3) FUTURE CHANGES IN ACCOUNTING POLICIES

The Trust will be subject to International Financial Reporting Standards ("IFRS") commencing in 2011. The Trust is currently assessing the impact conversion to IFRS may have on its financial statements.

4) ISSUANCE OF TRUST UNITS

In the nine months ended September 30, 2009, approximately 2.9 million Trust Units were issued pursuant to the Trust's Premium Distribution, Distribution Re-investment and Optional Unit Purchase Plan ("DRIP") for $63 million.

In the nine months ended September 30, 2008, approximately 2.1 million Trust Units were issued for $24 million on the exercise of employee stock options.

5) EMPLOYEE FUTURE BENEFITS

Syncrude Canada Ltd. ("Syncrude Canada"), the operator of the Syncrude Joint Venture, has a defined benefit and two defined contribution plans providing pension benefits, and other post-employment benefit plans ("OPEB") covering most of its employees. Other post-employment benefits include certain health care and life insurance benefits for retirees, their beneficiaries and covered dependents. The OPEB plan is not funded.

Canadian Oil Sands accrues its obligations as a joint venture owner in respect of Syncrude Canada's employee benefit plans and the related costs, net of plan assets. The cost of employee pension and other retirement benefits is actuarially determined using the projected benefit method based on length of service and reflects Canadian Oil Sands' best estimate of the expected performance of the plan investment, salary escalation factors, retirement ages of employees and future health care costs. The expected return on plan assets is based on the fair value of those assets. Past service costs from plan amendments are amortized on a straight-line basis over the estimated average remaining service life of active employees ("EARSL") at the date of amendment. The excess of any net actuarial gain or loss exceeding 10 per cent of the greater of the benefit obligation and fair value of the plan assets is amortized over the EARSL.

Canadian Oil Sands' share of Syncrude Canada's net defined benefit and contribution plans expense for the three and nine months ended September 30, 2009 and 2008 is based on its 36.74 per cent working interest. The costs have been recorded in operating expense as follows:



Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Defined benefit plans:
Pension benefits $ 11 $ 8 $ 28 $ 23
Other benefit plans - 1 3 3
----------------------------------------------------------------------------
$ 11 $ 9 $ 31 $ 26

Defined contribution plans 1 1 2 2
----------------------------------------------------------------------------
Total benefit cost $ 12 $ 10 $ 33 $ 28
----------------------------------------------------------------------------

6) BANK CREDIT FACILITIES

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


Each of the Trust's credit facilities is unsecured. These credit agreements contain covenants restricting Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business. In addition, Canadian Oil Sands has agreed to maintain its total debt-to-total book capitalization at an amount less than 60 per cent, or 65 per cent in certain circumstances involving acquisitions.

a) The $40 million extendible revolving term facility is a 364-day facility with a one-year term out, expiring April 22, 2010. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at September 30, 2009, no amounts were drawn on this facility ($Nil - December 31, 2008).

b) The $70 million line of credit is a one-year revolving letter of credit facility. Letters of credit drawn on the facility mature April 30(th) each year and are automatically renewed, unless notification to cancel is provided by Canadian Oil Sands or the financial institution providing the facility at least 60 days prior to expiry. Letters of credit on this facility bear interest at a credit spread.

Letters of credit of approximately $70 million were written against the line of credit as at September 30, 2009.

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

7) LONG-TERM DEBT

On August 10, 2009 the Trust repaid U.S. $250 million of 4.8 per cent Senior Notes.

On June 29, 2009 the Trust repaid $200 million of 5.55 per cent Medium Term Notes.

On May 11, 2009, the Trust issued U.S. $500 million of 7.75 per cent Senior Notes, maturing May 15, 2019. Interest is payable on the notes semi-annually on May 15 and November 15.



8) INTEREST, NET

Three Months Ended Nine Months Ended
September 30 September 30
($ millions) 2009 2008 2009 2008
----------------------------------------------------------------------------

Interest expense on long-term debt $ 25 $ 18 $ 71 $ 56
Interest income and other - (2) (1) (7)
----------------------------------------------------------------------------
Interest expense, net $ 25 $ 16 $ 70 $ 49
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9) FUTURE INCOME TAXES

During the first quarter of 2009, an additional $63 million future income tax recovery was recorded on the substantive enactment of legislation to reduce the tax rates applicable to the Trust in 2011.

10) STOCK BASED COMPENSATION

During 2009, 485,292 options were issued by the Trust to employees with an average exercise price of $19.74 pursuant to the Trust's Unit Incentive Option Plan. The options have an estimated weighted-average fair value of $4.53 per option.

11) UNITHOLDER DISTRIBUTIONS

Pursuant to Section 5.1 of the Trust Indenture, the Trust is required to distribute all the Distributable Income, as defined by the Trust Indenture, received or receivable by the Trust in a quarter. The Trust's Distributable Income primarily consists of a royalty from its operating subsidiary, Canadian Oil Sands Limited ("COSL"). The royalty is designed to capture the cash generated by COSL, after the deduction of all costs and expenses including operating and administrative costs, income taxes, capital expenditures, debt interest and principal repayments, working capital and reserves for future obligations deemed appropriate. The amount of royalty income that the Trust receives in any period has a considerable amount of flexibility through the use of discretionary reserves and debt borrowings or repayments (either intercompany or third party). Quarterly distributions are determined by COSL's Board of Directors after considering the current and expected economic and operating conditions, ensuring financing capacity for Syncrude's expansion projects and/or Canadian Oil Sands acquisitions, and with the objective of maintaining an investment grade credit rating.



Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash from operating activities $ 213 $ 921 $ 219 $ 1,775
Add (Deduct):
Capital expenditures (85) (94) (308) (195)
Change in non-cash working
capital (1) (8) 22 6 22
Reclamation trust funding (1) (1) (3) (4)
Change in cash and cash
equivalents and financing, net (2) 2 (246) 352 (155)
----------------------------------------------------------------------------
Unitholder distributions $ 121 $ 602 $ 266 $ 1,443
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Unitholder distributions per Trust
Unit $ 0.25 $ 1.25 $ 0.55 $ 3.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) From investing activities.

(2) Primarily represents the change in cash and cash equivalents and net
financing to fund the Trust's share of investing activities.


Unitholder distributions during the first nine months of 2009 were funded by cash payments of $203 million and by the issuance of 2.9 million Trust Units for $63 million.

12) ASSET RETIREMENT OBLIGATION AND RECLAMATION TRUST

Canadian Oil Sands and each of the other Syncrude owners are liable for their share of ongoing environmental obligations related to the ultimate reclamation of the Syncrude properties on abandonment. The Trust estimates reclamation expenditures will be made over approximately the next 60 years and has applied an average credit-adjusted risk-free discount rate of six per cent (2008-six per cent) in deriving the asset retirement obligation.

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the Trust's share of the obligation associated with the retirement the Syncrude properties.



As at September 30, As at December 31,
2009 2008
----------------------------------------------------------------------------

Asset retirement obligation,
beginning of year $ 235 $ 226
Liabilities settled (22) (14)
Accretion expense 11 14
Change in estimated future cash
flows 162 9
----------------------------------------------------------------------------
Asset retirement obligation, end of
period $ 386 $ 235
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The total undiscounted estimated cash flows required to settle the Trust's share of Syncrude's obligation was $906 million at September 30, 2009 (December 31, 2008 - $774 million).

The reclamation expenditures will be funded from Canadian Oil Sands' cash from operating activities and reclamation trust. In addition to annual funding for reclamation expenditures, Canadian Oil Sands deposits $0.1322 per barrel of production attributable to its Working Interest to a reclamation trust established for the purpose of funding the operating subsidiary's share of environmental and reclamation obligations. As at September 30, 2009, including interest earned on investments, the balance of the reclamation trust was $46 million (December 31, 2008 - $43 million).

The Trust has posted letters of credit with the Province of Alberta in the amount of $70 million (December 31, 2008 - $67 million) to secure its pro rata share of the reclamation obligations of the Syncrude participants.

13) COMMITMENTS

During the first nine months of 2009, Syncrude entered into new natural gas purchase commitments that expire between 2009 and 2011. The value of this commitment will fluctuate with changes to natural gas prices. Based on an estimated AECO price of $6.00/GJ, the remaining commitment to the Trust for these contracts at September 30, 2009 is approximately $144 million.

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

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



14) SUPPLEMENTARY INFORMATION

Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
----------------------------------------------------------------------------

Income tax paid $ - $ - - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Interest paid $ 27 $ 18 68 $ 56
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Canadian Oil Sands Limited

Marcel Coutu, President & Chief Executive Officer

Units Listed - Symbol: COS.UN
Toronto Stock Exchange


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


Contact Information