Canadian Oil Sands Trust announces third quarter 2008 results and a reduction in the quarterly distribution to $0.75 per Trust unit



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

    TSX - COS.UN
    

    CALGARY, Oct. 29 /CNW/ - Canadian Oil Sands Trust ("Canadian Oil Sands",
the "Trust" or "we") today announced that third quarter 2008 cash from
operating activities nearly doubled over the same period last year, increasing
to $921 million ($1.91 per Trust unit ("Unit")) compared with $484 million
($1.01 per Unit) recorded in the 2007 third quarter. Year-to-date, cash from
operating activities was up 76 per cent to $1.8 billion ($3.69 per Unit)
compared with the same period of 2007. The increase in cash from operating
activities on both a quarter and year-to-date basis reflects a higher realized
selling price for our synthetic crude oil partially offset by lower sales
volumes and higher operating and Crown royalties expenses.
    Net income for the third quarter 2008 was $604 million ($1.25 per Unit)
compared with a net income of $361 million ($0.75 per Unit) for the 2007
period. Year-to-date, net income totaled $1.4 billion ($2.91 per Unit) in 2008
compared with net income of $228 million ($0.48 per Unit) for 2007. The
improvement in net income was primarily the result of higher revenues net of
higher operating costs and Crown royalties in 2008. As well, in the second
quarter of 2007 the Trust recorded a one time future income tax expense of
$701 million for the substantive enactment of trust taxation legislation,
reducing net income in 2007.
    Despite very strong financial results for the third quarter of 2008,
Canadian Oil Sands declared a 40 per cent reduction in the quarterly
distribution amount to $0.75 per Unit for Unitholders of record on November
14, 2008, payable on November 28, 2008, in response to current market
conditions. Canadian Oil Sands takes a long-term view of distributions that
considers, among other criteria, current and expected economic and operating
conditions. While our Syncrude operation is sound and strong, as a result of
the deterioration in economic conditions, in particular the significant
decline in crude oil prices and the heightened risk in the credit markets, we
deem it prudent to reduce the distribution in order to maintain our strong
balance sheet.
    Expanding on the impact of the current market condition on the Trust,
Marcel Coutu, President and Chief Executive Officer of Canadian Oil Sands,
said: "I would like to provide our Unitholders with Canadian Oil Sands'
perspective on the financial turmoil that continues to restrict access to
capital markets and create significant volatility in equity valuations. The
fundamentals of Canadian Oil Sands and our Syncrude project remain among the
very best in our industry, from both a long-life mining resource perspective
and an ever-improving operational record in producing sweet, synthetic crude
oil.
    "As Syncrude's Stage 3 expansion neared completion, we began redirecting
cash flow to our Unitholders through quarterly distributions, which have risen
from $0.20 per Unit in February 2006 to $1.25 per Unit in August 2008. The
increase in distributions has been a reflection of rising crude oil prices,
growing production, and reduced capital spending. The distributions also
reflect the execution of our financing plan following the legislation of trust
taxation post 2010. In this context, we have communicated to you our plan of
distributing discretionary cash flow and allowing net debt to increase to
about $1.6 billion by the end of 2010."
    "In addition to stable operations, our ability to execute this finance
strategy hinges on two key factors: oil prices and competitive access to
capital markets. Clearly, both of these factors have shifted dramatically in
recent weeks. The price of WTI crude oil has quickly declined from
approximately US$120 per barrel when the last distribution was established to
approximately US$60 to US$70 per barrel during October 2008. As well, the
turmoil in the financial markets has reduced the availability of new debt and
substantially increased interest costs."
    "Having assessed these new market conditions, Canadian Oil Sands has
decided to reduce the quarterly distribution amount to $0.75 per Unit to
protect and maintain a strong liquidity position and financial flexibility
during this market turmoil. Our $1.6 billion net debt target by the end of
2010 remains unchanged, but we must now consider more carefully the
refinancing of approximately $500 million of 2009 debt maturities in addition
to the incremental leverage to meet our objective. Until debt capital markets
are available to execute this strategy on an efficient basis, Canadian Oil
Sands will prudently preserve its liquidity by managing the rate at which its
leverage rises. Should bank facilities or debt markets not be available to
fund our mid-2009 debt maturities, further distribution reductions may be
required in order to fund maturities out of cash from operating activities.
With the significant cash flow we continue to generate at current oil prices
and the $840 million of undrawn credit facilities, we are strongly positioned
until the financial turmoil subsides."
    "The important message is that the fundamentals of Canadian Oil Sands and
Syncrude's oil production business remain very robust. Our current marginal
operating cost is about $35 per barrel and our sustaining maintenance capital
requirements are about $10 per barrel. In the meantime we will continue to
assess market conditions to prudently execute our strategy. Despite near-term
expectations of reduced global demand, our view of future crude oil prices
remains constructive, based primarily on supply-side constraints. We continue
to be unhedged in the sale of our crude oil production, and our objective of
maintaining a strong balance sheet is serving us well in this regard."
    Sales volumes in 2008 were seven per cent lower quarter-over-quarter and
six per cent lower year-to-date compared with 2007, averaging about
116,700 barrels per day and 105,000 barrels per day during the third quarter
and year-to-date, respectively, in 2008. Sales volumes in the third quarter of
2008 were reduced by a scheduled coker turnaround. The re-start of the coker
has been delayed until the first week of November to enable repairs to an
associated gas compressor. The delay is not expected to affect projected
production volumes for 2008 of 106 million barrels, gross to Syncrude, because
bitumen froth volumes will go into tankage, which can be processed in November
and December. A scheduled turnaround of another coker was also successfully
completed in the second quarter, and together with a disruption in operations
during the first quarter resulted in lower volumes for the first nine months
of 2008 compared with the same period of 2007. In 2007, unplanned maintenance
occurred on two cokers as well as planned maintenance on other units however,
this work was completed by the end of the second quarter, resulting in near
design capacity production for the third quarter of 2007.
    Operating costs in the third quarter of 2008 were $32.15 per barrel, or
$11.31 per barrel higher than the comparative 2007 quarter. Year-to-date in
2008, operating costs were $36.37 per barrel, or $11.89 per barrel more than
the same period of 2007. In addition to reduced production volumes in 2008
compared with 2007, inflationary cost pressures and operational inefficiencies
in 2008 contributed to the rise in operating costs. More information on
operating costs is provided in the Management's Discussion and Analysis
("MD&A") section of this report.
    In the third quarter of 2008, Syncrude's total recordable injury rate was
0.57 for every 200,000 hours worked compared to a rate of 0.40 recorded for
the same period of 2007.

    Syncrude releases 2007 Sustainability Report

    In September 2008, Syncrude released its 2007 Sustainability Report,
which provides a comprehensive discussion about Syncrude's social, economic
and environmental performance. The report is available at www.syncrude.ca.

    
    CANADIAN OIL SANDS TRUST
    Highlights



    (millions of Canadian            Three Months Ended    Nine Months Ended
     dollars, except Trust              September 30          September 30
     unit and volume amounts)         2008       2007       2008       2007
    -------------------------------------------------------------------------
    Net Income                    $     604  $     361  $   1,399  $     228
      Per Trust unit- Basic       $    1.25  $    0.75  $    2.91  $    0.48
      Per Trust unit- Diluted     $    1.25  $    0.75  $    2.91  $    0.48

    Cash from Operating
     Activities                   $     921  $     484  $   1,775  $   1,010
      Per Trust unit              $    1.91  $    1.01  $    3.69  $    2.11

    Unitholder Distributions      $     602  $     192  $   1,443  $     527
      Per Trust unit              $    1.25      $0.40  $    3.00  $    1.10

    Sales Volumes(1)
      Total (MMbbls)                   10.8       11.5       28.7       30.3
      Daily average (bbls)          116,656    124,904    104,571    110,927

    Operating Costs per barrel    $   32.15  $   20.84  $   36.37  $   24.48

    Net Realized SCO Selling
     Price per barrel             $  127.55  $   81.48  $  120.19  $   75.94

    West Texas Intermediate
     (average $US per barrel)(2)  $  118.22  $   75.15  $  113.52  $   66.22
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) The Trust's sales volumes differ from its production volumes due to
        changes in inventory, which are primarily in-transit pipeline
        volumes, and are net of purchased crude oil volumes.
    (2) Pricing obtained from Bloomberg.
    


    2008 Outlook

    The Trust is maintaining its estimate for 2008 Syncrude production of 106
million barrels with a range of 103 to 109 million barrels (net to the Trust,
equivalent to 39 million barrels with a range of 38 to 40 million barrels). We
have reduced our estimate for average WTI prices in 2008 to US$102.00 per
barrel, which reflects actual prices for the first nine months of 2008 and an
assumption of US$66.98 per barrel for the fourth quarter. Combined with an
anticipated reduction in Crown royalties payable in 2008 and an operating cost
assumption largely unchanged at $35.47 per barrel, the estimate for cash from
operating activities has declined to $4.58 per Unit. With the decrease in the
distribution to $0.75 per Unit announced this quarter, we are estimating net
debt levels of approximately $1.1 billion at the end of 2008.

    More information on the Trust's Outlook is provided in the MD&A section
of this report and the October 29, 2008 guidance document, which is available
on the Trust's web site at www.cos-trust.com under "investor information".
    All statements regarding 2008 year-end numbers or future events are
qualified by the forward-looking advisory contained in the MD&A.


    MANAGEMENT'S DISCUSSION AND ANALYSIS

    The following Management's Discussion and Analysis ("MD&A") was prepared
as of October 29, 2008 and should be read in conjunction with the unaudited
interim consolidated financial statements of Canadian Oil Sands Trust
("Canadian Oil Sands" or the "Trust") for the nine months ended September 30,
2008 and September 30, 2007, and the audited consolidated financial statements
and MD&A of the Trust for the year ended December 31, 2007 and the Trust's
Annual Information Form ("AIF") dated March 15, 2008. 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 sustainability of
operations at certain levels of WTI prices; future distributions and any
increase or decrease from current payment amounts; the belief that
inflationary pressures will continue; the belief that operational reliability
will improve over time and with that improvement that operating costs will be
reduced; the expected level of sustaining capital for the next few years and
longer term; the expectations regarding bitumen purchases; the expected net
debt level at the end of 2008; the expected impact on the Trust and
distributions and the expected structure to be assumed given the Federal
government's tax changes effective in 2011; plans regarding refinancing of the
2009 debt maturities and views on future credit markets and availability of
financing and the impact on distributions; expectations regarding future
distribution levels; the cost estimate for the SER project and the expectation
that the SER project will significantly reduce total sulphur dioxide and other
emissions; the completion date for the SER project; the expected impact on the
Trust from announced changes by the Alberta government regarding its royalty
regime; any expectations regarding the enforceability of legal rights; 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; improvements in
operational reliability; the belief that the Trust will not be restricted by
its net debt to total capitalization financial covenant; the expectation that
no crude oil hedges will be entered into in the future; the expected realized
selling price, which includes the anticipated differential to WTI, to be
received in 2008 for Canadian Oil Sands' product; the potential amount payable
in respect of any future income tax liability; the plans regarding future
expansions of the Syncrude project and in particular all plans regarding Stage
4 development; the level of energy consumption in 2008 and beyond; capital
expenditures for 2008; the level of natural gas consumption in 2008 and
beyond; the expected price for crude oil and natural gas in 2008; the expected
production, revenues and operating costs for 2008; 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, 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; 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 2008, crude oil production from the Syncrude
Joint Venture ("Syncrude") totalled 29.1 million barrels, or about
316,000 barrels per day, compared with 32.1 million barrels, or about
348,000 barrels per day, during the same period of 2007. Net to the Trust,
production totalled 10.7 million barrels in the third quarter of 2008 compared
with 11.8 million barrels in 2007, based on our 36.74 per cent working
interest.
    Production in the third quarter of 2008 was primarily impacted by a
scheduled turnaround on Coker 8-2, which began in September. The restart of
the coker, originally anticipated for late October, has been delayed until the
first week of November to enable repairs to an associated gas compressor. The
delay is not expected to affect projected production volumes for 2008 of 106
million barrels, gross to Syncrude, because bitumen froth volumes will go into
tankage, which can be processed in November and December.  During the third
quarter of 2007, production was relatively stable and was not significantly
affected by maintenance activities.
    Year-to-date, Syncrude produced 77.5 million barrels in 2008, or about
283,000 barrels per day, compared with 82.6 million barrels, or about
302,000 barrels per day in 2007. In addition to the coker turnarounds during
the second and third quarters, production in the first nine months of 2008 was
impacted by a disruption in operations that was compounded by extremely cold
weather during the first quarter. The cold weather during the first quarter of
2008 also affected bitumen production and extraction. By comparison,
production in the first nine months of 2007 was impacted by unplanned
maintenance on Coker 8-3 and Coker 8-2, and planned maintenance on other
units.
    Operating costs increased to $32.15 per barrel in the third quarter of
2008, up $11.31 per barrel from the same quarter last year. Year-to-date
operating costs were $36.37 per barrel in 2008 versus $24.48 per barrel in
2007 (see the "Operating costs" section of this MD&A for further discussion).
    Syncrude's facilities have the design capability to produce approximately
375,000 barrels per day when operating at full capacity under optimal
conditions and with no downtime for maintenance or turnarounds. Under normal
operating conditions, scheduled downtime is required for maintenance and
turnaround activities and unscheduled downtime will occur as a result of
operational and mechanical problems, unanticipated repairs and other
slowdowns. When allowances for such downtime are included, the daily design
productive capacity of Syncrude's facilities is approximately 350,000 barrels
per day on average and is referred to as "barrels per calendar day". All
references to Syncrude's productive capacity in this report refer to barrels
per calendar day, unless stated otherwise.
    The Trust's production volumes differ from its sales volumes due to
changes in inventory, which are primarily in-transit pipeline volumes that
vary with current production. The impact of Syncrude's 2008 operations on
Canadian Oil Sands' financial results is more fully discussed later in this
MD&A.

    
    SUMMARY OF QUARTERLY RESULTS

    ($ millions, except per
     Trust Unit and volume                       2008                  2007
     amounts)                          Q3         Q2         Q1         Q4
    -------------------------------------------------------------------------
    Revenues(1)                   $   1,381  $   1,177  $     907  $     950

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

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

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

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

    Net realized SCO selling
     price ($/bbl)(3)             $  127.55  $  131.32  $  100.41  $   88.73

    Operating costs ($/bbl)(4)    $   32.15  $   41.92  $   35.93  $   27.38

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

    West Texas Intermediate
     (avg. US$/bbl)(5)            $  118.22  $  123.80  $   97.82  $   90.50

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


    ($ millions, except per
     Trust Unit and volume                       2007                  2006
     amounts)                          Q3         Q2         Q1         Q4
    -------------------------------------------------------------------------
    Revenues(1)                   $     936  $     690  $     674  $     646

    Net income (loss)             $     361  $    (395) $     262  $     128
      Per Trust Unit, Basic       $    0.75  $   (0.82) $    0.55  $    0.27
      Per Trust Unit, Diluted     $    0.75  $   (0.82) $    0.54  $    0.27

    Cash from operating
     activities                   $     484  $     324  $     202  $     412
      Per Trust Unit(2)           $    1.01  $    0.68  $    0.42  $    0.88

    Unitholder distributions      $     192  $     191  $     144  $     140
      Per Trust Unit              $    0.40  $    0.40  $    0.30  $    0.30

    Daily average sales volumes
     (bbls)                         124,904     98,720    108,981    110,185

    Net realized SCO selling
     price ($/bbl)(3)             $   81.48  $   76.81  $   68.69  $   63.71

    Operating costs ($/bbl)(4)    $   20.84  $   30.13  $   23.56  $   23.60

    Purchased natural gas price
     ($/GJ)                       $    4.99  $    6.78  $    6.99  $    6.51

    West Texas Intermediate
     (avg. US$/bbl)(5)            $   75.15  $   65.02  $   58.23  $   60.16

    Foreign exchange rates
     (US$/Cdn$):
      Average                     $    0.96  $    0.91  $    0.85  $    0.88
      Quarter - end               $    1.00  $    0.94  $    0.87  $    0.86

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

    (4) 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.

    (5) Pricing obtained from Bloomberg.
    -------------------------------------------------------------------------

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

    -   U.S. dollar West Texas Intermediate ("WTI") oil prices, which impact
        the Trust's revenues, increased significantly in the 2008 periods
        relative to the 2007 and 2006 time periods.

    -   The substantive enactment of income tax legislation in June 2007 to
        apply a new tax on distributions from Canadian public trusts starting
        in 2011 resulted in an additional future income tax expense of
        $701 million in the second quarter of 2007. Other corporate tax rate
        reductions substantively enacted in the fourth and second quarters of
        2007 resulted in future income tax recoveries of $153 million and
        $38 million in each quarter, respectively.

    -   On January 2, 2007 the Trust acquired a 1.25 per cent working
        interest in Syncrude from Talisman Energy Inc. Commencing in 2007,
        the Trust's financial results reflect a 36.74 per cent working
        interest in Syncrude while the 2006 financial results reflect the
        Trust's previous ownership of 35.49 per cent.

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

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

    REVIEW OF FINANCIAL RESULTS

    In the third quarter of 2008, net income amounted to $604 million, or
$1.25 per Trust unit ("Unit"), compared with net income of $361 million, or
$0.75 per Unit, recorded in the comparable quarter in 2007, primarily as a
result of higher revenues net of higher operating costs and Crown royalties.
    Year-to-date net income totaled $1.4 billion, or $2.91 per Unit in 2008
compared with net income of $228 million, or $0.48 per Unit, recorded in 2007.
The improvement in net income was primarily the result of higher revenues net
of higher operating costs and Crown royalties in 2008 without the impact of
the one-time future income tax expense of $701 million that was recorded in
the second quarter of 2007.
    Cash from operating activities increased to $921 million for the third
quarter of 2008 versus $484 million for the third quarter of 2007.
Year-to-date cash from operating activities increased to $1.8 billion for 2008
versus $1.0 billion for 2007. The increase in cash from operating activities
was the result of the higher revenues net of increases in operating expenses,
Crown royalties and changes in non-cash working capital.
    Changes in non-cash working capital increased cash from operating
activities by $164 million in the third quarter of 2008, primarily as a result
of lower accounts receivable at September 30, 2008 versus June 30, 2008. The
decline in accounts receivable was the result of lower sales volumes and oil
prices in September 2008 versus June 2008. In the third quarter of 2007,
changes in non-cash working capital increased cash from operating activities
by $14 million, primarily as a result of higher accounts receivable net of
higher accounts payable at September 30, 2007 relative to June 30, 2007.
    Year-to-date changes in non-cash working capital increased cash from
operating activities by $28 million in 2008, primarily as a result of higher
accounts payable at September 30, 2008 relative to December 31, 2007. In the
same period of 2007, changes in non-cash working capital decreased cash from
operating activities by $23 million, primarily as a result of higher accounts
receivable offset by higher accounts payable at September 30, 2007 relative to
December 31, 2007.
    Non-cash working capital and changes therein can vary on a
period-by-period basis as a result of the timing and settlements of accounts
receivable and accounts payable balances, and are impacted by a number of
factors including changes in revenue, operating expenses, Crown royalties, the
timing of capital expenditures, and inventory fluctuations.

    
    Net Income per Barrel

                             Three Months Ended         Nine Months Ended
                                September 30               September 30
    ($ per bbl)(1)        2008     2007  Variance    2008     2007  Variance
    -------------------------------------------------------------------------
    Revenues after crude
     oil purchases and
     transportation
     expense             128.66    81.48    47.18   120.93    75.94    44.99
    Operating costs      (32.15)  (20.84)  (11.31)  (36.37)  (24.48)  (11.89)
    Crown royalties      (21.50)  (14.32)   (7.18)  (18.83)  (11.49)   (7.34)
    -------------------------------------------------------------------------
                          75.01    46.32    28.69    65.73    39.97    25.76
    -------------------------------------------------------------------------

    Non-production costs  (1.95)   (1.40)   (0.55)   (1.87)   (1.62)   (0.25)
    Administration
     and insurance        (0.44)   (0.54)    0.10    (0.70)   (0.67)   (0.03)
    Interest, net         (1.52)   (1.83)    0.31    (1.73)   (2.24)    0.51
    Depletion,
     depreciation and
     accretion           (11.35)   (8.76)   (2.59)  (11.36)   (8.60)   (2.76)
    Foreign exchange
     gain (loss)          (2.99)    3.59    (6.58)   (1.85)    3.69    (5.54)
    Future income tax
     (expense) recovery
     and other            (0.52)   (5.94)    5.42     0.64   (23.01)   23.65
    -------------------------------------------------------------------------
                         (18.77)  (14.88)   (3.89)  (16.87)  (32.45)   15.58
    -------------------------------------------------------------------------
    Net income per
     barrel               56.24    31.44    24.80    48.86     7.52    41.34
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Sales volumes
     (MMbbls)              10.8     11.5     (0.7)    28.7     30.3     (1.6)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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.
    


    Non-GAAP Financial Measures

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

    
    Revenues after Crude Oil Purchases and Transportation Expense

                             Three Months Ended         Nine Months Ended
                                September 30               September 30
    ($ millions)          2008     2007  Variance    2008     2007  Variance
    -------------------------------------------------------------------------
    Sales revenue(1)    $ 1,462  $ 1,033  $   429  $ 3,772  $ 2,618  $ 1,154
    Crude oil purchases     (73)     (91)      18     (283)    (299)      16
    Transportation
     expense                 (9)      (8)      (1)     (27)     (27)       -
    -------------------------------------------------------------------------
                          1,380      934      446    3,462    2,292    1,170

    Currency hedging
     gains(1)                 1        2       (1)       3        8       (5)
    -------------------------------------------------------------------------
                        $ 1,381  $   936  $   445  $ 3,465  $ 2,300  $ 1,165
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Sales volumes
     (MMbbls)(2)           10.8     11.5     (0.7)    28.7     30.3     (1.6)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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)  $127.46  $ 81.23  $ 46.23  $120.09  $ 75.66  $ 44.43
    Currency hedging
     gains                 0.09     0.25    (0.16)    0.10     0.28    (0.18)
    -------------------------------------------------------------------------
    Net realized SCO
     selling price      $127.55  $ 81.48  $ 46.07  $120.19  $ 75.94  $ 44.25
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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


    The increase in sales revenue for 2008 versus 2007 on a quarterly and on
a year-to-date basis was due to a higher realized selling price for our
synthetic crude oil ("SCO") offset by a decline in sales volumes.
    The increase in the SCO selling price primarily reflects the increase in
WTI prices in 2008. During the third quarter of 2008, WTI prices averaged
US$118.22 per barrel compared to US$75.15 per barrel for the third quarter of
2007. Year-to-date, WTI prices averaged US$113.52 per barrel in 2008 versus
US$66.22 per barrel in 2007. This increase in US dollar WTI prices on a
year-to-date basis was tempered, however, by a stronger Canadian dollar, which
averaged $0.98 US/Cdn in 2008 compared with $0.90 US/Cdn in 2007. On a
quarterly basis, the Canadian dollar averaged $0.96 US/Cdn for both 2008 and
2007.
    In addition to the increase in WTI prices, our SCO continued to receive a
premium to Canadian dollar WTI (the "differential") in 2008. In the third
quarter of 2008, the Trust's SCO realized a weighted-average premium of
$3.78 per barrel compared with the average Canadian dollar WTI price versus a
premium of $2.60 per barrel in the same period in 2007. Year-to-date in 2008,
the Trust's SCO realized a weighted-average premium of $3.21 per barrel
relative to the average Canadian dollar WTI price versus a premium of
$2.40 per barrel for 2007.
    The Trust's sales volumes for the third quarter of 2008 averaged about
116,700 barrels per day versus an average of about 124,900 barrels per day in
the third quarter of 2007.
    Year-to-date sales volumes averaged about 104,600 barrels per day in 2008
versus an average of about 110,900 barrels per day for 2007. Sales volumes for
2008 were impacted by the scheduled turnarounds of Cokers 8-2 and 8-1 and by
operational difficulties during the first quarter. Sales volumes in 2007 were
impacted by maintenance on Coker 8-3, Coker 8-2 and other units.

    
    Operating Costs

                              Three Months Ended          Nine Months Ended
                                 September 30                September 30
                              2008          2007          2008          2007
    -------------------------------------------------------------------------
                      $/bbl  $/bbl  $/bbl  $/bbl  $/bbl  $/bbl  $/bbl  $/bbl
                     Bitumen  SCO  Bitumen  SCO  Bitumen  SCO  Bitumen  SCO
    -------------------------------------------------------------------------

    Bitumen Costs(1)
      Bitumen
       production(2)  15.23          9.71         15.39         10.14
      Purchased
     energy(2),(4)     2.41          1.23          2.97          2.13
      Purchased
       bitumen            -             -          1.22             -
    -------------------------------------------------------------------------
                      17.64  19.60  10.94  12.31  19.58  23.08  12.27  14.49
    -------------------------------------------------------------------------
    Upgrading Costs(3)
      Bitumen
       processing and
       upgrading(2)           5.85          3.83          5.85          4.58
      Turnaround and
       catalysts              2.06          0.25          2.07          1.26
      Purchased
       energy(4)              3.83          2.34          4.15          2.48
    -------------------------------------------------------------------------
                             11.74          6.42         12.07          8.32
    -------------------------------------------------------------------------
    Other and
     research(2)             (0.18)         0.87          1.29          1.05
    Change in treated
     and untreated
     inventory                0.81          0.63         (0.10)         0.10
    -------------------------------------------------------------------------
     Total Syncrude
      operating
      costs                  31.97         20.23         36.34         23.96
    Canadian Oil
     Sands
     adjustments(5)           0.18          0.61          0.03          0.52
    -------------------------------------------------------------------------
    Total operating
     costs                   32.15         20.84         36.37         24.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (thousands of
     barrels per
     day)            Bitumen  SCO  Bitumen  SCO  Bitumen  SCO  Bitumen  SCO
    -------------------------------------------------------------------------
    Syncrude
     production
    volumes(6)          351    316    392    348    333    283    357    302
    -------------------------------------------------------------------------

    (1) Bitumen costs relate to the removal of overburden, oil sands mining,
        bitumen extraction and tailings dyke construction and disposal costs.
        The costs are expressed on a per barrel of bitumen production basis
        and converted to a per barrel of SCO based on the effective yield of
        SCO from the processing and upgrading of bitumen.
    (2) Prior year information has been restated for comparative purposes to
        conform to a revised presentation of costs.
    (3) Upgrading costs include the production and ongoing maintenance costs
        associated with processing and upgrading of bitumen to SCO. It also
        includes the costs of major upgrading equipment turnarounds and
        catalyst replacement, all of which are expensed as incurred.
    (4) Natural gas prices averaged $7.86/GJ and $4.99/GJ in the third
        quarter of 2008 and 2007, respectively. For the first nine months of
        the year, natural gas costs averaged $8.13/GJ and $6.25/GJ in 2008
        and 2007, respectively.
    (5) Canadian Oil Sands' adjustments mainly pertain to 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 production volumes include the impact of processed purchased
        bitumen volumes.


                                    Three Months Ended     Nine Months Ended
                                        September 30          September 30
    ($/bbl of SCO)                    2008       2007       2008       2007
    -------------------------------------------------------------------------

    Production costs                  25.64      17.12      28.72      19.48
    Purchased energy                   6.51       3.72       7.65       5.00
    -------------------------------------------------------------------------
      Total operating costs           32.15      20.84      36.37      24.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (GJs/bbl of SCO)
    -------------------------------------------------------------------------
    Purchased energy consumption       0.83       0.75       0.94       0.80
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    In the third quarter of 2008, operating costs were $345 million,
averaging $32.15 per barrel, an increase of $106 million, or $11.31 per
barrel, over the third quarter of 2007 operating costs of $239 million.
Year-to-date operating costs were approximately $1.0 billion in 2008,
averaging $36.37 per barrel, an increase of $301 million, or $11.89 per barrel
over 2007. The change in costs for the reported periods is primarily due to
the following:

    
    -   additional overburden material was moved during the first three
        quarters of 2008 versus 2007. Syncrude also increased its use of
        contracted equipment and operators to supplement its own material
        movement activities in 2008 in order to increase exposed mineable ore
        inventory and meet operational requirements;

    -   increased costs for contractors and wages for Syncrude staff on a
        quarterly and on a year-to-date basis as a result of inflationary
        pressures and contract settlements;

    -   higher energy costs reflecting higher natural gas prices and
        increased purchased energy consumption on per barrel basis due to
        operational inefficiencies during 2008;

    -   the purchase of incremental bitumen during the first half of 2008 to
        support production during times of internal bitumen supply
        shortfalls;

    -   inflationary pressure for materials and consumables;

    -   additional costs during the first quarter of 2008 associated with
        resuming shipments at Syncrude following the disruption of operations
        early in the year;

    -   turnaround costs were incurred in the third quarter of 2008 while
        there were no associated turnaround costs during the third quarter of
        2007; and

    -   changes in the value of Syncrude's long term incentive plan in 2008
        versus 2007. 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 weaker in the
        third quarter of 2008 relative to the same period in 2007. There was
        no significant change in year-to-date costs for Syncrude's long term
        incentive plans in 2008 versus 2007.
    

    Operating costs per barrel also have increased in 2008 as a result of
reduced production volumes in 2008 versus 2007 on a quarterly and year-to-date
basis. A significant portion of Syncrude's operating costs are fixed and as
such, any change in production impacts per unit operating costs. While
inflationary pressures are expected to persist, improvements in operational
reliability should help to reduce the costs related to the operational
inefficiencies experienced during 2008.

    Non-Production Costs

    Non-production costs totalled $21 million and $16 million in the third
quarters of 2008 and 2007, respectively. Year-to-date non-production costs
totalled $54 million for 2008 and $49 million for 2007. Non-production costs
consist primarily of development expenditures relating to capital programs,
which are expensed, such as: commissioning costs, pre-feasibility engineering,
technical and support services, research and development, and regulatory and
stakeholder consultation expenditures. Non-production costs can vary on a
periodic basis depending on the number of projects underway and the status of
the projects.

    Crown Royalties

    In the third quarter of 2008, Crown royalties increased to $231 million,
or $21.50 per barrel, from $165 million, or $14.32 per barrel, in the
comparable 2007 quarter. Year-to-date Crown royalties increased to
$540 million, or $18.83 per barrel, in 2008 from $348 million, or $11.49 per
barrel in 2007. The increase in royalties in 2008 on both a quarterly and a
year-to-date basis was primarily due to significantly increased revenues
partially offset by higher operating costs and higher capital expenditures.
    In 2007, the Alberta government announced new Crown royalty terms,
effective January 1, 2009. For oil sands projects, the new terms are based on
a sliding scale royalty rate that responds to Canadian dollar equivalent WTI
("C$-WTI") price levels. The minimum royalty rate is proposed to start at one
per cent of revenue and increase for every dollar oil is priced above $55
C$-WTI per barrel, to nine per cent of revenue at $120 C$-WTI per barrel or
higher. The net royalty rate will start at 25 per cent of net revenue and rise
for every dollar of C$-WTI increase above $55 C$-WTI per barrel up to 40 per
cent of net revenue at $120 C$-WTI per barrel or higher.
    The Syncrude Joint Venture owners have a Crown royalty agreement with the
Alberta government that codifies the current royalty terms of 25 per cent of
net SCO revenues to December 31, 2015. The Crown royalty agreement also
provides Syncrude with the option to convert to a bitumen-based royalty,
consistent with the rest of the industry, prior to 2010. Canadian Oil Sands,
as one of the Syncrude owners, is currently in discussions with the Alberta
government regarding both the conversion to a bitumen-based royalty and an
equitable solution to offset Syncrude's transition to the higher generic
royalty rate prior to 2016. Canadian Oil Sands remains of the view that any
transition to the new generic royalty terms must recognize our legal rights to
the embedded value in Syncrude's contract with the Alberta government.

    
    Interest Expense, Net

                                    Three Months Ended     Nine Months Ended
                                        September 30          September 30
                                      2008       2007       2008       2007
    -------------------------------------------------------------------------

    Interest expense on
     long-term debt               $      18  $      22  $      56  $      71
    Interest income and other            (2)        (1)        (7)        (3)
    -------------------------------------------------------------------------
      Interest expense, net       $      16  $      21  $      49  $      68
    -------------------------------------------------------------------------

    The Trust's net interest expense in 2008 has decreased relative to the
comparable periods in 2007 due to reduced average net debt outstanding.

    Depreciation, Depletion and Accretion Expense

                                    Three Months Ended     Nine Months Ended
                                        September 30          September 30
    -------------------------------------------------------------------------
    ($ millions)                      2008       2007       2008       2007
    -------------------------------------------------------------------------

    Depreciation and depletion
     expense                      $     118  $      98  $     315  $     252
    Accretion expense                     3          3         10          8
    -------------------------------------------------------------------------
                                  $     121  $     101  $     325  $     260
    -------------------------------------------------------------------------
    

    The increase in depreciation and depletion ("D&D") expense in 2008 on a
quarterly and on a year-to-date basis versus 2007 was due to a higher per
barrel D&D rate. In 2008 the D&D rate per barrel of production increased to
$11.07 from $8.31 in 2007 as a result of higher projected capital cost
estimates for Syncrude in the Trust's December 31, 2007 independent reserves
report.

    
    Foreign Exchange Loss (Gain)

                                    Three Months Ended     Nine Months Ended
                                        September 30          September 30
    ($ millions)                      2008       2007       2008       2007
    -------------------------------------------------------------------------

    Unrealized foreign exchange
     loss (gain)                  $      36  $     (59) $      62  $    (146)
    Realized foreign exchange
     loss (gain)                         (4)        17         (9)        34
    -------------------------------------------------------------------------
      Total foreign exchange
       loss (gain)                $      32  $     (42) $      53  $    (112)
    -------------------------------------------------------------------------
    

    Unrealized foreign exchange ("FX") gains and losses are 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 unrealized FX
gains and losses reported in 2008 resulted from the change in the value of the
Canadian dollar relative to the U.S. dollar to $0.94 US/Cdn at September 30,
2008 from $0.98 US/Cdn at June 30, 2008 and $1.01 US/Cdn at December 31, 2007.
The unrealized FX gains in 2007 were due to the change in the value of the
Canadian dollar relative to the U.S. dollar to $1.00 US/Cdn at September 30,
2007 from $0.94 US/Cdn at June 30, 2007 and $0.86 US/Cdn at December 31, 2006.

    Future Income Tax and Other

    In the third quarter of 2008, a $6 million future income tax expense was
recorded on the increase of temporary differences versus a future income tax
expense of $69 million in the third quarter of 2007. On a year-to-date basis,
a future income tax recovery of $18 million was recorded in 2008 on the
reduction of temporary differences compared with a future income tax expense
of $697 million in 2007.
    Prior to the substantive enactment of Bill C-52 in June 2007, the federal
government's legislation to tax distributions from income trusts commencing in
2011, Canadian Oil Sands' future income taxes reflected only those temporary
differences in the Trust's subsidiaries. On the substantive enactment of Bill
C-52, Canadian Oil Sands recorded a one-time $701 million future income tax
expense and a corresponding future income tax liability during the second
quarter of 2007 related to the differences between the accounting and tax
basis of the Trust's assets and liabilities.
    In June 2008, Bill C-50, which contains legislation to adjust the deemed
provincial component on the tax rate on distributions from income and royalty
trusts expected to apply to Canadian Oil Sands commencing in 2011, passed
third reading in the House of Commons. Under this legislation, we expect the
provincial component of the tax applicable to Canadian Oil Sands will be
reduced from 13 per cent to 10 per cent as substantially all of Canadian Oil
Sands' activities are in Alberta. For accounting purposes the adjustment to
the provincial component of the tax is not considered substantively enacted as
the income tax regulations for the adjustment have not been finalized. If the
proposal becomes enacted, we expect to record a future income tax recovery
based on the temporary differences at that time.
    On July 14, 2008, the Department of Finance released draft legislation
for income and royalty trust conversions. The draft legislation, which was
subject to public comment, is designed to permit income and royalty trusts to
convert into public corporations without triggering adverse tax consequences
to the income or royalty trust and its unitholders.
    With the taxation of income trusts commencing January 1, 2011 Canadian
Oil Sands has evaluated alternatives as to the best structure for its
Unitholders in the future. Based on the current information and subject to the
finalization of tax legislation, we will likely convert to a corporation. We
plan, however, to retain the flow-through advantages of a trust structure
until 2011 unless circumstances arise that favor a faster transition. Canadian
Oil Sands continues to be a long-term value investment in the oil sands and
does not rely on the tax efficiency of a flow-through trust model to sustain
its business. Our long-life reserves and virtually non-declining production
profile provide a solid foundation to generate future cash from operating
activities.

    CHANGES IN ACCOUNTING POLICIES

    In its audited consolidated financial statements for the year ended
December 31, 2007 ("Audited 2007 Financial Statements"), Canadian Oil Sands
adopted the requirements of the Canadian Institute of Chartered Accountants
("CICA") Section 3862 Financial Instruments - Disclosures, Section 3863
Financial Instruments - Presentation and Section 1535 - Capital Disclosures.
These standards were effective January 1, 2008, however, early adoption was
encouraged by the CICA. Additional disclosures required as a result of
adopting the standards can be found in the Trust's Audited 2007 Financial
Statements.
    In June 2007, the CICA issued a new accounting standard Section 3031
Inventories, which replaces the existing standard for inventories, Section
3030. The main features of the new section are as follows:

    
    -   measurement of inventories at the lower of cost and net realizable
        value;

    -   consistent use of either first-in, first-out or a weighted average
        cost formula to measure cost; and

    -   reversal of previous write-downs to net realizable value when there
        is a subsequent increase to the value of inventories.
    

    The new inventory standard is effective for the Trust beginning
January 1, 2008. Application of the new standard did not have an impact on the
Trust's financial statements.

    NEW ACCOUNTING PRONOUNCEMENTS

    In February 2008, the 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 is not
expected to have a material impact on the Trust's financial statements.
    On February 13, 2008 the CICA Accounting Standards Board announced that
Canadian public reporting issuers will be required to report under
International Financial Reporting Standards ("IFRS") starting in 2011.
Canadian Oil Sands has commenced assessing the impact on our business of
adopting IFRS in 2011 and is preparing for the transition accordingly.

    
    UNITHOLDER DISTRIBUTIONS

                                    Three Months Ended     Nine Months Ended
                                        September 30          September 30
    -------------------------------------------------------------------------
    ($ millions)                      2008       2007       2008       2007
    -------------------------------------------------------------------------

    Cash from operating
     activities                   $     921  $     484  $   1,775  $   1,010

    Net income                    $     604  $     361  $   1,399  $     228

    Unitholder distributions      $     602  $     192  $   1,443  $     527
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Excess (shortfall) of cash
     from operating activities
     over Unitholder
     distributions                $     319  $     292  $     332  $     483

    Excess (shortfall) of net
     income over Unitholder
     distributions                $       2  $     169  $     (44) $    (299)
    -------------------------------------------------------------------------
    

    In the third quarter of 2008, cash from operating activities exceeded
Unitholder distributions by $319 million. On a year-to-date basis, cash from
operating activities in 2008 exceeded Unitholder distributions by
$332 million. During 2008, cash from operating activities was sufficient to
fund the Trust's distributions, capital expenditures, reclamation trust fund
contributions and the majority of debt repayments.
    Total distributions during 2008 exceeded net income on a year-to-date
basis primarily as a result of DD&A, which is a non-cash item that does not
affect the Trust's cash from operating activities or ability to pay
distributions over the next several years.
    The Trust uses debt and equity financing to the extent that cash from
operating activities and existing cash balances are insufficient to fund
distributions, capital expenditures, reclamation trust contributions, debt
repayments, acquisitions and working capital changes from financing and
investing activities.
    On October 29, 2008 the Trust declared a quarterly distribution of $0.75
per Unit in respect of the fourth quarter of 2008 for a total distribution of
$361 million. The distribution will be paid on November 28, 2008 to
Unitholders of record on November 14, 2008. Quarterly distributions are
approved by our Board of Directors after considering the current and expected
economic conditions, ensuring financing capacity for Canadian Oil Sands'
capital requirements, and with the objective of maintaining an investment
grade credit rating.
    In establishing the distribution amount for the current quarter the Trust
has recognized both the significant decrease in crude oil prices and the
turmoil in worldwide credit markets. The price of WTI crude oil has quickly
declined from approximately US$120 per barrel when the last distribution was
established to approximately US$60 to US$70 per barrel during October 2008.
While the decrease in commodity prices has been partially offset by a
weakening Canadian dollar, if lower oil prices persist, cash from operating
activities and our ability to fund distributions and capital expenditures will
significantly decline. In addition, as a result of the ongoing credit market
and banking turmoil, there is heightened financing risk around the ability of
the Trust to prudently access the capital markets. The Trust has approximately
$500 million of bonds maturing within the next ten months, and had planned on
refinancing these debt instruments through credit facility draws and eventual
refinancing in the capital markets. With the recent credit market turmoil,
risk around accessing these markets in a cost-effective manner has risen.
During this period of heightened financing risk, we believe that it is prudent
to reduce the rate at which leverage levels rise to maintain liquidity and
financial flexibility. As the financial markets calm and there is more
certainty around the ability to access the markets in an efficient and
cost-effective manner, we still plan on refinancing the 2009 debt maturities
and increasing our net debt to about $1.6 billion by the end of 2010. At
current market prices, the Trust continues to generate significant cash from
operating activities and is currently undrawn on its $840 million of credit
facilities. We are therefore well positioned to execute our financial and
operating strategies.
    The current distribution continues to reflect the Trust's financial plan
of managing its capital structure in anticipation of trust taxation in 2011.
The Trust has been distributing a fuller amount of its cash from operating
activities, and still targets long-term net debt of about $1.6 billion by the
end of 2010. We believe this net debt target reflects efficient capital
management and will help conserve tax pools prior to trust taxation. The
target is based on Syncrude's existing productive capacity and we will
reconsider this target in light of Canadian Oil Sands future capital
requirement plans and any growth opportunities.
    In determining the Trust's distributions, Canadian Oil Sands also
considers funding for its significant operating obligations, which are
included in cash from operating activities. Such obligations include the
Trust's share of Syncrude's pension and reclamation funding, which amounted to
$32 million and $30 million on a year-to-date basis in 2008 and 2007,
respectively, and approximated the related expense for both pension and
reclamation of $38 million and $32 million for each of the periods,
respectively. While our share of Syncrude's annual pension funding has
increased modestly as a result of the most recent actuarial valuation and our
share of Syncrude's future reclamation costs also has increased, we currently
do not anticipate any material increases in funding related to these items for
the next year.
    Debt covenants do not specifically limit the Trust's ability to pay
distributions and are not expected to influence the Trust's liquidity in the
foreseeable future. Aside from covenants relating to restrictions on Canadian
Oil Sands' ability to sell all or substantially all of its assets or to change
the nature of its business, the most restrictive financial covenant limits
total debt-to-total capitalization at an amount less than 55 per cent. With a
current net debt-to-total capitalization of approximately 20 per cent, a
significant increase in debt or decrease in equity would be required to
restrict the Trust's financial flexibility.
    Cash from operating activities and net income can fluctuate dramatically
from period to period reflecting, among other things, variability in
operational performance, WTI prices, SCO differentials to WTI and FX rates.
The Trust strives to smooth out the effect of this variability on
distributions by taking a longer-term view of our outlook for our operating
and business environment, our net debt level relative to our target, and our
capital expenditure and other commitments. In that regard, we may distribute
more or less in a period than we generate in cash from operating activities or
net income. Nonetheless, the highly variable nature of our cash from operating
activities introduces risk in our ability to sustain or provide stability in
distributions and any expectations regarding the stability or sustainability
of distributions are unwarranted and should not be implied.
    As the Trust executes its financial plan and crude oil prices remain
volatile, investors should anticipate increased variability in distributions
and understand that current distribution levels may not be sustainable once we
have reached our net debt target. As distributions comprise a larger
percentage of cash from operating activities, the distributions will
necessarily be more reflective of business performance and crude oil prices.
Further, the taxation of income trusts commencing January 1, 2011 likely will
materially alter our cash from operating activities and consequently
distribution levels.

    
    LIQUIDITY AND CAPITAL RE

SOURCES September 30 December 31 ($ millions) 2008 2007 ------------------------------------------------------------------------- Long-term debt $ 1,116 $ 1,218 Cash and cash equivalents (278) (268) ------------------------------------------------------------------------- Net debt(1) $ 838 $ 950 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Unitholders' equity $ 4,148 $ 4,172 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total capitalization(2) $ 4,986 $ 5,122 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Non-GAAP measure (2) Net debt plus Unitholders' equity Net debt to total capitalization (%) 17 19 ------------------------------------------------------------------------- As at September 30, 2008 the Trust had $840 million of credit facilities available and unutilized. In addition, the Trust had $67 million in letters of credit issued against a separate line of credit. During the second quarter of 2008, the Trust repaid $150 million of medium term notes that matured. Canadian Oil Sands has set a long-term net debt target of approximately $1.6 billion by the end of 2010. The Trust's actual net debt will fluctuate, however, as factors such as actual crude oil prices, Syncrude's operational performance, distributions, and FX rates vary from our assumptions. CAPITAL EXPENDITURES With the completion of Syncrude's Stage 3 project in 2006, Canadian Oil Sands' expansion capital expenditures have declined and capital costs for 2008 and 2007 are primarily related to sustaining capital. The Trust defines expansion capital expenditures as the costs incurred to grow the productive capacity of the operation, such as the Stage 3 project, while sustaining capital is effectively all other capital. Sustaining capital expenditures may fluctuate considerably year-to-year due to the timing of 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 2008, capital expenditures totalled $94 million, compared with expenditures of $45 million in the same quarter of 2007. The Syncrude Emissions Reduction ("SER") project accounted for $18 million and $17 million of the capital spent in the third quarters of 2008 and 2007, respectively. The remaining amounts in each quarter pertained to other sustaining capital activities including replacement trucks and infrastructure projects. Sustaining capital expenditures on a per barrel basis were approximately $8.69 and $3.95 in each of the third quarters of 2008 and 2007, respectively. Year-to-date capital expenditures totalled $195 million in 2008 versus $128 million in 2007. The SER project accounted for $56 million and $51 million of the capital spent in 2008 and 2007, respectively, with the remaining expenditures relating to other sustaining capital activities. Sustaining capital expenditures on a per barrel basis were approximately $6.78 and $4.21 on a year-to-date basis in 2008 and 2007, respectively. Syncrude is undertaking the SER project to retrofit technology into the operation of Syncrude's original two cokers to significantly reduce total sulphur dioxide and other emissions. After the completion of the SER project, stack emissions of sulphur compounds are anticipated to be about 60 per cent lower than current approved levels. In the third quarter of 2008, Syncrude completed its review of the SER project and revised its cost estimates for the project to $1.6 billion ($590 million net to the Trust) from $772 million ($284 million net to the Trust). The cost increase reflects a delay in the expected completion date and inflationary pressures. The Trust's share of the SER project expenditures incurred to date is approximately $163 million, with the remaining costs expected to be incurred over the next four years to coordinate with equipment turnaround schedules. Sustaining capital expenditures, including the SER project, are estimated to average approximately $7 per barrel for 2008. Over the longer term, we expect sustaining capital expenditures to average approximately $6 per barrel excluding inflation; however, over the next few years we may incur an additional $5 to $10 per barrel annually for large environmental and infrastructure projects. These projects include the relocation of certain mining trains and tailings systems, which is required as mining operations progress across the active leases. Tailings system projects also include initiatives to improve and supplement the effectiveness of systems used to separate water from sand and clay so that the water can be recycled back to the operation and solids can be incorporated into the final reclamation landscapes. Our per barrel estimates are based on estimated annual Syncrude production, which increases from 106 million barrels in 2008, or 39 million barrels net to the Trust, to 129 million barrels, or 47 million barrels net to the Trust, at design capacity. Syncrude's next significant growth stage is anticipated to be the Stage 3 debottleneck, which is estimated to increase Syncrude's productive capacity by about 50,000 barrels per day. Following the debottleneck, the Stage 4 expansion was expected to grow Syncrude capacity by a further 100,000 barrels per day, post-2016. Syncrude is re-evaluating its plans to increase production well beyond the 500,000 barrels per day provided by the Stage 4 expansion. The objective is to develop an expansion plan that maintains an appropriate resource life based on an independent estimate of Syncrude's reserves and resources as of December 31, 2007. The scoping engineering work on the Stage 3 debottleneck and subsequent expansion stages has been approved by the joint venture owners and is being pursued. Spending will ramp up as the engineering work progresses. The timing of the expansions will depend on the engineering and construction execution plans. It is possible that the debottleneck will be delayed beyond our current 2012 projected startup as could other expansion timing. We plan to provide more information on timing over the next year or two as the scoping work progresses. No cost estimates have been provided for these projects nor have they been approved by the Syncrude owners as they are still in the early planning stages. 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 $18.7 billion with 482 million Units outstanding and a closing price of $38.76 per Unit on September 30, 2008. Canadian Oil Sands Trust - Trading Activity Third Quarter September August July 2008 2008 2008 2008 ------------------------------------------------------------------------- Unit price High $ 55.25 $ 50.12 $ 53.26 $ 55.25 Low $ 36.20 $ 36.20 $ 45.21 $ 44.63 Close $ 38.76 $ 38.76 $ 51.46 $ 51.44 Volume traded (millions) 108.8 51.0 26.1 31.7 Weighted average Trust units outstanding (millions) 481.5 481.5 481.5 481.5 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONTRACTUAL OBLIGATIONS AND COMMITMENTS With the exception of an additional $828 million ($304 million net to the Trust) expected to be incurred by Syncrude in respect of the SER project and the repayment of $150 million in maturing medium term notes during the second quarter of 2008, there have been no significant changes to the Trust's contractual obligations and commitments in 2008 from our 2007 year-end disclosure. FINANCIAL RISK MANAGEMENT The Trust did not have any financial derivatives outstanding at September 30, 2008. Crude Oil Price Risk Canadian Oil Sands did not have any crude oil price hedges in place for 2008 or 2007. As at September 30, 2008, the Trust remains unhedged on its crude oil price exposure and does not intend to introduce any crude oil hedge positions. Canadian Oil Sands may, however, hedge its crude oil production in the future depending on the business environment and growth opportunities. Foreign Currency Hedging As at September 30, 2008, we do not have any foreign currency hedges in place. At the present time, we do not intend to introduce any currency hedge positions. Canadian Oil Sands may, however, hedge foreign exchange rates in the future, depending on the business environment and growth opportunities. Interest Rate Risk Canadian Oil Sands' net income and cash from operating activities are impacted by interest rate changes based on the amount of floating rate debt outstanding. As at September 30, 2008, we did not have any debt outstanding bearing interest at floating market-based rates. 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 through daily and longer-term cash, debt and equity management strategies. Such strategies encompass, among other factors: having adequate sources of financing available through its bank credit facilities, estimating future cash generated from operations based on reasonable production and pricing assumptions, analysis of economic hedging opportunities and compliance with debt covenants. Within the next year, two tranches of Canadian Oil Sands' debt will mature. As well, Canadian Oil Sands has stated its intention to increase net debt to approximately $1.6 billion by the end of 2010. Canadian Oil Sands will therefore be subject to liquidity risk in the coming years in respect of these financing requirements. In addition, we are exposed to liquidity risk to the extent we have financing requirements related to significant capital or operating commitments. Over the long-term, Canadian Oil Sands manages these risks by spreading out the maturities of its various debt tranches and maintaining a prudent capital structure. During 2007 and 2008, the economic crisis has spread resulting in a tightening of credit markets characterized by a decline in liquidity and higher borrowing costs. While Canadian Oil Sands continues to generate significant cash from operating activities and has $840 million of unutilized credit facilities to support liquidity, access to capital markets has become constrained and significantly more expensive. The Trust has approximately $500 million of debt maturities in the next ten months, and is considering the risk that the financial markets do not improve over this time frame as part of its financing plan. Should bank facilities or debt markets not be available to fund our mid-2009 debt maturities, further distribution reductions may be required in order to fund maturities out of cash from operating activities. Credit Risk Canadian Oil Sands is exposed to credit risk primarily through its trade accounts receivable balances with customers and with financial counterparties with whom the Trust has invested its cash and purchased term deposits from. At September 30, 2008, over 90 per cent of our accounts receivable balance was due from investment grade energy producers and refinery-based customers. At September 30, 2008, over 95 per cent of our cash and cash equivalents were invested in term deposits from a range of high-quality senior Canadian banks. FOREIGN OWNERSHIP Based on information from the statutory declarations by Unitholders, we estimate that, as of August 15 2008, approximately 32 percent of our Units are held by non-Canadian residents with the remaining 68 per cent of Units being held by Canadian residents. Canadian Oil Sands' Trust Indenture provides that not more than 49 per cent of its Units can be held by non-Canadian residents. The Trust regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of November 14, 2008. The Trust posts its foreign ownership level 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. SUSTAINABLE DEVELOPMENT Waterfowl Incident at Syncrude's Aurora Mine Tailings Pond In April 2008, a flock of ducks landed and died on one of Syncrude's tailings ponds. Syncrude is cooperating with Alberta Environment in their investigation into why this occurred and on improvements to help prevent future occurrences. Greenhouse Gas Emissions Reduction Requirements In 2007, through the Specified Gas Emitters Regulation, Alberta became the first province in Canada to regulate greenhouse gases by establishing intensity targets for Large Final Emitters of carbon. Effectively, the regulation requires Syncrude, beginning in the second half of 2007, to reduce its per barrel emissions of greenhouse gases by 12 per cent from the average of its annual per barrel emissions between 2003 and 2005. If Syncrude is unable to meet this target directly, it must purchase offset credits or pay into a government fund dedicated to the development of emissions reduction technology. For 2007, Syncrude met 90 per cent of its reduction target under the new regulation and offset the remainder through the payment of approximately $1 million to the Alberta government's technology fund. Syncrude's emissions calculation method and its data were externally verified. For 2008, Syncrude is accruing approximately $0.10 per barrel for compliance with the Specified Gas Emitters Regulation, which is reflected in the Trust's operating costs. The cost estimate remains preliminary pending Syncrude's actual carbon dioxide ("CO(2)") emission intensity level and clarification from the Alberta government regarding details of implementation. No cost estimates are available for future years. On March 10, 2008 Canada's federal government provided further detail on its regulatory framework to reduce GHG and air pollutant emissions originally announced on April 26, 2007. The draft regulations are currently expected to be finalized in 2009 and take effect on January 1, 2010. The draft regulations for oil sands projects require existing projects to reduce emissions intensity by 18 per cent in 2010 from the 2006 level and two per cent thereafter. New oil sands facilities coming onstream over the period 2004 to 2011 also will be required to meet clean fuel standards and will be encouraged to implement mechanisms to capture CO(2) emissions. In addition to the reduction of existing GHG emissions, the capture and storage of CO(2) emissions ("CCS") will be a requirement for all oil sands projects coming onstream post 2012. The draft regulations are expected to impact both current Syncrude operations and its future expansion projects, however the full impact of the regulations cannot be quantified until they are finalized. Syncrude continues to explore and implement measures to reduce energy intensity in its operations, which reduces both CO(2) emissions and operating costs. Syncrude also is exploring the viability of developing a large scale CO(2) capture, transportation and storage network through participation in the integrated CO(2) Network ("ICON"). Reclamation In March 2008, the Alberta government certified a parcel of reclaimed land north of Fort McMurray. The 104 hectares, known as Gateway Hill, was submitted by Syncrude to the Alberta government in 2003 for certification. Alberta's Environmental Protection and Enhancement Act requires operators to conserve and reclaim specified land and obtain a reclamation certificate. These certificates are issued to operators when their site has been successfully reclaimed. Syncrude is the first in the oil sands industry to receive certification for land that has been reclaimed. Syncrude has reclaimed more than 4,500 hectares, representing the largest share in the oil sands industry. Tailings Management Syncrude's reclamation efforts also include tailings systems management. Tailings systems are designed to separate water from sand and clay to enable incorporation of solids into reclamation landscapes and recycling of water back into the operations. Syncrude and most other oil sands producers use a method called consolidated tails technology; however, additional tailings management technologies may be required in order to meet the approved closure and reclamation plan. Syncrude is exploring methods to improve and supplement the effectiveness of its tailings systems. On June 26, 2008, the Alberta Energy Resources Conservation Board ("ERCB") released a draft Directive on Tailings Criteria for public review and comment. This directive proposes to develop new industry-wide criteria to supplement existing regulations by requiring operators to: - prepare an operations and abandonment plan for every consolidated tailings pond, which would be reviewed for the establishment of performance measures by the ERCB; - operate and abandon each consolidated tailings pond in accordance with their applications or ERCB approvals; - consume fine fluid tailings as proposed in their applications or as approved by the ERCB; and - specify dates for pond construction, pond use, pond closure, and other milestones and file these dates with the ERCB through the course of 2009. Syncrude is involved in both the review of the draft directive and submission of comments to the ERCB, as well as assessing the impact of the proposed directive on current and future operations. Until the directive is finalized, the impact, if any, of the new regulations on Syncrude cannot be fully determined. The regulation as presently drafted, however, is likely to have an adverse impact on the costs for tailings management. Syncrude is filing an amendment to its regulatory approval to modify the design of the existing Southwest Sand Storage ("SWSS") facility to permit interim storage of increased volumes of mature fine tailings. Changes to the design of the SWSS facility will be required to increase its fluid storage capacity. The change in design would not increase the footprint of the structure but rather elevate the fluid level within it. Pending regulatory approval, Syncrude intends to make use of this increase in capacity in 2009. 2008 OUTLOOK (millions of Canadian dollars, October 29, July 29, except volume and per barrel amounts) 2008 2008 ------------------------------------------------------------------------- Syncrude production (MMbbls) 106 106 Canadian Oil Sands Sales (MMbbls) 38.9 38.9 Revenues, net of crude oil purchases and transportation 4,336 4,734 Operating costs 1,381 1,381 Operating costs per barrel 35.47 35.46 Crown royalties 646 742 Capital expenditures 284 294 Cash from operating activities 2,204 2,356 Business environment assumptions -------------------------------- West Texas Intermediate (US$/bbl) $ 102 $ 120 Premium (Discount) to average C$ WTI prices (C$/bbl) $ 2.75 $ 1.50 Foreign exchange rate (US$/Cdn$) $ 0.94 $ 1.00 AECO natural gas (Cdn$/GJ) $ 8.00 $ 9.50 The Trust is maintaining its estimate for 2008 Syncrude production of 106 million barrels which reflects year-to-date results, Syncrude's remaining 2008 maintenance program, and an allowance for unplanned outages. The range for Syncrude production is estimated at 103 to 109 million barrels for 2008. We have decreased the Trust's 2008 revenue outlook as a result of a lower estimated SCO sales price for the last quarter. The Trust has not assumed any further bitumen purchases in this current Outlook; however, Syncrude may purchase up to 10,000 barrels per day of additional bitumen during the remainder of 2008 to provide for flexibility in SCO production. The decrease in forecasted Crown royalties is due to the decrease in estimated revenues. Based on current assumptions, our estimate of cash from operating activities has decreased to $2,204 million, or $4.58 per Unit. With the decrease in the distribution to $0.75 per Unit in the fourth quarter of 2008, we are estimating net debt levels of approximately $1.1 billion at the end of 2008. Distributions paid in 2008 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 2009. Changes in certain factors and market conditions could potentially impact Canadian Oil Sands' Outlook. The following table provides a sensitivity analysis of the key factors affecting the Trust's performance. In addition to the factors described in the table, the supply/demand equation and pipeline access for synthetic crude oil in the North American markets could impact the differential for SCO relative to crude benchmarks; however, these factors are difficult to predict. (NTD numbers in the following table are not final) 2008 Outlook Sensitivity Analysis Cash from Operating Activities Annual(2) Increase Variable(1) Sensitivity $ millions $/Trust unit ------------------------------------------------------------------------- Syncrude operating costs decrease C$1.00/bbl 29 0.06 Syncrude operating costs decrease C$50 million 14 0.03 WTI crude oil price increase US$1.00/bbl 25 0.05 Syncrude production increase 2 million bbls 31 0.06 Canadian dollar weakening US$0.01/C$ 22 0.04 AECO natural gas price decrease C$0.50/GJ 14 0.03 (1) An opposite change in each of these variables will result in the opposite cash from operating activities impacts. (2) Sensitivities assume a larger change in unrealized quarters to result in the annual impact. CANADIAN OIL SANDS TRUST CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (unaudited) Three Months Ended Nine Months Ended ($ millions, except per September 30 September 30 Unit amounts) 2008 2007 2008 2007 ------------------------------------------------------------------------- Revenues $ 1,463 $ 1,035 $ 3,775 $ 2,626 Crude oil purchases and transportation expense (82) (99) (310) (326) ------------------------------------------------------------------------- 1,381 936 3,465 2,300 ------------------------------------------------------------------------- Expenses: Operating 345 239 1,042 741 Non-production 21 16 54 49 Crown royalties 231 165 540 348 Administration 3 4 16 14 Insurance 2 2 5 6 Interest, net (Note 8) 16 21 49 68 Depreciation, depletion and accretion 121 101 325 260 Foreign exchange loss (gain) 32 (42) 53 (112) ------------------------------------------------------------------------- 771 506 2,084 1,374 ------------------------------------------------------------------------- Earnings before taxes 610 430 1,381 926 Future income tax expense (recovery) and other 6 69 (18) 697 ------------------------------------------------------------------------- Net income from continuing operations 604 361 1,399 229 Loss from discontinued operations - - - (1) ------------------------------------------------------------------------- Net income 604 361 1,399 228 Other comprehensive loss, net of income taxes Reclassification of derivative gains to net income (1) (2) (2) (6) ------------------------------------------------------------------------- Comprehensive income $ 603 $ 359 $ 1,397 $ 222 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Weighted average Trust Units (millions) 482 479 481 479 Trust Units, end of period (millions) 482 479 482 479 Net income per Trust Unit: Basic $ 1.25 $ 0.75 $ 2.91 $ 0.48 Diluted $ 1.25 $ 0.75 $ 2.91 $ 0.48 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) 2008 2007 2008 2007 ------------------------------------------------------------------------- Retained earnings Balance, beginning of period $ 1,597 $ 1,223 $ 1,643 $ 1,691 Net income 604 361 1,399 228 Unitholder distributions (Note 9) (602) (192) (1,443) (527) ------------------------------------------------------------------------- Balance, end of period 1,599 1,392 1,599 1,392 ------------------------------------------------------------------------- Accumulated other comprehensive income Balance, beginning of period 23 26 24 30 Other comprehensive loss (1) (2) (2) (6) ------------------------------------------------------------------------- Balance, end of period 22 24 22 24 ------------------------------------------------------------------------- Unitholders' capital Balance, beginning of period 2,524 2,499 2,500 2,260 Issuance of Trust Units (Note 4) - - 24 239 ------------------------------------------------------------------------- Balance, end of period 2,524 2,499 2,524 2,499 ------------------------------------------------------------------------- Contributed surplus Balance, beginning of period 3 4 5 4 Exercise of employee stock options - - (3) - Stock-based compensation - 1 1 1 ------------------------------------------------------------------------- Balance, end of period 3 5 3 5 ------------------------------------------------------------------------- Total Unitholders' equity $ 4,148 $ 3,920 $ 4,148 $ 3,920 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See Notes to Unaudited Consolidated Financial Statements CANADIAN OIL SANDS TRUST CONSOLIDATED BALANCE SHEETS AS AT (unaudited) September 30 December 31 ($ millions) 2008 2007 ------------------------------------------------------------------------- ASSETS Current assets: Cash and cash equivalents $ 278 $ 268 Accounts receivable 377 379 Inventories 104 102 Prepaid expenses 6 6 ------------------------------------------------------------------------- 765 755 Property, plant and equipment, net 6,297 6,427 Goodwill 52 52 Reclamation trust 41 37 ------------------------------------------------------------------------- $ 7,155 $ 7,271 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $ 332 $ 289 Current portion of employee future benefits 17 16 ------------------------------------------------------------------------- 349 305 Employee future benefits and other liabilities 103 128 Long-term debt 1,116 1,218 Asset retirement obligation 235 226 Future income taxes 1,204 1,222 ------------------------------------------------------------------------- 3,007 3,099 Unitholders' equity 4,148 4,172 ------------------------------------------------------------------------- $ 7,155 $ 7,271 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commitments (Note 10) 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) 2008 2007 2008 2007 ------------------------------------------------------------------------- Cash from (used in) operating activities Net income $ 604 $ 361 $ 1,399 $ 228 Items not requiring outlay of cash: Depreciation, depletion and accretion 121 101 325 260 Unrealized foreign exchange on long-term debt 36 (59) 62 (146) Future income tax expense (recovery) 6 68 (18) 696 Other (1) 1 4 (3) Net change in deferred items (9) (2) (25) (2) ------------------------------------------------------------------------- 757 470 1,747 1,033 Change in non-cash working capital 164 14 28 (23) ------------------------------------------------------------------------- Cash from operating activities 921 484 1,775 1,010 ------------------------------------------------------------------------- Cash from (used in) financing activities Repayment of medium term and Senior Notes - - (150) (272) Net drawdown (repayment) of bank credit facilities - (70) (16) - Unitholder distributions (Note 9) (602) (192) (1,443) (527) Issuance of Trust Units (Note 4) - (1) 21 1 ------------------------------------------------------------------------- Cash used in financing activities (602) (263) (1,588) (798) ------------------------------------------------------------------------- Cash from (used in) investing activities Capital expenditures (94) (45) (195) (128) Acquisition of additional Syncrude working interest - - - (231) Disposition of properties - - - 4 Reclamation trust funding (1) (1) (4) (4) Change in non-cash working capital 22 (7) 22 (5) ------------------------------------------------------------------------- Cash used in investing activities (73) (53) (177) (364) ------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents 246 168 10 (152) Cash and cash equivalents at beginning of period 32 33 268 353 ------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 278 $ 201 $ 278 $ 201 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash and cash equivalents consist of: Cash $ 10 $ 1 Short-term investments 268 200 ------------------------------------------------------------------------- $ 278 $ 201 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplementary Information (Note 11) See Notes to Unaudited Consolidated Financial Statements NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2008 (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, 2007, 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, 2007. 2) CHANGES IN ACCOUNTING POLICIES In its consolidated financial statements for the year ended December 31, 2007, Canadian Oil Sands adopted the requirements of the Canadian Institute of Chartered Accountants ("CICA") Section 3862 Financial Instruments - Disclosures, Section 3863 Financial Instruments - Presentation, and Section 1535 Capital Disclosures. The standards were effective January 1, 2008, however early adoption was encouraged by the CICA. Additional disclosures required as a result of adopting the standards can be found in the Trust's consolidated financial statements for the year ended December 31, 2007. In June 2007, the CICA issued a new accounting standard - Section 3031 Inventories, which replaces the existing standard for inventories, Section 3030. The main features of the new Section are as follows: - Measurement of inventories at the lower of cost and net realizable value - Consistent use of either first-in, first-out or a weighted average cost formula to measure cost - Reversal of previous write-downs to net realizable value when there is a subsequent increase to the value of inventories The new Section was effective for the Trust beginning January 1, 2008. Application of the new Section did not have a significant impact on the financial statements. 3) FUTURE CHANGES IN ACCOUNTING POLICIES In February 2008, the 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 is not expected to have a material impact on the Trust's financial statements. 4) ISSUANCE OF TRUST UNITS 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 retirement 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, 2008 and 2007 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 2008 2007 2008 2007 --------------------------------------------------------------------- Defined benefit plans: Pension benefits $ 8 $ 6 $ 23 $ 20 Other benefit plans 1 1 3 3 --------------------------------------------------------------------- $ 9 $ 7 $ 26 $ 23 Defined contribution plans 1 - 2 1 --------------------------------------------------------------------- Total benefit cost $ 10 $ 7 $ 28 $ 24 --------------------------------------------------------------------- 6) BANK CREDIT FACILITIES --------------------------------------------------------------------- Extendible revolving term facility (a) $ 40 Line of credit (b) 67 Operating credit facility (c) 800 --------------------------------------------------------------------- $ 907 --------------------------------------------------------------------- --------------------------------------------------------------------- Each of the Trust's credit facilities is unsecured. These credit agreements contain typical covenants relating to the restrictions on Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business. In addition, Canadian Oil Sands has agreed to maintain its total debt-to-total book capitalization at an amount less than 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 23, 2009. 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, 2008, no amounts were drawn on this facility. b) The $67 million line of credit is a one-year revolving letter of credit facility. Letters of credit drawn on the facility mature April 30th each year and are automatically renewed, unless notification to cancel is provided by Canadian Oil Sands or the financial institution providing the facility at least 60 days prior to expiry. Letters of credit on this facility bear interest at a credit spread. Letters of credit of approximately $67 million have been written against the line of credit as at September 30, 2008. c) The $800 million operating facility is a five-year facility, expiring April 27, 2012. Amounts borrowed through this facility bear interest at a floating rate based on either prime interest rates or bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at September 30, 2008, no amounts were drawn on this facility. 7) LONG-TERM DEBT On April 9, 2008, the Trust repaid $150 million of 5.75% medium term notes. 8) INTEREST, NET Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 --------------------------------------------------------------------- Interest expense on long-term debt $ 18 $ 22 $ 56 $ 71 Interest income and other (2) (1) (7) (3) --------------------------------------------------------------------- Interest expense, net $ 16 $ 21 $ 49 $ 68 --------------------------------------------------------------------- --------------------------------------------------------------------- 9) UNITHOLDER DISTRIBUTIONS The Consolidated Statements of Unitholder Distributions is provided to assist Unitholders in reconciling cash from operating activities to Unitholder distributions. Pursuant to Section 5.1 of the Trust Indenture, the Trust is required to distribute all the 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 2008 2007 2008 2007 --------------------------------------------------------------------- Cash from operating activities $ 921 $ 484 $ 1,775 $ 1,010 Add (Deduct): Capital expenditures (94) (45) (195) (128) Acquisition of additional Syncrude working interest - - - (231) Disposition of properties - 4 Change in non-cash working capital(1) 22 (7) 22 (5) Reclamation trust funding (1) (1) (4) (4) Change in cash and cash equivalents and financing, net(2) (246) (239) (155) (119) --------------------------------------------------------------------- Unitholder distributions $ 602 $ 192 $ 1,443 $ 527 --------------------------------------------------------------------- --------------------------------------------------------------------- Unitholder distributions per Trust Unit $ 1.25 $ 0.40 $ 3.00 $ 1.10 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) From investing activities. (2) Primarily represents the change in cash and cash equivalents and net financing to fund the Trust's share of investing activities. 10) COMMITMENTS During the third quarter of 2008, Canadian Oil Sands committed to additional costs of approximately $304 million relating to its share of Syncrude's Emissions Reduction project. The additional costs are expected to be incurred over the next four years. 11) SUPPLEMENTARY INFORMATION Three Months Ended Nine Months Ended September 30 September 30 2008 2007 2008 2007 --------------------------------------------------------------------- Income tax paid $ - $ - $ - $ 1 --------------------------------------------------------------------- --------------------------------------------------------------------- Interest paid $ 18 $ 27 $ 56 $ 81 --------------------------------------------------------------------- Canadian Oil Sands Limited Canadian Oil Sands Trust Marcel Coutu 2500 First Canadian Centre President & Chief Executive Officer 350 - 7 Avenue S.W. Calgary, Alberta T2P 3N9 Units Listed - Symbol: COS.UN Ph: (403) 218-6200 Toronto Stock Exchange Fax: (403) 218-6201

For further information:

For further information: Siren Fisekci, Director, Investor Relations,
(403) 218-6228, investor_relations@cos-trust.com; web site: www.cos-trust.com

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CANADIAN OIL SANDS TRUST

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