Canadian Oil Sands Trust raises its quarterly distribution 36 per cent to $0.75 per Trust unit



    All financial figures are unaudited and in Canadian dollars unless
    otherwise noted. The Trust's 2007 financial results reflect a 36.74 per
    cent working interest in the Syncrude Joint Venture, which represents the
    Trust's increased ownership following its acquisition of a 1.25 per cent
    Syncrude interest from Talisman Energy Inc. on January 2, 2007. Prior
    year comparative information is based on the Trust's previous ownership
    of 35.49 per cent.

    TSX - COS.UN

    CALGARY, Jan. 30 /CNW/ - Canadian Oil Sands Trust ("Canadian Oil Sands",
the "Trust" or "we") today announced that 2007 cash from operating activities
increased 21 per cent to $1.4 billion, or $2.87 per Trust unit ("Unit"), over
2006. Net income decreased to $743 million ($1.55 per Unit) in 2007 from $834
million ($1.79 per Unit) last year. The decline reflects a $701 million future
income tax expense recorded in the second quarter of 2007 as a result of the
enactment of income trust taxation that takes effect in 2011. Earnings before
taxes increased by $469 million to $1,321 million in 2007 compared to 2006.
Future income tax is a non-cash item that has no current impact on our cash
from operating activities.
    The increase in both cash from operating activities and earnings before
taxes is largely attributable to a 22 percent increase in year-over-year sales
volumes, which averaged 112,000 barrels per day during 2007, and a higher 2007
realized selling price.
    The Trust has declared a 36 per cent increase in the quarterly
distribution amount to $0.75 per Unit from $0.55 per Unit for Unitholders of
record on February 12, 2008, payable on February 29, 2008.
    "In 2007 we reported strong financial results, met our annual production
forecast, and substantially increased distributions," said Marcel Coutu,
President and Chief Executive Officer. "For 2008, Syncrude is planning a heavy
maintenance program, which is expected to result in only a modest production
increase over last year. Syncrude remains focused on achieving design
capacity, which is about 10 per cent above where we are producing today. The
distribution increase this quarter reflects the financial plan we established
to enhance investor returns prior to trust taxation taking effect in 2011.
Based on current circumstances regarding this taxation, we most likely will
convert to a corporate structure."
    During the fourth quarter of 2007, cash from operating activities
decreased 11 per cent to $367 million ($0.77 per Unit) compared with the same
2006 period. Excluding working capital changes, cash from operating activities
increased in the fourth quarter of 2007 compared with 2006, principally due to
an increase in our net realized selling price and modestly higher sales
volumes quarter-over-quarter. Net income in the fourth quarter of 2007 was
$515 million ($1.07 per Unit), up from $128 million ($0.27 per Unit) in the
fourth quarter of 2006.

    
    CANADIAN OIL SANDS TRUST
    Highlights

                                    Three Months Ended   Twelve Months Ended
    (millions of Canadian                December 31           December 31
     dollars, except Trust unit
     and volume amounts)               2007       2006       2007       2006
    -------------------------------------------------------------------------

    Net Income                    $     515  $     128  $     743  $     834
      Per Trust unit - Basic      $    1.07  $    0.27  $    1.55  $    1.79
      Per Trust unit - Diluted    $    1.07  $    0.27  $    1.54  $    1.78

    Cash from Operating
     Activities                   $     367  $     412  $   1,377  $   1,142
      Per Trust unit              $    0.77  $    0.88  $    2.87  $    2.45

    Unitholder Distributions      $     264  $     140  $     791  $     512
      Per Trust unit              $    0.55  $    0.30  $    1.65  $    1.10

    Sales Volumes(1)
      Total (MMbbls)                   10.7       10.1       41.0       33.5
      Daily average (bbls)          116,368    110,185    112,298     91,844

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

    Net Realized Selling Price
     per barrel
      Realized selling price
       before hedging             $   88.50  $   63.47  $   79.02  $   71.96
      Currency hedging gains           0.23       0.24       0.27       0.60
    -------------------------------------------------------------------------
      Net realized selling price  $   88.73  $   63.71  $   79.29  $   72.56
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    West Texas Intermediate
     (average $US per barrel)(2)  $   90.50  $   60.16  $   72.36  $   66.25
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The Trust's sales volumes differ from its production volumes due to
        changes in inventory, which are primarily in-transit pipeline
        volumes, and are net of purchased crude oil volumes.

    (2) Pricing obtained from Bloomberg.
    


    2008 Outlook

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


    The Trust is estimating Syncrude production to total 115 million barrels
in 2008 with a range of 110 to 120 million barrels (net to the Trust,
equivalent to 42 million barrels with a range of 40 to 44 million barrels).
The single point production estimate incorporates Syncrude's extensive 2008
maintenance program, an allowance for unplanned outages and recognition that
Syncrude is still working to establish reliable Stage 3 design rates. During
2008, Syncrude plans to perform turnarounds of Coker 8-1 (second quarter) and
Coker 8-2 (third quarter) as well as associated maintenance work on other
units. The production range reflects our current best estimate of the upside
and downside in volumes Syncrude could experience, depending on operational
reliability, in 2008.
    More information on the Trust's Outlook is provided in the MD&A section
of this report and the January 30, 2008 guidance document, which is available
on the Trust's web site at www.cos-trust.com under "investor information".

    MANAGEMENT'S DISCUSSION AND ANALYSIS

    The following Management's Discussion and Analysis ("MD&A") was prepared
as of January 30, 2008 and should be read in conjunction with the unaudited
interim consolidated financial statements of Canadian Oil Sands Trust
("Canadian Oil Sands" or the "Trust") for the twelve months ended December 31,
2007 and December 31, 2006, as well as the audited consolidated financial
statements and MD&A of the Trust for the year ended December 31, 2006.

    ADVISORY- in the interest of providing the Trust's Unitholders and
potential investors with information regarding the Trust, including
management's assessment of the Trust's future production and cost estimates,
plans and operations, certain statements throughout this MD&A contain
"forward-looking statements" under applicable securities law. Forward-looking
statements in this M&DA include, but are not limited to, statements with
respect to: the preliminary estimate for repair costs of the December fire;
the expectation that increased inflationary costs in Alberta will negatively
impact Syncrude's costs in 2008; expectations regarding depreciation and
depletion rates and expense, accretion expense and asset retirement
obligations in 2008 and beyond; the expected structure to be assumed given the
Federal government's tax changes in 2011; plans regarding the refinancing of
the $150 million medium term note maturity in April 2008; expectations
regarding future distribution levels; the expectation that there will not be
any material funding increases relative to Syncrude's future reclamation costs
or pension funding for the next several years; the belief that the Trust will
not be restricted by its net debt to total capitalization financial covenant;
the expectation that no crude oil hedges will be entered into in the future;
the expected impact on the Trust from announced changes by the Alberta
government regarding its royalty regime; any expectations regarding the
enforceability of legal rights; the expected timeframe that current tax pools
will allow Canadian Oil Sands to shelter income post-2010; the plan to move to
fuller payout of cash from operating activities; the expected realized selling
price, which includes the anticipated differential to WTI, to be received in
2008 for Canadian Oil Sands' product; the potential amount payable in respect
of any future income tax liability; the expected increased reliability and
other benefits from the Management Services Agreement between Syncrude Canada
Ltd. and Imperial Oil Resources; the expected impact that increased supplies
of synthetic crude oil will have on the net realized selling price that
Canadian Oil Sands receives for its product; the level of energy consumption
in 2008 and beyond; the expectation that the SER project will significantly
reduce total sulphur dioxide and other emissions; capital expenditures for
2008; the anticipated cost and completion date for the SER project; the level
of natural gas consumption in 2008 and beyond; the expectations regarding
discussions with the Alberta government over Crown royalties applicable to
Syncrude; the expected price for crude oil and natural gas in 2008; the
expected production, revenues and operating costs for 2008; the anticipated
impact that certain factors such as natural gas and oil prices, foreign
exchange and operating costs have on the Trust's cash from operating
activities and net income; and the expected impact of any current and future
environmental legislation or changes to the Crown royalties regime. You are
cautioned not to place undue reliance on forward-looking statements, as there
can be no assurance that the plans, intentions or expectations upon which they
are based will occur. By their nature, forward-looking statements involve
numerous assumptions, known and unknown risks and uncertainties, both general
and specific, that contribute to the possibility that the predictions,
forecasts, projections and other forward-looking statements will not occur.
Although the Trust believes that the expectations represented by such forward-
looking statements are reasonable, there can be no assurance that such
expectations will prove to be correct. Some of the risks and other factors
which could cause results to differ materially from those expressed in the
forward-looking statements contained in this MD&A include, but are not limited
to: the impacts of regulatory changes especially as such relate to royalties,
taxation, and environmental charges; the impact of technology on operations
and processes and how new complex technology may not perform as expected,
labour shortages and the productivity achieved from labour in the Fort
McMurray area, the supply and demand metrics for oil and natural gas, the
impact that pipeline capacity and refinery demand have on prices for our
products, the variances of stock market activities generally, normal risks
associated with litigation, general economic, business and market conditions,
regulatory changes, and such other risks and uncertainties described from time
to time in the reports and filings made with securities regulatory authorities
by the Trust. You are cautioned that the foregoing list of important factors
is not exhaustive. No assurance can be given that the final legislation
implementing the federal tax changes regarding income trusts will not be
further changed in a manner which adversely affects the Trust and its
Unitholders. To the extent that changes, including the Bill C-52 tax changes,
are implemented, such changes could result in the income tax considerations
described in this MD&A being materially different in certain respects.
Furthermore, the forward-looking statements contained in this MD&A are made as
of the date of this MD&A, and unless required by law, the Trust does not
undertake any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise. The forward-looking statements contained in this MD&A are
expressly qualified by this cautionary statement.

    REVIEW OF SYNCRUDE OPERATIONS

    During the fourth quarter of 2007, crude oil production from the Syncrude
Joint Venture ("Syncrude") totalled 28.8 million barrels, or an average of
about 313,000 barrels per day, compared with 27.8 million barrels, or
approximately 302,700 barrels per day, during the same period of 2006. Net to
the Trust, production totalled 10.6 million barrels in the fourth quarter of
2007 based on our 36.74 per cent working interest compared with 9.9 million
barrels in 2006 based on a 35.49 percent interest.
    Fourth quarter production in both 2007 and 2006 reflected incremental
volumes from the expanded Stage 3 facilities; however, volumes in the 2007
period were reduced by Coker 8-3 outages. The first disruption suspended
production from the coker for approximately one week at the beginning of the
quarter and the second disruption occurred in early December following a fire
in the environmental section of Coker 8-3. There were no injuries as a result
of the fire but the electro-static precipitators ("ESP"), which remove fine
dust particles from the coker flue gas, were damaged. Following repairs to
certain of the ESPs, operation of Coker 8-3 resumed in mid-December. The
preliminary cost estimate of the damage is $50 million ($18 million net to the
Trust). However, Syncrude continues to perform a fulsome analysis of the
necessary repair costs, which may change our current estimate. Canadian Oil
Sands will provide an update on the costs following Syncrude's review, should
they differ materially from our current estimation. Canadian Oil Sands has
property insurance with a $50 million deductible, which applies at the
Syncrude level. The two operational incidents involving Coker 8-3 were
unrelated events. In comparison, fourth quarter 2006 volumes were reduced by
unplanned maintenance late in the quarter on Coker 8-2.
    Canadian Oil Sands' operating costs were $27.38 per barrel in the fourth
quarter of 2007, up $3.78 per barrel from the same quarter last year (see the
"Operating costs" section of this MD&A for further discussion).
    Syncrude's annual production in 2007 totaled 111.3 million barrels, or
approximately 305,000 barrels per day, compared with 94.3 million barrels, or
about 258,400 barrels per day, during 2006. Net to the Trust, production
totalled 40.9 million barrels in 2007 based on our 36.74 per cent working
interest compared with 33.5 million barrels in 2006 based on a 35.49 per cent
interest. Production in 2007 exceeded the original budget estimate of 110
million barrels Canadian Oil Sands provided on December 7, 2006. The Trust
revised its estimate for annual Syncrude production to 111 million barrels on
October 31, 2007 to reflect better than anticipated operational reliability
during the first nine months of the year.
    The increase in year-over-year volumes primarily reflects Stage 3 volumes
along with a higher working interest in 2007. Aside from a brief initial
startup in May 2006, Stage 3 production commenced at the end of August 2006,
thereby contributing volumes for only the last four months of the 2006 year.
In comparison, the 2007 year benefited more from Stage 3 production with the
new facilities operating throughout the year, partially offset by Coker 8-3
constrained production rates and downtime. Production in 2007 was further
reduced by unplanned maintenance on Coker 8-2 during the first quarter and
planned maintenance on other units, including a turnaround of the LC-Finer.
Production in 2006 was reduced by an extensive maintenance program, including
an extended turnaround of Coker 8-1.
    Operating costs during 2007 averaged $25.23 per barrel, down $1.84 a
barrel from 2006, largely as a result of less turnaround and maintenance
activity and more production in 2007 relative to 2006 (discussed more fully in
the "Operating costs" section of this MD&A).
    Syncrude's entire production volumes during the fourth quarter of 2007
reflect the higher quality Syncrude(TM) Sweet Premium ("SSP") blend, a
transition that occurred in the third quarter of 2007. The transition occurred
earlier than the revised 2008 timeframe as Syncrude was able to access the
required hydrogen capacity by identifying and removing hydrogen constraints on
various units. Syncrude still plans to perform repairs to the new hydrogen
plant in 2008 in order to secure additional hydrogen feedstock to enable the
continued production of SSP at design capacity rates.
    Commencing in the 2007 third quarter report, we started using the term
"synthetic crude oil", or "SCO", to refer to Syncrude's production and our
sales volumes in the current and prior periods in lieu of the terms SSB and
SSP.
    Syncrude's facilities have the design capability to produce approximately
375,000 barrels per day when operating at full capacity under optimal
conditions and with no downtime for maintenance or turnarounds. This daily
production capacity is referred to as "barrels per stream day". However, under
normal operating conditions, scheduled downtime is required for maintenance
and turnaround activities and unscheduled downtime will occur as a result of
operational and mechanical problems, unanticipated repairs and other
slowdowns. When allowances for such downtime are included, the daily design
productive capacity of Syncrude's post-Stage 3 facilities is approximately
350,000 barrels per day on average and is referred to as "barrels per calendar
day". Syncrude is still lining out the Stage 3 facilities, and therefore is
not producing at design rates on a consistent basis. All references to
Syncrude's productive capacity in this report refer to barrels per calendar
day, unless stated otherwise.
    The Trust's production volumes differ from its sales volumes due to
changes in inventory, which are primarily in-transit pipeline volumes. These
in-transit volumes vary with current production. The growth in production from
the Stage 3 facilities also has required Canadian Oil Sands to access more
distant markets on additional pipelines to sell its volumes, which generally
increases pipeline inventory volumes. The impact of Syncrude's 2007 operations
on Canadian Oil Sands' financial results is more fully discussed later in this
MD&A.

    
    SUMMARY OF QUARTERLY RESULTS

    ($ millions, except per Trust Unit                  2007
     and volume amounts)                  Q4        Q3        Q2        Q1
    -------------------------------------------------------------------------
    Revenues(1)                       $    950  $    936  $    690  $    674

    Net income (loss)                 $    515  $    361  $   (395) $    262
      Per Trust Unit, Basic(2)        $   1.07  $   0.75  $  (0.82) $   0.55
      Per Trust Unit, Diluted(2)      $   1.07  $   0.75  $  (0.82) $   0.55

    Cash from operating activities    $    367  $    484  $    324  $    202
      Per Trust Unit(2)               $   0.77  $   1.01  $   0.68  $   0.42

    Unitholder distributions          $    264  $    192  $    191  $    144
      Per Trust Unit(2)               $   0.55  $   0.40  $   0.40  $   0.30

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

    Net realized selling
     price ($/bbl)(3)                 $  88.73  $  81.48  $  76.81  $  68.69

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

    Purchased natural gas
     price ($/GJ)                     $   5.84  $   4.99  $   6.78  $   6.99

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

    Foreign exchange rates
     (US$/Cdn$):
      Average                         $   1.02  $   0.96  $   0.91  $   0.85
      Quarter-end                     $   1.01  $   1.00  $   0.94  $   0.87


    ($ millions, except per Trust Unit                  2006
     and volume amounts)                  Q4        Q3        Q2        Q1
    -------------------------------------------------------------------------
    Revenues(1)                       $    646  $    689  $    624  $    473

    Net income (loss)                 $    128  $    278  $    337  $     91
      Per Trust Unit, Basic(2)        $   0.27  $   0.60  $   0.72  $   0.20
      Per Trust Unit, Diluted(2)      $   0.27  $   0.59  $   0.72  $   0.20

    Cash from operating activities    $    412  $    334  $    209  $    187
      Per Trust Unit(2)               $   0.88  $   0.72  $   0.45  $   0.40

    Unitholder distributions          $    140  $    140  $    139  $     93
      Per Trust Unit(2)               $   0.30  $   0.30  $   0.30  $   0.20

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

    Net realized selling
     price ($/bbl)(3)                 $  63.71  $  78.43  $  79.35  $  70.24

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

    Purchased natural gas
     price ($/GJ)                     $   6.51  $   5.42  $   5.72  $   7.42

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

    Foreign exchange rates
     (US$/Cdn$):
      Average                         $   0.88  $   0.89  $   0.89  $   0.87
      Quarter-end                     $   0.86  $   0.90  $   0.90  $   0.86


    (1) Revenues after crude oil purchases and transportation expense.
    (2) Trust Unit information has been adjusted to reflect the 5:1 Unit
        split that occurred on May 3, 2006.
    (3) Net realized selling price after foreign currency hedging.
    (4) Pricing obtained from Bloomberg.
    -------------------------------------------------------------------------


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

    -  The substantive enactment in June 2007 of Bill C-52 Budget
       Implementation Act, 2007 ("Bill C-52" or "trust taxation") resulted in
       the recording of a future income tax expense of $665 million in the
       second quarter of 2007. Canadian Oil Sands is now required to record
       future income tax related to temporary differences at the Trust level,
       which represent the differences between the accounting and tax basis
       of the Trust's net assets. In addition to the Bill C-52 impact,
       corporate tax rate reductions enacted in the second and fourth
       quarters of 2007 and in the second quarter of 2006 resulted in future
       income tax recoveries and accordingly increased net income by $38
       million, $153 million and $29 million in each quarter, respectively.
       Future income tax is a non-cash item that has no current impact on the
       Trust's cash from operating activities.
    -  Syncrude's Stage 3 expansion came on-line at the end of August 2006,
       increasing Syncrude's productive capacity by about 100,000 barrels per
       day with a corresponding pro-rata impact on the Trust's revenues,
       operating costs, and depletion, depreciation and accretion ("DD&A")
       expense.
    -  During the second quarter of 2006, Crown royalties shifted to the
       higher rate of 25 per cent of net revenue, compared to the one per
       cent of gross revenue that had applied since January 1, 2002,
       increasing Crown royalties expense and somewhat offsetting the revenue
       increase impact on net income and cash from operating activities in
       the latter half of 2006 and all of 2007. As the transition occurred in
       May 2006, Crown royalties in the second quarter of 2006 did not
       reflect the full impact of the rate change.
    -  Starting in 2007, the Trust's financial results reflect a 36.74 per
       cent working interest in Syncrude, which represents its increased
       ownership following the acquisition of Talisman Energy Inc.'s
       ("Talisman") 1.25 per cent working interest on January 2, 2007. Prior
       year comparative information is based on the Trust's previous
       ownership of 35.49 per cent.
    -  During 2007, the Canadian dollar strengthened considerably relative to
       the U.S. dollar, which resulted in significant unrealized foreign
       exchange gains on the revaluation of our U.S. dollar denominated debt
       and related interest payable. The unrealized foreign exchange gains
       related to our long-term debt are non-cash and therefore only impact
       net income.
    -  In the last six months, and in particular the last quarter of 2007,
       U.S. dollar West Texas Intermediate ("WTI") prices, which our sales
       are priced relative to, have increased significantly and reached
       record highs in the quarter. The significant increase in this
       benchmark pricing has boosted our revenues; however, the revenue
       increase has been mitigated somewhat as a result of the strengthening
       Canadian dollar relative to the U.S. dollar.
    

    Quarterly variances in revenues, net income, and cash from operating
activities are caused mainly by fluctuations in crude oil prices, production
and sales volumes, operating costs and natural gas prices. Net income is also
impacted by non-cash foreign exchange gains and losses caused by fluctuations
in foreign exchange rates on our U.S. dollar denominated debt and by future
income tax changes. A large proportion of operating costs are fixed and, as
such, unit operating costs are highly variable to production volumes. While
the supply/demand balance for crude oil affects selling prices, the impact of
this equation is difficult to predict and quantify and has not displayed
significant seasonality. Maintenance and turnaround activities are typically
scheduled to occur in the first or second quarter. However, the exact timing
of unit shutdowns cannot be precisely scheduled, and unplanned outages will
occur. As a result, production levels also may not display reliable
seasonality patterns or trends. Maintenance and turnaround costs are expensed
in the period incurred and can lead to significant increases in operating
costs and reductions in production in those periods, as demonstrated by the
particularly high per barrel operating costs in the second quarter of 2007 and
first quarter of 2006. Natural gas prices are typically higher in winter
months as heating demand rises, but this seasonality is significantly
influenced by weather conditions and North American natural gas inventory
levels.

    REVIEW OF FINANCIAL RESULTS

    In the fourth quarter of 2007, net income of $515 million, or $1.07 per
Trust unit ("Unit"), exceeded net income of $128 million, or $0.27 per Unit,
recorded in the comparable quarter in 2006, primarily as a result of higher
revenues, foreign exchange gains compared to losses in 2006, and a future
income tax recovery rather than an expense in 2006, offset somewhat by an
increase in operating costs, Crown royalties, and DD&A expenses. Revenues
(after crude oil purchases and transportation expense) totalled $950 million,
an increase of $304 million, in the fourth quarter of 2007 relative to 2006.
This significant increase was substantially attributable to a $25 per barrel
increase in our net realized selling price with a modest contribution from
increased sales volumes quarter-over-quarter. In the fourth quarter of 2007,
the Trust recorded a foreign exchange gain of $5 million compared with a loss
of $40 million in the same quarter of 2006, primarily related to unrealized
foreign exchange gains on the translation of U.S. dollar denominated long-term
debt. Also in the fourth quarter of 2007, future income taxes resulted in a
$157 million increase to net income quarter-over-quarter, primarily reflecting
the revaluation of future tax balances from a 3.5 per cent decrease in federal
corporate tax rates substantively enacted in the fourth quarter of 2007.
    The positive revenue, foreign exchange and future income tax impacts in
the fourth quarter of 2007 were somewhat offset by higher operating costs,
which increased to $293 million from $239 million in the last quarter of 2006.
On a per barrel basis, operating costs in the fourth quarter of 2007 increased
by $3.78 to average $27.38 compared to the same quarter of 2006. Crown
royalties also increased by $54 million quarter-over-quarter as a result of
the increase in net revenues. DD&A expense rose by $16 million
quarter-over-quarter, mainly reflecting a higher depreciation and depletion
rate.
    Cash from operating activities decreased by $45 million
quarter-over-quarter and totalled $367 million in the fourth quarter of 2007;
however, this decrease was driven by a $258 million increase in operating
working capital requirements, as shown in the table below. Excluding the
non-cash increases to unrealized foreign exchange gains, DD&A expense and
future income tax recoveries, cash from operating activities was affected by
the same variables as net income, as described above.

    
                             Three Months Ended        Twelve Months Ended
                                 December 31               December 31
                           2007     2006  Variance    2007     2006  Variance
    -------------------------------------------------------------------------

    Cash from (used in)
     changes in:
      Accounts
       receivable        $  (37)  $   73   $ (110)  $ (135)  $  (47)  $  (88)
      Inventories           (22)       7      (29)     (18)       3      (21)
      Prepaid expenses        3        -        3        1       (4)       5
      Accounts payable
       and accrued
       liabilities          (82)      39     (121)     (15)      23      (38)
      Less: A/P reclassed
       to investing and
       other                 (4)      (3)      (1)       2       47      (45)
    -------------------------------------------------------------------------
    Change in operating
     non-cash working
     capital             $ (142)  $  116   $ (258)  $ (165)  $   22   $ (187)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    The two most significant components of the $258 million operating working
capital increase quarter-over-quarter were a $110 million and $121 million
change in accounts receivable and accounts payable and accrued liabilities
("A/P"), respectively. Given the nature of the oil and gas industry whereby
accounts receivable from customers are typically settled in the following
month, working capital can fluctuate significantly resulting from volume and
price changes relative to each period end. Canadian Oil Sands' cash from
operating activities is also impacted by changes in its A/P balance, which can
reflect the timing of significant accruals and payments, such as Crown
royalties, operating costs, and interest payments on long-term debt.
    On a year-to-date basis in 2007, the Trust recorded net income of $743
million, or $1.55 per Unit, compared with net income of $834 million, or $1.79
per Unit, in 2006. Net income year-over-year was significantly reduced by the
$665 million future income tax expense recorded in the second quarter of 2007.
On an earnings before taxes basis, the Trust's results improved by $469
million year-over-year, primarily reflecting the net positive contributions of
the incremental Stage 3 volumes combined with robust crude oil prices, and
larger foreign exchange gains, partially offset by higher operating, Crown
royalties and DD&A expenses. Revenues (after crude oil purchases and
transportation expense) increased by $818 million and foreign exchange gains
increased by $112 million in 2007 relative to the prior year. The substantial
rise in revenues was attributable to both an increase in sales volumes and a
higher realized selling price, resulting in total revenues in 2007 of $3.3
billion. The larger foreign exchange gains are primarily attributable to an
increase in unrealized gains recorded on the revaluation of our U.S. dollar
denominated debt, reflecting the strengthening Canadian dollar relative to the
U.S. dollar. The 2007 revenue and foreign exchange gains increases were offset
somewhat by higher operating expenses of $127 million, Crown royalties of $253
million, and DD&A expense of $96 million year-over-year.
    Cash from operating activities increased 21 per cent in 2007 relative to
2006 and totalled $1,377 million, or $2.87 per Unit. Changes in non-cash
working capital decreased cash from operating activities by $187 million year-
over-year, with the main factors being changes in accounts receivable and A/P
balances. Relative to our October 31, 2007 guidance for 2007, actual cash from
operating activities was lower than expected by $49 million, or $0.11 per
Unit, and was impacted by the significant change in non-cash working capital
(guidance estimate of $nil), offset somewhat by higher actual revenues.
    The changes in revenues, operating expenses and Crown royalties also
impacted cash from operating activities, unlike the unrealized foreign
exchange gains, DD&A expense, and future income tax expense which are all non-
cash items.

    
                             Three Months Ended        Twelve Months Ended
                                 December 31               December 31
    ($ per bbl)            2007     2006  Variance    2007     2006  Variance
    -------------------------------------------------------------------------

    Net realized
     selling price        88.73    63.71    25.02    79.29    72.56     6.73
    Operating costs      (27.38)  (23.60)   (3.78)  (25.23)  (27.07)    1.84
    Crown royalties      (12.81)   (8.23)   (4.58)  (11.83)   (6.93)   (4.90)
    -------------------------------------------------------------------------
      Netback             48.54    31.88    16.66    42.23    38.56     3.67

    Non-production costs  (1.33)   (1.40)    0.07    (1.54)   (2.08)    0.54
    Administration and
     insurance            (0.76)   (0.39)   (0.37)   (0.69)   (0.65)   (0.04)
    Interest, net         (1.63)   (2.35)    0.72    (2.08)   (2.93)    0.85
    Depletion, depreciation
     and accretion        (8.47)   (7.39)   (1.08)   (8.56)   (7.61)   (0.95)
    Foreign exchange gain  0.53    (3.97)    4.50     2.86     0.16     2.70
    Future income tax
     recovery (expense)
     and other            11.00    (3.94)   14.94   (14.12)   (0.53)  (13.59)
    -------------------------------------------------------------------------
                          (0.66)  (19.44)   18.78   (24.13)  (13.64)  (10.49)
    -------------------------------------------------------------------------
    Net income per
     barrel               47.88    12.44    35.44    18.10    24.92    (6.82)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Sales volumes
     (MMbbls)              10.7     10.1      0.6     41.0     33.5      7.5
    -------------------------------------------------------------------------
    

    Non-GAAP Financial Measures

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

    
    Revenues after Crude Oil Purchases and Transportation Expense

                             Three Months Ended        Twelve Months Ended
                                 December 31               December 31
    ($ millions)           2007     2006  Variance    2007     2006  Variance
    -------------------------------------------------------------------------

    Sales revenue(1)    $ 1,004  $   734  $   270  $ 3,622  $ 2,672  $   950
    Crude oil purchases     (49)     (78)      29     (348)    (219)    (129)
    Transportation
     expense                 (8)     (12)       4      (35)     (41)       6
    -------------------------------------------------------------------------
                            947      644      303    3,239    2,412      827

    Currency hedging
     gains(1)                 3        2        1       11       20       (9)
    -------------------------------------------------------------------------
                        $   950  $   646  $   304  $ 3,250  $ 2,432  $   818
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Sales volumes
     (MMbbls)(2)           10.7     10.1      0.6     41.0     33.5      7.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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


    ($ per barrel)
    -------------------------------------------------------------------------

    Realized selling
     price before
     hedging(3)         $ 88.50  $ 63.47  $ 25.03  $ 79.02  $ 71.96  $  7.06
    Currency hedging
     gains                 0.23     0.24    (0.01)    0.27     0.60    (0.33)
    -------------------------------------------------------------------------
    Net realized
     selling price      $ 88.73  $ 63.71  $ 25.02  $ 79.29  $ 72.56  $  6.73
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

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

    
      -  An increase in demand for our SCO product in the fourth quarter of
         2007 from two major refineries, due to upgrading and refinery unit
         processing issues at those refineries; and
      -  An unusually deep discount in the fourth quarter of 2006 relative to
         other quarters, including the last quarter of 2007, reflecting
         increased supply in the market of light, sweet synthetics and lower
         demand for our product. We believe higher inventory levels at
         refineries, lower refinery margins and turnarounds by refiners all
         served to reduce demand in the last quarter of 2006.
    

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

    
                                                          Actual  Guidance(1)
    -------------------------------------------------------------------------

    Syncrude production (MMbbls)                              111        111
    West Texas Intermediate
     (average $US per barrel)                            $  72.36   $  70.00
    Premium (Discount) to average C$ WTI prices
     (C$/bbl)                                            $   1.63   $   1.50
    Average foreign exchange rates (US$/Cdn$):           $   0.93   $   0.94

    (1) As at October 31, 2007.
    


    The positive price differential in 2007 primarily reflected the
disconnect of the relationship between WTI and other benchmark light, sweet
crude oils during the second and third quarters of 2007. In addition to more
demand for our product in the third and fourth quarters of 2007 by certain
major refineries, a stronger differential relative to the prior year was
supported by reduced synthetic crude oil supply as a result of operational
issues and turnarounds experienced by various synthetic crude oil producers
during 2007, including Syncrude. By comparison, in 2006, primarily in the
first quarter, the discount from Canadian dollar WTI reflected reduced product
demand as a result of refinery outages, increased supply of light crude oil
resulting from a pipeline reconfiguration, and downward pressure on SCO prices
due to limited pipeline capacity to move crude oil to extended markets, in
addition to the factors which impacted the fourth quarter 2006 differential.
The shift in differentials from discounts to premiums can happen quickly
depending on the short-term supply/demand dynamics in the marketplace and
pipeline availability for transporting the crude oil.

    
    Operating costs
                          Three Months Ended         Twelve Months Ended
                              December 31                December 31
                          2007          2006          2007          2006
    -------------------------------------------------------------------------
                      $/bbl  $/bbl  $/bbl  $/bbl  $/bbl  $/bbl  $/bbl  $/bbl
                     Bitumen  SCO  Bitumen  SCO  Bitumen  SCO  Bitumen  SCO
    -------------------------------------------------------------------------

    Bitumen Costs(1)
      Overburden
       removal         2.14          1.65          1.82          2.09
      Bitumen
       production(2)   9.90          6.44          8.82          7.60
      Purchased
       energy(2,4)     2.33          2.22          2.19          2.64
    -------------------------------------------------------------------------
                      14.37  17.49  10.31  12.54  12.83  15.26  12.33  14.58
    -------------------------------------------------------------------------
    Upgrading Costs(3)
      Bitumen
       processing and
       upgrading(2)           3.63          4.74          4.35          4.78
      Turnaround and
       catalysts              0.45          0.47          1.05          2.20
      Purchased
       energy(4)              2.77          3.15          2.55          2.98
    -------------------------------------------------------------------------
                              6.85          8.36          7.95          9.96
    -------------------------------------------------------------------------
    Other and
     research(2)              2.54          2.29          1.43          1.92
    Change in treated
     and untreated
     inventory               (0.37)        (0.01)        (0.02)         0.25
    -------------------------------------------------------------------------
      Total Syncrude
       operating costs       26.51         23.18         24.62         26.71
    -------------------------------------------------------------------------
    Canadian Oil Sands
     adjustments(5)           0.87          0.42          0.61          0.36
    -------------------------------------------------------------------------
    Total operating
     costs                   27.38         23.60         25.23         27.07
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (thousands of
    barrels per day)  Bitumen  SCO  Bitumen  SCO  Bitumen  SCO  Bitumen  SCO
    -------------------------------------------------------------------------
    Syncrude
     production
     volumes            380    313    369    303    363    305    305    258
    -------------------------------------------------------------------------

    (1) Bitumen costs relate to the removal of overburden, oil sands mining,
        bitumen extraction and tailings dyke construction and disposal costs.
        The costs are expressed on a per barrel of bitumen production basis
        and converted to a per barrel of SCO based on the effective yield of
        SCO from the processing and upgrading of bitumen.
    (2) Prior year information has been restated for comparative purposes to
        conform to a revised presentation of costs between bitumen, upgrading
        and other and research starting in the second quarter of 2007.
    (3) Upgrading costs include the production and ongoing maintenance costs
        associated with processing and upgrading of bitumen to SCO. It also
        includes the costs of major refining equipment turnarounds and
        catalyst replacement, all of which are expensed as incurred.
    (4) Natural gas prices averaged $5.84/GJ and $6.51/GJ in the fourth
        quarters of 2007 and 2006, respectively. For the year, natural gas
        prices averaged $6.14/GJ and $6.26/GJ in 2007 and 2006, respectively.
    (5) Canadian Oil Sands' adjustments mainly pertain to Syncrude-related
        pension costs, opportunity assessment team costs and contract fees
        related to the Management Services Agreement between Syncrude Canada
        Ltd. and Imperial Oil Resources, property insurance costs, site
        restoration costs, as well as the inventory impact of moving from
        production to sales as Syncrude reports per barrel costs based on
        production volumes and we report based on sales volumes.


                           Three Months Ended         Twelve Months Ended
                               December 31                December 31
    ($/bbl of SCO)         2007          2006          2007          2006
    -------------------------------------------------------------------------

    Production costs         21.78         17.75         20.08         20.97
    Purchased energy          5.60          5.85          5.15          6.10
    -------------------------------------------------------------------------
      Total operating costs  27.38         23.60         25.23         27.07
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (GJs/bbl of SCO)
    -------------------------------------------------------------------------
    Purchased energy
     consumption              0.96          0.90          0.84          0.98
    -------------------------------------------------------------------------

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

      -  Additional waste and oil sand moved during the fourth quarter of
         2007. Syncrude supplemented its own material movement activities
         with contracted equipment and operators to increase exposed mineable
         ore and corresponding lead-time to meet operational needs and
         enhance operational flexibility.

      -  Inflation and retroactive adjustments for third party contract
         settlements with the building trades group related to prior years.
         The building trades group encompasses trades such as welders and
         electrical workers, which Syncrude uses for a significant amount of
         its work. Inflationary cost pressures, which have significantly
         impacted the entire upstream oil and gas industry in Alberta, are
         expected to continue to negatively impact Syncrude's (and other
         producers) material and labour costs in 2008.

      -  Various other factors, including an increased Syncrude workforce and
         additional maintenance costs from employing more equipment (Syncrude
         and contracted) and running the equipment at higher rates as a
         result of the additional Stage 3 processing capacity.
    

    On an annual basis, operating costs averaged $25.23 per barrel in 2007, a
reduction of $1.84 per barrel compared to 2006. Actual per barrel operating
costs were in-line with our October 31, 2007 annual 2007 guidance of $24.87.
While coker turnarounds occurred in both years, 2007 experienced less
turnaround and maintenance activity and more production relative to the prior
year, which reduced operating costs by $1.15 per barrel and is reflected in
the decrease in "Turnaround and catalysts" costs in the Operating Costs table.
    Purchased energy costs fell by almost $1 per barrel in 2007 relative to
2006 due to lower per barrel consumption volumes and slightly lower natural
gas prices. Energy consumption decreased by 14 per cent on a per barrel basis
in 2007, primarily due to improved operational efficiency. In part, such
improvements were because Stage 3 units were being commissioned during the
first nine months of 2006, increasing energy requirements without an
offsetting production increase as Stage 3 production did not commence until
September 2006.

    Non-production costs

    Non-production costs consist primarily of development expenditures
relating to capital programs, which are expensed, such as: commissioning
costs, pre-feasibility engineering, technical and support services, research
and development ("R&D"), and regulatory and stakeholder consultation
expenditures. Accordingly, non-production costs can vary depending on the
number of projects under way and the status of the projects. Non-production
costs totalled $14 million in each of the fourth quarters of 2007 and 2006.
However, on an annual basis, non-production costs totalled $63 million in
2007, a decrease of $7 million compared to 2006. More spending was incurred in
2007 related to R&D activities, such as drilling for further delineation of
current and new mines, as well as Canadian Oil Sands' larger working interest
ownership. However, non-production costs in the same period of 2006 included
$20 million of Stage 3 commissioning and start-up costs.

    Crown Royalties

    Under Alberta's current generic Oil Sands Royalty, the Crown royalty is
calculated as the greater of one per cent of gross plant gate revenue before
hedging, or 25 per cent of net revenues, calculated as gross plant gate
revenue before hedging, less allowed Syncrude operating, non-production and
capital costs. Crown royalties increased by $54 million to $137 million, or
$12.81 per barrel, in the fourth quarter of 2007 from $83 million, or $8.23
per barrel, in the comparable 2006 quarter. On an annual basis, Crown
royalties increased by $253 million to total $485 million, or $11.83 per
barrel in 2007, relative to the prior year, which reported $232 million, or
$6.93 per barrel. Compared with our most recent 2007 guidance, actual Crown
royalties exceeded our anticipated expense by $31 million, or $0.69 per
barrel, primarily as a result of higher actual revenues, as discussed earlier
in this MD&A. The increase in 2007 Crown royalties relative to 2006 reflects a
shift to the higher 25 per cent royalty rate, which occurred in the second
quarter of 2006, higher net revenues, and a larger Syncrude working interest.
The shift to the higher Crown royalty rate is triggered once a project reaches
payout by recovering its costs and a return allowance equal to a Government of
Canada long-term bond rate. See the "Crown Royalty Changes" section of this
MD&A for more information.

    
    Interest, Net
                                   Three Months Ended    Twelve Months Ended
                                       December 31           December 31
                                     2007       2006       2007       2006
    -------------------------------------------------------------------------

    Interest expense on
     long-term debt                 $    20   $     25   $     91   $    102
    Interest income and other            (3)        (1)        (6)        (4)
    -------------------------------------------------------------------------
      Interest expense, net         $    17   $     24   $     85   $     98
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    Depreciation, depletion and accretion expense

                                   Three Months Ended    Twelve Months Ended
                                       December 31           December 31
    ($ millions)                     2007       2006       2007       2006
    -------------------------------------------------------------------------

    Depreciation and depletion
     expense                        $    88    $    73    $   340    $   246
    Accretion expense                     3          2         11          9
    -------------------------------------------------------------------------
                                    $    91    $    75    $   351    $   255
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    

    Depreciation and depletion ("D&D") expense for the fourth quarter and
year-ended 2007 rose by $15 million and $94 million, respectively, compared to
the same periods of 2006, reflecting a higher per barrel D&D rate and an
increase in production volumes. In 2007 our D&D rate increased by about $1 per
barrel from the prior year to approximately $8.30 per barrel. The increase
reflects the additional assets and reserves acquired in the January
acquisition of an additional 1.25 per cent Syncrude working interest, as well
as the updated reserve and higher future development cost estimates provided
for in the Trust's December 31, 2006 independent reserves report, which
reflect a higher cost environment relative to the prior year.
    The Trust's December 31, 2006 reserve report is summarized in our 2006
Annual Information Form and can be found at www.sedar.com, or on our website
at www.cos-trust.com under "investor information".
    We anticipate the Trust's D&D rate will increase to approximately $11 per
barrel in 2008, based on preliminary 2007 reserve report estimates, which
include updated reserve and future development cost figures. While the Trust
does not expect any material revisions to our reserve figures in our December
31, 2007 reserve report, future development costs have continued to increase,
mainly as a result of higher projected sustaining capital expenditures,
consistent with recent experience. We expect to provide our updated 2008 D&D
rate in our first quarter 2008 MD&A.
    The Trust recorded a $37 million increase to its asset retirement
obligation ("ARO") liability and corresponding asset at December 31, 2007,
which primarily reflects the Trust's share of increased cost estimates to
comply with new material handling requirements under the Alberta Environmental
Protection and Enhancement Act Approval. The new requirements resulted in
higher cost estimates for soil salvage, soil placement thickness and soil
layering. The increased ARO liability is expected to marginally increase total
accretion expense to $14 million in 2008 from 2007 levels of $11 million.

    
    Foreign exchange loss (gain)

                                   Three Months Ended    Twelve Months Ended
                                       December 31           December 31
    ($ millions)                     2007       2006       2007       2006
    -------------------------------------------------------------------------

    Unrealized foreign exchange
     loss (gain)                   $     (7)  $     47   $   (153)  $     (1)
    Realized foreign exchange loss
     (gain)                               2         (7)        36         (4)
    -------------------------------------------------------------------------
      Total foreign exchange loss
       (gain)                      $     (5)  $     40   $   (117)  $     (5)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Foreign exchange rates as at:
    ($US/$Cdn)                                  2007       2006       2005
    -------------------------------------------------------------------------
    December 31                               $   1.01   $   0.86   $   0.86
    September 30                              $   1.00   $   0.90
    June 30                                   $   0.94   $   0.90
    March 31                                  $   0.87   $   0.86

    

    Foreign exchange ("FX") gains/losses are primarily the result of
revaluations of our U.S. dollar denominated long-term debt caused by
fluctuations in U.S. and Canadian dollar exchange rates. The resulting
unrealized FX gains/losses impact net income but do not affect cash from
operating activities as they are non-cash items. Other FX gains/losses are
created through the revaluation of cash, accounts receivable and A/P balances
denominated in U.S. dollars, which impact both net income and cash from
operating activities as these gains/losses are considered realized. Realized
FX gains/losses also result from repayment of U.S. dollar denominated
balances, such as long-term debt, in which case the resulting FX impacts are
included in financing activities on the Trust's Consolidated Statement of Cash
Flows.
    In the fourth quarter of 2007, Canadian Oil Sands' total FX gains mainly
related to the revaluation of our U.S. dollar denominated debt. The debt
revaluation in the fourth quarter of 2007 resulted in an unrealized FX gain of
$7 million, reflecting continued strengthening of the Canadian dollar on
December 31, 2007 from September 30, 2007. By comparison, the value of the
Canadian dollar relative to the U.S. dollar weakened on December 31, 2006
compared with September 30, 2006, resulting in an unrealized FX loss of $47
million in the fourth quarter of 2006.
    On an annual basis, total FX gains increased by $112 million in 2007
relative to 2006. Unrealized foreign exchange gains resulting from debt
revaluations accounted for $153 million and $1 million of the total FX gains
in each of 2007 and 2006, respectively, reflecting a stronger Canadian dollar
at the end of each year relative to the prior year December 31 rate. Also
included in the year ended December 31, 2007 was an FX gain of $18 million
realized upon repayment of US$70 million of Senior Notes in May 2007. The debt
was originally issued in 1997 when the FX rate was $0.73 US/Cdn and was repaid
in 2007 when the Canadian dollar had strengthened considerably to $0.91
US/Cdn. Excluding the realized gains on debt repayment, the significant
strengthening of the Canadian dollar in 2007 resulted in a realized loss of
$54 million, compared to a $4 million gain in the same period of 2006,
primarily attributable to U.S. dollar denominated accounts receivable and cash
balances.

    Future Income Tax and other

    Canadian Oil Sands' future income taxes on its Consolidated Balance Sheet
represent the net difference between tax values and accounting values,
referred to as temporary differences, tax-effected at substantively enacted
tax rates expected to apply when the differences reverse. A $118 million
future income tax recovery was recorded in the fourth quarter of 2007 and was
primarily the result of corporate tax rate reductions, partially offset by
increases in our taxable temporary differences. In December 2007, the federal
government substantively enacted tax rate reductions, which lowered the
corporate tax rates for the years 2008 to 2012 and beyond. The corporate tax
rates were reduced from 20.5 per cent in 2008 to an ultimate rate of 15 per
cent in 2012 and future years. These rate reductions also lower the trust
taxation rate from 31.5 per cent, as enacted by the federal government in the
second quarter of 2007 for years commencing in 2011, to 29.5 per cent and 28
per cent in 2011 and 2012 (and future years), respectively. As a result of
these rate changes, Canadian Oil Sands recorded a future income tax recovery
of $153 million in the fourth quarter of 2007. Somewhat offsetting this large
future income tax recovery in the fourth quarter of 2007 was a $35 million
future income tax expense, primarily attributable to having increased Canadian
Oil Sands' taxable temporary differences by utilizing more tax pools to
shelter current quarter taxable income compared to deductions taken for
accounting purposes. Conversely in the same quarter of 2006, the Trust
recorded a future income tax expense of $39 million, which was comprised of
$16 million expense related to changes in temporary differences and a $23
million expense adjustment pertaining to tax rates applied to certain
temporary differences.
    In addition to the fourth quarter net recovery amount, the Trust's annual
2007 future income tax and other expense of $579 million includes an
additional $701 million future income tax expense and corresponding future
income tax liability related to the Trust's temporary differences, reflecting
the substantive enactment of Bill C-52 in June 2007. Prior to this
legislation, which introduces a new tax on distributions from Canadian public
trusts starting in 2011, Canadian Oil Sands' future income taxes reflected
only those temporary differences in the Trust's subsidiaries. While net income
in 2007 was reduced significantly by this future tax adjustment, there was no
impact on cash from operating activities. This significant expense was
partially offset by a future income tax recovery of approximately $40 million
recorded in the second quarter of 2007 at the subsidiary level relating to the
federal tax rate reduction from 19 per cent to 18.5 per cent in 2011. The
remaining $34 million of future income tax and other expense recorded in 2007
primarily relates to changes to taxable temporary differences. In the prior
year, the Trust recorded an $18 million future income tax expense, which was
comprised of a $29 million future income tax recovery related to substantively
enacted reductions to future federal and provincial tax rates and the
elimination of the federal surtax, offset by an expense of $47 million related
to changes in temporary differences.
    In response to the income trust tax changes, Canadian Oil Sands continues
to evaluate alternatives as to the best structure for its Unitholders in the
future. In Alberta where the Trust is registered, a corporation is subject to
a lower overall tax rate than the rate that will apply to income trusts post-
2010. The federal government has confirmed that it intends to allow corporate
conversions to occur on a tax-deferred basis, so given current conditions, we
will most likely convert to a corporate structure. However, the rules of
transitioning to a corporate structure have yet to be established. Until 2011,
the Trust plans to retain the flow-through advantages of its trust structure,
unless circumstances arise that favour a faster transition to an alternate
structure. Canadian Oil Sands continues to be a long-term value investment in
the oil sands and does not rely on the tax efficiency of a flow-through trust
model to sustain our business. Our long-life reserves and non-declining
production profile provide a solid foundation to generate cash from operating
activities.
    In the first quarter of 2007, Canadian Oil Sands recorded an additional
future income tax liability on its Consolidated Balance Sheet totalling $327
million, with a corresponding increase to property, plant and equipment, as a
result of the 1.25 per cent Syncrude working interest acquisition on January 2
and the subsequent dissolution of the partnership in which the working
interest was held. The future income tax liability represents the temporary
differences between the book values of the net assets and the related tax
pools acquired.

    CHANGE IN ACCOUNTING POLICIES

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

    
    LIQUIDITY AND CAPITAL RE

SOURCES December 31 ($ millions) 2007 2006 ------------------------------------------------------------------------- Long-term debt $ 1,218 $ 1,644 Cash and cash equivalents (268) (353) ------------------------------------------------------------------------- Net debt $ 950 $ 1,291 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Unitholders' equity $ 4,172 $ 3,956 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total capitalization(1) $ 5,122 $ 5,247 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net debt plus Unitholders' equity Net debt to total capitalization (%) 19 25 ------------------------------------------------------------------------- In January 2007, Canadian Oil Sands paid $237.5 million in cash and issued 8.2 million Units valued at $237.5 million to Talisman as consideration for the purchase of Talisman's 1.25 per cent indirect Syncrude working interest. The acquisition was followed by the maturity of $195 million of medium term notes on January 15, 2007 and US$70 million of Senior Notes on May 15, 2007, resulting in debt repayments of $272 million in the first half of 2007. The debt repayments were financed by drawings on the Trust's $800 million operating credit facility, which were subsequently repaid. As discussed in Note 2 to the unaudited Consolidated Financial Statements, the Trust recorded a $16 million reduction to its long-term debt as a result of adopting the new financial instruments accounting standards. The reduction reflected the reclassification of deferred financing charges against long-term debt, which were previously recorded in other assets on the Trust's Consolidated Balance Sheet. Including an unrealized foreign exchange gain of $153 million, the Trust's long-term debt decreased by $426 million to $1.2 billion at December 31, 2007 and net debt dropped to $950 million. As at December 31, 2007, the Trust's unutilized credit facilities amounted to $808 million, net of letters of credit issued against its $40 million revolving term facility and an additional $45 million line of credit. The Trust has a $150 million medium term note maturing on April 9, 2008, which the Trust currently anticipates refinancing on maturity using its available credit facilities. In response to the income trust tax changes, Canadian Oil Sands adjusted its financial plan by raising its long-term net debt target to $1.6 billion by 2010 from $1.2 billion, which supports fuller payout of cash from operating activities and conserves tax pools. The Trust believes this net debt target maintains its strong balance sheet, allowing it to remain unhedged on crude oil production and providing the capacity to fund growth opportunities. The Trust's actual net debt will fluctuate around this level as factors such as crude oil prices, FX rates, Syncrude operational performance, and the timing of distribution changes vary from our assumptions. The Units issued from treasury in January 2007 to partially fund the additional Syncrude working interest acquisition increased Unitholders' equity. However, as the Units were issued directly to Talisman, there was no cash impact. The investing section of the Trust's cash flow statement, therefore, only reflects the cash paid to Talisman for the additional working interest less cash balances acquired. Unitholders' equity was increased by net income of $743 million, but reduced by distributions of $791 million recorded on a year-to-date basis. UNITHOLDER DISTRIBUTIONS Three Months Ended Twelve Months Ended December 31 December 31 ($ millions) 2007 2006 2007 2006 ------------------------------------------------------------------------- Cash from operating activities $ 367 $ 412 $ 1,377 $ 1,142 Net income $ 515 $ 128 $ 743 $ 834 Unitholder distributions $ 264 $ 140 $ 791 $ 512 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Excess (shortfall) of cash from operating activities over Unitholder distributions(1) $ 103 $ 272 $ 586 $ 630 Excess (shortfall) of net income over Unitholder distributions(2) $ 251 $ (12) $ (48) $ 322 (1) Cash from operating activities less Unitholder distributions. (2) Net income less Unitholder distributions. ------------------------------------------------------------------------- Cash from operating activities and net income can fluctuate dramatically from period to period, reflecting variability in operational performance, WTI prices, SCO differentials and FX rates. Given these risks, we strive to smooth out the variability of distributions by taking a longer-term view in the context of our outlook for our operating and business environment, including monitoring of our net debt relative to our target and assessing our capital expenditure commitments. In that regard, we may distribute more or less in a period than we generate in cash from operating activities or net income. The distribution depends on numerous factors including our financial and operational performance, working capital requirements and future capital expenditures. Despite management's goal to strive for relative distribution stability, the highly variable nature of these considerations introduces risk in our ability to sustain or stabilize distributions. Therefore, unwarranted expectations in the stability or sustainment of distributions should not be implied. In addition, the taxation of income trusts commencing January 1, 2011 likely will materially alter our cash from operating activities and consequently distribution levels. A Unitholder distributions schedule pertaining to the quarter ended December 31 is included in Note 12 to the unaudited Consolidated Financial Statements. The Trust uses debt and equity financing to the extent that cash from operating activities is insufficient to fund distributions, capital expenditures, reclamation trust contributions, acquisitions and working capital changes from financing and investing activities. Cash from operating activities exceeded distributions by $103 million in the fourth quarter of 2007. This excess amount was sufficient to pay the Trust's capital expenditures and reclamation funding of $58 million. On a year-to-date basis, the $586 million excess of cash from operating activities over Unitholder distributions exceeded capital expenditures and reclamation funding totalling $190 million and debt repayments of $272 million. Capital expenditures are discussed more fully in the "Capital Expenditures" section of this MD&A. Net income also exceeded distributions in the fourth quarter of 2007. However, on an annual basis, distributions exceeded net income in 2007 as a result of the $701 million future income tax expense recorded in the second quarter related to the enactment of Bill C-52. The future income tax expense is a non-cash item that does not affect the Trust's cash from operating activities or its balance sheet strength and ability to pay distributions over the next several years. As a result, the Trust paid the distribution despite the lower net income. As indicated in previous disclosures, the Trust suspended its Premium Distribution, Distribution Reinvestment and Optional Unit Purchase Plan ("DRIP") and, as such, the DRIP did not provide additional equity financing in 2007. In determining the Trust's distributions, Canadian Oil Sands also considers funding for its significant operating obligations, which are included in cash from operating activities. Such obligations include the Trust's share of Syncrude's pension and reclamation funding, which amounted to approximately $38 million and $30 million in 2007 and 2006, respectively, and approximated the related expense for both pension and reclamation of $41 million and $42 million in each of the years, respectively. While our share of Syncrude's annual pension funding has increased modestly as a result of the most recent actuarial valuation and our share of Syncrude's future reclamation costs has also increased, we currently do not anticipate any material funding increases related to these items for at least the next few years. Debt covenants do not specifically limit the Trust's ability to pay distributions and are not expected to influence the Trust's liquidity in the foreseeable future. Aside from the typical covenants relating to restrictions on Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business, the most restrictive financial covenant limits total debt-to-book capitalization at an amount less than 55 per cent. With a current net debt-to-book capitalization of approximately 19 per cent, a significant increase in debt or decrease in equity would be required to negatively impact the Trust's financial flexibility. On January 30, 2008, the Trust declared a 36 per cent increase to its quarterly distribution to $0.75 per Unit for total distributions of $359 million. The distribution will be paid on February 29, 2008 to Unitholders of record on February 12, 2008. With the completion of the Stage 3 project, robust crude oil prices and our current net debt level relative to our long- term target, the Trust has more than doubled its quarterly distribution since the first quarter of 2007. The rise in the Trust's distribution levels is consistent with our previous indications that we would be moving to a fuller payout of cash from operating activities unless capital investment or acquisition opportunities exist that we believe offer Unitholders enhanced value. With Syncrude's existing productive capacity, we are targeting a long- term net debt level of about $1.6 billion by the end of 2010 and will reconsider this target in light of future Syncrude growth and other acquisition opportunities. Capital expenditures With the completion of Syncrude's Stage 3 project in 2006, Canadian Oil Sands' expansion capital expenditures have been reduced significantly and, as such, current capital costs are essentially all related to sustaining capital. The Trust defines expansion capital expenditures as the costs incurred to grow the productive capacity of the operation, such as the Stage 3 project, while sustaining capital is effectively all other capital and includes the costs required to maintain the current productive capacity of Syncrude's mines and upgraders. Sustaining capital may fluctuate considerably year-to-year due to timing of equipment replacement and other factors. The productive capacity of Syncrude's operations was defined previously in the "Review of Syncrude Operations" section of this MD&A. In the last quarter of 2007, capital expenditures totalled $55 million, comparable to expenditures of $57 million in the same quarter of 2006. The Syncrude Emissions Reduction ("SER") project accounted for $18 million and $13 million of the capital spent in the fourth quarters of 2007 and 2006, respectively, with the remaining amounts in each quarter pertaining to the maintenance of Syncrude's existing plant and facilities, all of which are considered sustaining capital. Sustaining capital expenditures on a per barrel basis were approximately $5.00 in each of the fourth quarters of 2007 and 2006. On a year-to-date basis, capital expenditures totalled $183 million in 2007, a decrease of $117 million compared to 2006, as a result of the Stage 3 completion in 2006. Actual capital expenditures were slightly lower than our anticipated spending of $199 million provided in our October 31, 2007 guidance for 2007, reflecting a deferral in actual spending for maintenance of business/other capital. In 2006, Stage 3 costs accounted for $121 million of the $300 million in total capital expenditures. Annual sustaining capital expenditures in 2007 were $4.46 per barrel compared with $5.01 per barrel recorded in the same period in 2006. Syncrude is undertaking the SER project to retrofit technology into the operation of Syncrude's original two cokers to significantly reduce total sulphur dioxide and other emissions. While expenditures on the SER project are currently estimated at approximately $772 million ($284 million net to the Trust based on its 36.74 per cent working interest), as previously disclosed, there are indications of upward cost pressure on the project. Syncrude is currently performing a full review of the project and will provide updates to cost estimates and timing after such review has been completed. The Trust's share of the SER project expenditures incurred to date is approximately $106 million, with the remaining costs to be incurred in the next three years to coordinate with equipment turnaround schedules. Our sustaining capital expenditures, including the SER project, are estimated at approximately $7 per barrel in 2008. The increase in projected 2008 sustaining capital costs relative to 2007 actual costs of $4.46 per barrel reflects an escalation in material and labour costs for most capital projects. Recent labour settlements in Alberta for construction workers will add to hourly wage rates and increase sustaining capital costs over the coming several years. As well, we expect the cost of construction materials, such as fabricated steel, electrical components and mechanical equipment to continue to rise. In addition to inflationary cost pressures that will continue to impact our longer-term average sustaining capital expenditures estimate of about $5 per barrel, we expect to incur costs for large environmental and infrastructure projects. These are projects that are required to support the on-going operation, but do not add to production volumes. In addition to the SER project, Syncrude expects to proceed with other environmental and infrastructure projects. These projects include the relocation of certain mining trains and tailings systems, which is required as mining operations progress across the active leases. Tailings system projects also include initiatives to improve and supplement the effectiveness of systems used to separate water from sand and clay so that the water can be recycled back to the operation and solids can be incorporated into the final reclamation landscapes. These infrastructure projects, including SER, are expected to add about $2 to $5 per barrel annually to sustaining capital expenditures over the next few years. Our per barrel estimates are based on estimated annual Syncrude production, which increases from 115 million barrels in 2008, or 42 million barrels net to the Trust, to 128 million barrels, or 47 million barrels net to the Trust, at design capacity. Syncrude's next significant growth stage is anticipated to be the Stage 3 debottleneck. We estimate the project will increase Syncrude productive capacity by 30,000 to 50,000 barrels per day. Based on the current business environment, this incremental production is expected to be achieved by 2012. Following the Stage 3 debottleneck, the Stage 4 expansion is planned to grow Syncrude capacity by a further 100,000 barrels per day, resulting in total productive capacity of approximately 500,000 barrels per day post-2016. Spending on each of these respective projects is expected to commence several years prior to the incremental production coming on-stream. The plans for these projects are preliminary and have not been approved by the Syncrude owners, and as such, may change. No cost estimates have been provided for either of these projects because they are still in the early planning stages. At the end of May 2007, Canadian Oil Sands completed the sale of the remaining conventional properties that it acquired in 2006 from Canadian Arctic Gas Ltd, formerly Canada Southern Petroleum Ltd. The conventional properties which the Trust owned up to May 31, 2007 did not generate material income in 2007 and is reflected in "Discontinued operations" on the Trust's Consolidated Statements of Income and Comprehensive Income. UNITHOLDERS' CAPITAL AND UNIT TRADING ACTIVITY The Trust's Units trade on the Toronto Stock Exchange under the symbol COS.UN. The Trust had a market capitalization of approximately $19 billion with 479 million Units outstanding and a closing price of $38.71 per Unit on December 31, 2007. Canadian Oil Sands Trust - Trading Activity Fourth Quarter December November October 2007 2007 2007 2007 ------------------------------------------------------------------------- Unit price High $ 38.88 $ 38.88 $ 38.45 $ 35.82 Low $ 30.70 $ 34.81 $ 33.57 $ 30.70 Close $ 38.71 $ 38.71 $ 36.24 $ 34.70 Volume traded (millions) 91.2 23.3 29.1 38.8 Weighted average Trust units outstanding (millions) 479 479 479 479 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CONTRACTUAL OBLIGATIONS AND COMMITMENTS The following table outlines the significant financial obligations that are known as of January 30, 2008, which represent future cash payments that the Trust is required to make under existing contractual agreements that it has entered into either directly, or as a 36.74 per cent owner in the Syncrude Joint Venture: Payments due by period less than After ($ millions) Total 1 year 1-3 years 4-5 years 5 years ------------------------------------------------------------------------- Long-term debt(1) 1,229 166 447 296 320 Capital expenditure commitments(2) 250 84 166 - - Pension plan solvency deficiency payments(3) 122 14 42 17 49 Management services agreement(4) 153 17 51 34 51 Pipeline commitments(5) 575 25 59 40 451 Other obligations(6) 288 166 81 9 32 ------------------------------------------------------------------------- 2,617 472 847 396 903 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Actual payments differ from the carrying value, which is stated at amortized cost. While there is approximately $150 million of debt maturing in 2008, Canadian Oil Sands' intention is to refinance such debt. (2) Capital expenditure commitments are primarily comprised of our 36.74 per cent share of Syncrude's Emissions Reduction project. (3) We are responsible for funding our 36.74 per cent share of Syncrude Canada's registered pension plan solvency deficiency, which was confirmed in the December 31, 2006 actuarial valuation that was completed in 2007. (4) Reflects our 36.74 per cent share of Syncrude Canada's annual fixed service fees under the agreement. (5) Reflects our 36.74 per cent share of the AOSPL pipeline commitment as a Syncrude Joint Venture owner, and various other Canadian Oil Sands pipeline commitments for transportation access beyond Edmonton. (6) These obligations primarily include our 36.74 per cent share of the minimum payments required under Syncrude's commitments for natural gas purchases and employee retention program. Other items include, but are not limited to, annual disposal fees for the flue gas desulphurization unit and capital and operating lease obligations. In total, the Trust's financial obligations have decreased by approximately $1.0 billion relative to the prior year-end. The two most significant changes are: (1) a reduction in long-term debt of $415 million, as discussed in the "Liquidity and Capital Resources" section of this MD&A, and (2) a $475 million payment, comprised of cash and Units, to Talisman on January 2, 2007 for the additional 1.25 per cent Syncrude working interest acquisition. Natural gas purchase commitments have also decreased by approximately $60 million, mainly reflecting timing of natural gas contract renewals. Syncrude's pension plan actuarial valuation for December 31, 2006 was completed in the second quarter of 2007, which confirmed an increase to our share of Syncrude's pension funding of approximately $5 million per year for the next five years. There have been no other significant changes to the Trust's contractual obligations and commitments in 2007 from our 2006 year-end disclosure, other than reductions to the capital expenditure and various payment obligation commitments as a result of expenditures incurred in the year. FINANCIAL RISK MANAGEMENT Crude Oil Price Risk As Canadian Oil Sands did not have any crude oil price hedges in 2007 and 2006, revenues were not impacted by crude oil hedging gains or losses and benefited fully from strong WTI prices. As at December 31, 2007 and, based on current expectations, the Trust remains unhedged on its crude oil price exposure. However, we may hedge our crude oil production in the future as part of our growth financing strategies. Foreign Currency Hedging As at December 31, 2007, we no longer had any foreign currency hedges in place. At the present time, we do not intend to increase our currency hedge positions. However, the Trust may hedge foreign exchange rates in the future, depending on the business environment and growth opportunities. Interest Rate Risk Canadian Oil Sands' net income and cash from operating activities are impacted by interest rate changes based on the amount of floating rate debt outstanding. On December 31, 2007, we drew $16 million on our credit facilities, which bear interest at a floating market-based rate. The year-end draw was repaid on January 2, 2008; therefore we had minimal interest rate exposure at year-end. The Trust's other floating rate debt was repaid in January 2007. With the adoption of the new financial instrument accounting rules, all of the Trust's financial risk management activities are now recorded on its Consolidated Balance Sheet at fair value. The Trust did not have any financial derivatives outstanding at December 31, 2007. FOREIGN OWNERSHIP Based on information from the statutory declarations by Unitholders, we estimate that, as of November 16, 2007, approximately 32 per cent of our Unitholders are non-Canadian residents with the remaining 68 per cent being Canadian residents. Canadian Oil Sands' Trust Indenture provides that not more than 49 per cent of its Units can be held by non-Canadian residents. The Trust regularly monitors its foreign ownership levels through declarations from Unitholders, and the next declarations will be requested as of February 12, 2008. The Trust posts its foreign ownership levels and describes its steps for managing these levels on its web site (www.cos- trust.com under "investor information", "frequently asked questions"). These steps are also described in the Trust's 2007 Annual Information Form. CROWN ROYALTY CHANGES The Alberta government has announced that it plans to introduce new Crown royalty terms, effective January 1, 2009, for the energy sector. The new royalty regime for oil sands projects is to be based on a sliding scale royalty rate ranging from one to nine per cent pre-payout and 25 to 40 per cent post-payout that responds to WTI price levels. The pre-payout rate is proposed to start at one per cent of revenue and increase for every dollar oil is priced above $55 per barrel, to a maximum of nine per cent of revenue when oil is priced at $120 per barrel or higher. The net royalty applied post- payout will start at 25 per cent of net revenue and increase for every dollar oil is priced above $55 per barrel up to a maximum of 40 per cent of net revenue when oil reaches $120 per barrel or higher. The Syncrude Joint Venture owners have a Crown Agreement with the Alberta government that codifies the current royalty terms of 25 per cent of net SCO revenues to December 31, 2015. The Agreement also provides Syncrude with the option to convert to a bitumen-based royalty, consistent with the rest of the industry, prior to 2010. Canadian Oil Sands, as one of the Syncrude owners, is currently in discussions with the Alberta government regarding both the conversion to a bitumen-based royalty and an equitable solution to offset Syncrude's transition to the higher generic royalty rate prior to 2016. Canadian Oil Sands is of the view that any transition to the new generic royalty terms must recognize and preserve our legal rights to the embedded value in Syncrude's contract with the government. GREENHOUSE GAS EMISSIONS REDUCTION REQUIREMENTS In 2007, the Alberta government introduced legislation ("Bill 3") to reduce greenhouse gas ("GHG") emission intensity. Bill 3 states that facilities emitting more than 100,000 tonnes of GHGs a year ("Large Emitters") must reduce their emissions intensity (emissions per unit of production) by 12 per cent over the average emissions intensity levels of 2003, 2004 and 2005; if they are unable to do so, these facilities will be required to pay $15 per tonne for every tonne above the 12 per cent target, beginning July 1, 2007. In the last six months of 2007, Syncrude has accrued approximately $0.19 per barrel for compliance with the Alberta government's Bill 3 legislation, which is reflected in the Trust's operating costs. The cost estimate remains preliminary pending Syncrude's actual C02 emission intensity level and clarification from the Alberta government regarding details of the Bill 3 implementation. No cost estimates are available yet for future years. The federal government also released new GHG and air pollutant emission reduction targets on April 27, 2007 in its Regulatory Framework for Air Emissions (the "Framework"). The Framework forms the basis for consultations, with draft regulations anticipated to be released in spring 2008. Until further detail is provided regarding the specifics of any new federal regulation, Canadian Oil Sands is unable to provide information on the potential impact. 2008 OUTLOOK Canadian Oil Sands Trust's Outlook for 2008 is similar to our Budget announced on December 14, 2007, other than an increase to operating expenses to reflect currently estimated repair costs of $50 million ($18 million, net to the Trust) for the ESPs damaged in the December fire. Other minor changes to the budget are a result of adjusting estimated December 31, 2007 amounts to actual. On January 29, 2008 production from the Syncrude facility was suspended following several instrument freeze-ups as a result of extremely cold weather conditions. Operation of a number of units was disrupted. Syncrude has advised that it is focusing efforts on the safe and reliable restart of affected units, and expects that it will take several days to fully restore operations. At this time, investigations are too preliminary to know the impact, if any, on our 2008 Outlook; accordingly, we have not adjusted our current Outlook for this operational incident. Annual 2008 Syncrude production is estimated to total 115 million barrels with a range of 110 to 120 million barrels (net to the Trust, equivalent to 42 million barrels with a range of 40 to 44 million barrels). The single point production estimate incorporates Syncrude's extensive 2008 maintenance program, an allowance for unplanned outages, and recognition that Syncrude is still working to establish reliable Stage 3 design rates. During 2008, Syncrude plans to perform turnarounds of Coker 8-1 (second quarter) and Coker 8-2 (third quarter) as well as associated maintenance work on other units. The production range reflects our current best estimate of the upside and downside in volumes Syncrude could experience, depending on operational reliability, in 2008. For the anticipated 2008 production target, purchased bitumen should not be required; however, Syncrude has decided to increase its flexibility in its SCO production by arranging for the purchase of incremental bitumen in 2008 when internal bitumen supply shortfalls may occur. During the year, productivity of the mining operations may be reduced due to maintenance or extreme weather conditions, resulting in temporary decreases of internally produced bitumen. This additional purchased bitumen supply will support increased production during times when excess upgrading capacity is available. Syncrude is focused on improving reliability in the mining operations to meet the rising needs of the upgrader as we ramp up production to design capacity rates. We currently estimate imported bitumen volumes in 2008 will be less than five per cent of total supply at Syncrude and, therefore we do not anticipate such purchases to have a material impact on Syncrude's production, and correspondingly, our financial results. We expect the Trust's revenues in 2008 to total $3.3 billion, based on an average WTI price of US$80 per barrel, an average foreign exchange rate of $1.00 US/Cdn, and an average SCO discount to Canadian dollar WTI of $2.50 per barrel. We are budgeting operating costs of $26.83 per barrel, which includes $6.48 per barrel for purchased energy based on an average AECO natural gas price of $7.00 per gigajoule for 2008. We anticipate Crown royalties expense to total $443 million, or $10.49 per barrel, in 2008. We anticipate our cash from operating activities to total $1.6 billion, or $3.24 per Unit. We are estimating our share of Syncrude's capital expenditures to total $279 million with approximately 82 per cent of the 2008 capital expenditures directed to maintenance of operations and the remaining 18 per cent to the SER project. Distributions paid in 2007 and 2008 are expected to be 99 per cent and 100 per cent taxable, respectively, as other income. The actual taxability of the distributions will be determined and reported to Unitholders prior to the end of the first quarters of 2008 and 2009, respectively. Changes in certain factors and market conditions could potentially impact Canadian Oil Sands' Outlook. The following table provides a sensitivity analysis of the key factors affecting the Trust's performance. In addition to the factors described in the table, the supply/demand equation and pipeline access for synthetic crude oil in the North American markets could impact the price differential for SCO relative to crude benchmarks; however, these factors are difficult to predict. 2008 Outlook Sensitivity Analysis Cash from Operating Activities Annual(2) Increase Variable(1) Sensitivity $ millions $/Trust unit ------------------------------------------------------------------------- Syncrude operating costs decrease C$1.00/bbl 32 0.07 Syncrude operating costs decrease C$50 million 14 0.03 WTI crude oil price increase US$1.00/bbl 29 0.06 Syncrude production increase 2 million bbls 39 0.08 Canadian dollar weakening US$0.01/C$ 23 0.05 AECO natural gas price decrease C$0.50/GJ 15 0.03 (1) An opposite change in each of these variables will result in the opposite cash from operating activities impacts. (2) Sensitivities assume a larger change in unrealized quarters to result in the annual impact. CANADIAN OIL SANDS TRUST CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (unaudited) Three Months Ended Twelve Months Ended ($ millions, except December 31 December 31 per Unit amounts) 2007 2006 2007 2006 ------------------------------------------------------------------------- Revenues $ 1,007 $ 736 $ 3,633 $ 2,692 Crude oil purchases and transportation expense (57) (90) (383) (260) ------------------------------------------------------------------------- 950 646 3,250 2,432 ------------------------------------------------------------------------- Expenses: Operating 293 239 1,034 907 Non-production 14 14 63 70 Crown royalties 137 83 485 232 Administration 6 5 20 17 Insurance 2 1 8 6 Interest, net (Note 11) 17 24 85 98 Depreciation, depletion and accretion 91 75 351 255 Foreign exchange loss (gain) (5) 40 (117) (5) ------------------------------------------------------------------------- 555 481 1,929 1,580 ------------------------------------------------------------------------- Earnings before taxes from continuing operations 395 165 1,321 852 ------------------------------------------------------------------------- Future income tax expense (recovery) and other (Note 10) (118) 39 579 17 ------------------------------------------------------------------------- Net income from continuing operations 513 126 742 835 Income (loss) from discontinued operations 2 2 1 (1) ------------------------------------------------------------------------- Net income 515 128 743 834 Other comprehensive loss, net of income taxes Reclassification of derivative gains to net income - - (6) - ------------------------------------------------------------------------- Comprehensive income $ 515 $ 128 $ 737 $ 834 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Weighted average Trust Units (millions) 479 469 479 466 Trust Units, end of period (millions) 479 471 479 471 Net income per Trust Unit(1): Basic $ 1.07 $ 0.27 $ 1.55 $ 1.79 Diluted $ 1.07 $ 0.27 $ 1.54 $ 1.78 (1) Discontinued operations did not have a material impact on basic or diluted net income per Trust Unit. CANADIAN OIL SANDS TRUST CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY (unaudited) Three Months Ended Twelve Months Ended December 31 December 31 ($ millions) 2007 2006 2007 2006 ------------------------------------------------------------------------- Retained earnings Balance, beginning of period, as previously reported $ 1,392 $ 1,704 $ 1,692 $ 1,370 Transition adjustment on adoption of Financial Instruments standards (Note 2) - - (1) - ------------------------------------------------------------------------- Balance, beginning of period, adjusted 1,392 1,704 1,691 1,370 Net income 515 128 743 834 Unitholder distributions (Note 12) (264) (140) (791) (512) ------------------------------------------------------------------------- Balance, end of period 1,643 1,692 1,643 1,692 ------------------------------------------------------------------------- Accumulated other comprehensive income Balance, beginning of period 24 - - - Transition adjustment on adoption of Financial Instruments standards (Note 2) - - 30 - Other comprehensive loss - - (6) - ------------------------------------------------------------------------- Balance, end of period 24 - 24 - ------------------------------------------------------------------------- Unitholders' capital Balance, beginning of period 2,499 2,190 2,260 2,010 Issuance of Trust Units (Note 5) 1 70 240 250 ------------------------------------------------------------------------- Balance, end of period 2,500 2,260 2,500 2,260 ------------------------------------------------------------------------- Contributed surplus Balance, beginning of period 5 3 4 3 Stock-based compensation - 1 1 1 ------------------------------------------------------------------------- Balance, end of period 5 4 5 4 ------------------------------------------------------------------------- Total Unitholders' equity $ 4,172 $ 3,956 $ 4,172 $ 3,956 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CANADIAN OIL SANDS TRUST CONSOLIDATED BALANCE SHEETS AS AT DECEMBER 31 (unaudited) ($ millions) 2007 2006 ------------------------------------------------------------------------- ASSETS Current assets: Cash and cash equivalents $ 268 $ 353 Accounts receivable 379 244 Inventories 102 84 Prepaid expenses 6 7 ------------------------------------------------------------------------- 755 688 ------------------------------------------------------------------------- Property, plant and equipment, net 6,427 5,739 ------------------------------------------------------------------------- Other assets Goodwill 52 52 Assets held for sale - 6 Reclamation trust 37 30 Deferred financing charges, net and other (Note 2) - 17 ------------------------------------------------------------------------- 89 105 ------------------------------------------------------------------------- $ 7,271 $ 6,532 ------------------------------------------------------------------------- ------------------------------------------------------------------------- LIABILITIES AND UNITHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $ 289 $ 304 Current portion of employee future benefits 16 11 ------------------------------------------------------------------------- 305 315 Employee future benefits and other liabilities 128 100 Long-term debt (Notes 2,8) 1,218 1,644 Asset retirement obligation (Note 9) 226 173 Deferred currency hedging gains (Note 2) - 35 Future income taxes (Note 10) 1,222 309 ------------------------------------------------------------------------- 3,099 2,576 Unitholders' equity 4,172 3,956 ------------------------------------------------------------------------- $ 7,271 $ 6,532 ------------------------------------------------------------------------- ------------------------------------------------------------------------- CANADIAN OIL SANDS TRUST CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) Three Months Ended Twelve Months Ended December 31 December 31 ($ millions) 2007 2006 2007 2006 ------------------------------------------------------------------------- Cash provided by (used in): Cash from (used in) operating activities Net income $ 515 $ 128 $ 743 $ 834 Items not requiring outlay of cash: Depreciation, depletion and accretion 91 75 351 255 Foreign exchange on long-term debt (7) 47 (153) (1) Future income tax expense (recovery) (118) 39 578 18 Other - 1 (3) 4 Net change in deferred items 28 6 26 10 ------------------------------------------------------------------------- Funds from operations 509 296 1,542 1,120 Change in non-cash working capital (142) 116 (165) 22 ------------------------------------------------------------------------- Cash from operating activities 367 412 1,377 1,142 ------------------------------------------------------------------------- Cash from (used in) financing activities Repayment of medium term and Senior Notes (Note 8) - - (272) - Net drawdown (repayment) of bank credit facilities 16 - 16 (92) Unitholder distributions (Note 12) (264) (140) (791) (512) Issuance of Trust Units (Note 5) 2 70 3 250 ------------------------------------------------------------------------- Cash used in financing activities (246) (70) (1,044) (354) ------------------------------------------------------------------------- Cash from (used in) investing activities Capital expenditures (55) (57) (183) (300) Acquisition of additional Syncrude working interest (Note 4) - - (231) - Acquisition of Canadian Arctic Gas Ltd. - (48) - (199) Disposition of properties - 28 4 28 Reclamation trust funding (3) (1) (7) (5) Change in non-cash working capital 4 3 (1) (47) ------------------------------------------------------------------------- Cash used in investing activities (54) (75) (418) (523) ------------------------------------------------------------------------- Increase (decrease) in cash and cash equivalents 67 267 (85) 265 Cash and cash equivalents at beginning of period 201 86 353 88 ------------------------------------------------------------------------- Cash and cash equivalents at end of period $ 268 $ 353 $ 268 $ 353 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Cash and cash equivalents consist of: Cash $ 4 $ 8 Short-term investments 264 345 ------------------------------------------------------------------------- $ 268 $ 353 ------------------------------------------------------------------------- NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE TWELVE MONTHS ENDED DECEMBER 31, 2007 (Tabular amounts expressed in millions of Canadian dollars, except where otherwise noted.) 1) BASIS OF PRESENTATION The interim consolidated financial statements include the accounts of Canadian Oil Sands Trust and its subsidiaries (collectively, the "Trust" or "Canadian Oil Sands"), and are presented in accordance with Canadian generally accepted accounting principles ("GAAP"). The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2006, except as discussed in Note 2. The disclosures provided below are incremental to those included with the annual consolidated financial statements. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in the Trust's annual report for the year ended December 31, 2006. 2) CHANGES IN ACCOUNTING POLICIES Effective January 1, 2007, Canadian Oil Sands adopted the requirements of the Canadian Institute of Chartered Accountants ("CICA") related to the new financial instruments accounting framework, which encompasses the following new CICA Handbook sections: 3855 Financial Instruments - Recognition and Measurement, 1530 Comprehensive income, and 3861 Financial Instruments - Disclosure and Presentation. The CICA Handbook section 3865 Hedges is effective January 1, 2007, however, Canadian Oil Sands has elected not to apply hedge accounting on a go-forward basis, and, therefore, has only applied the transitional provisions of this Handbook section. These new Handbook sections provide comprehensive requirements for the recognition and measurement of financial instruments, and introduce a new component of equity referred to as accumulated other comprehensive income ("AOCI"). In accordance with the transitional provisions of all of the new sections, the comparative interim consolidated financial statements have not been restated. Under these new standards, all financial instruments, including derivatives, are recognized on the Trust's Consolidated Balance Sheet. Derivatives are measured at fair value with unrealized gains and losses reported in net income. Short-term investments are measured at fair value with unrealized gains and losses reported in AOCI. The Trust's other financial instruments (accounts receivable, accounts payable, and long-term debt) are measured at amortized cost using the effective interest rate method. Transaction costs are added to the amount of the associated financial instrument and amortized accordingly. Several adjustments to the Trust's consolidated financial statements were required upon transition to the new financial instruments framework, which were the following: Deferred currency hedging gains In 1996, Canadian Oil Sands entered into currency hedging contracts to fix the exchange rate in future years. During 1999, Canadian Oil Sands unwound various positions and exchanged the resulting gains for adjustments to other existing currency contracts. These gains were deferred and as at December 31, 2006, the remaining cumulative deferral of the unrecognized gains was $35 million. Prior to the adoption of the new standards, the remaining deferral was to be recognized as revenue over the period 2007 to 2016 which is when the hedging contracts would have expired had they not been unwound. On transition, the deferred currency hedging gains of $35 million were reclassified to opening AOCI. The related future income tax asset of $10 million was reclassified from Canadian Oil Sands' future income tax liability to AOCI. The deferred gains included in AOCI are amortized on a straight-line basis into net income and recorded as currency hedging gains in the Trust's revenues over the period 2007 to 2016, with a corresponding decrease to other comprehensive income, net of future income tax. Long-term debt and deferred financing charges Prior to the adoption of the new standards, the Trust's long-term debt was recorded at cost. The related financing charges were included in "Deferred financing charges, net and other" on the Trust's Consolidated Balance Sheet, and recognized in net income over the life of the debt. Under the transitional provisions of Handbook section 3855 Financial Instruments - Recognition and Measurement, the Trust's long-term debt is now recorded at amortized cost using the effective interest rate method. The related financing charges have been included in the cost of the long-term debt. As a result of these changes, "Deferred financing charges, net and other" of $16 million, which was previously recorded as assets of the Trust, were reclassified to "Long-term debt" on the Consolidated Balance Sheet, and $1 million was recorded as a decrease to opening retained earnings. Currency exchange contracts and interest rate swaps Prior to the adoption of the new standards, one foreign currency exchange contract with an estimated fair value gain of $6 million was outstanding. The derivative had been designated as a hedge, and therefore was not recorded on the Trust's Consolidated Balance Sheet. Beginning January 1, 2007, Canadian Oil Sands is no longer applying hedge accounting to any of its hedging activities. Based on the transitional provisions of Handbook section 3865 Hedges, the Trust's foreign currency exchange contract was recognized on the Consolidated Balance Sheet and included in "Derivative assets" at its estimated fair value of $6 million on January 1, 2007, with a corresponding increase to opening AOCI. On adoption, a $2 million increase to the Trust's future income tax liability and a corresponding reduction to AOCI were also recorded related to the foreign currency hedge. This foreign currency contract was settled December 31, 2007. The Trust also had an interest rate swap on its US$70 million Senior Notes, which did not qualify for hedge accounting prior to January 1, 2007. The $1 million liability representing the unrecognized gains on the swap was recorded on the Trust's Consolidated Balance Sheet and included in "Employee future benefits and other liabilities" at December 31, 2006. On adoption of the new accounting rules on January 1, 2007, the liability balance was reclassed to opening AOCI. This interest rate swap was settled May 15, 2007. Determination of fair value The fair value of the Trust's long-term debt is determined based on market price indications. In fair valuing its derivatives, the Trust utilizes a valuation technique using available market prices. Comprehensive income The Consolidated Statement of Income and Comprehensive Income includes a new line item for comprehensive income, which includes both net income and other comprehensive income. Other comprehensive income includes recognition of unrealized gains and losses on derivatives and hedging gains that were previously deferred, net of the related future income tax on those items. 3) FUTURE CHANGES IN ACCOUNTING POLICIES Capital disclosures The CICA issued a new accounting standard, Section 1535 Capital Disclosures, which requires the disclosure of both qualitative and quantitative information that provides users of financial statements with information to evaluate the entity's objectives, policies and processes for managing capital. This new section is effective for the Trust beginning January 1, 2008. Financial Instruments - Disclosure and Financial Instruments - Presentation Two new accounting standards were issued by the CICA, Section 3862 Financial Instruments -Disclosures, and Section 3863 Financial Instruments - Presentation. These sections will replace Section 3861 Financial Instruments - Disclosure and Presentation once adopted. The objective of Section 3862 is to provide users with information to evaluate the significance of the financial instruments on the entity's financial position and performance, the nature and extent of risks arising from financial instruments, and how the entity manages those risks. The provisions of Section 3863 deal with the classification of financial instruments, related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. These new sections are effective for the Trust beginning January 1, 2008. Inventories In June 2007, the CICA issued a new accounting standard - Section 3031 Inventories, which replaces the existing standard for inventories, Section 3030. The main features of the new Section are as follows: - Measurement of inventories at the lower of cost and net realizable value - Consistent use of either first-in, first-out or a weighted average cost formula to measure cost - Reversal of previous write-downs to net realizable value when there is a subsequent increase to the value of inventories The new Section is effective for the Trust beginning January 1, 2008. Application of the new Section is not expected to have an impact on the financial statements. 4) ACQUISITION OF ADDITIONAL SYNCRUDE WORKING INTEREST On January 2, 2007, a subsidiary of the Trust closed an acquisition with Talisman Energy Inc. ("Talisman") to purchase an additional 1.25 per cent indirect working interest in the Syncrude Joint Venture ("Syncrude") for total consideration of $476 million ($468 million net of $8 million cash acquired), including acquisition-related costs of approximately $1 million. The transaction price was comprised of $238 million in cash and 8,189,655 Units issued from treasury with an approximate value at the time of entering the acquisition agreement of $29 per Unit. The acquisition has been accounted for as a purchase of assets in accordance with Canadian GAAP. The Trust has allocated the purchase price to the assets and liabilities as follows: Net assets and liabilities assumed Property, plant and equipment $ 668 Cash 8 Working capital 1 Employee future benefits and other liabilities (8) Asset retirement obligation (6) Future income taxes (187) --------------------------------------------------------------------- $ 476 --------------------------------------------------------------------- --------------------------------------------------------------------- Consideration Cash $ 238 Issuance of Trust Units 237 Acquisition costs 1 --------------------------------------------------------------------- $ 476 --------------------------------------------------------------------- The additional 1.25 per cent working interest that Canadian Oil Sands acquired was held in a partnership owned by Talisman and a subsidiary of the Trust. Immediately following Canadian Oil Sand's acquisition of Talisman's interest in the partnership, the partnership was dissolved. The dissolution resulted in an adjustment, which increased Canadian Oil Sands' future income tax liability by $140 million and correspondingly increased its property, plant and equipment on the Consolidated Balance Sheet, which was accounted for prospectively. 5) ISSUANCE OF TRUST UNITS In the twelve months ended December 31, 2007, approximately 8.2 million Units were issued for proceeds of $237 million related to the acquisition of the 1.25 per cent indirect working interest in Syncrude. The following table summarizes Units that have been issued: Number of Date Units Amount --------------------------------------------------------------------- Balance, January 1, 2007 470.9 $ 2,260 Issued for acquisition of additional Syncrude working interest (non-cash) 8.2 237 Issued on exercise of employee options 0.3 3 --------------------------------------------------------------------- Balance, December 31, 2007 479.4 $ 2,500 --------------------------------------------------------------------- 6) EMPLOYEE FUTURE BENEFITS Syncrude Canada Ltd. ("Syncrude Canada"), the operator of the Syncrude Joint Venture, has a defined benefit and two defined contribution plans providing pension benefits, and other retirement and post-employment benefits to most of its employees. Other post- employment benefits include certain health care and life insurance benefits for retirees, their beneficiaries and covered dependents. Canadian Oil Sands accrues its obligations as a joint venture owner in respect of Syncrude Canada's employee benefit plans and the related costs, net of plan assets. The cost of employee pension and other retirement benefits is actuarially determined using the projected benefit method based on length of service and reflects Canadian Oil Sands' best estimate of the expected performance of the plan investment, salary escalation factors, retirement ages of employees and future health care costs. The expected return on plan assets is based on the fair value of those assets. Past service costs from plan amendments are amortized on a straight-line basis over the estimated average remaining service life of active employees ("EARSL") at the date of amendment. The excess of any net actuarial gain or loss exceeding 10 per cent of the greater of the benefit obligation and fair value of the plan assets is amortized over the EARSL. Canadian Oil Sands' share of Syncrude Canada's net defined benefit and contribution plans expense for the three and twelve months ended December 31, 2007 and 2006 is based on its 36.74 per cent and 35.49 per cent working interests in each of 2007 and 2006, respectively. The costs have been recorded in operating expense as follows: Three Months Ended Twelve Months Ended December 31 December 31 --------------------------------------------------------------------- 2007 2006 2007 2006 --------------------------------------------------------------------- Defined benefit plans: Pension benefits $ 7 $ 7 $ 27 $ 30 Other benefit plans - 1 3 3 --------------------------------------------------------------------- $ 7 $ 8 $ 30 $ 33 Defined contribution plans 1 - 2 2 --------------------------------------------------------------------- Total Benefit cost $ 8 $ 8 $ 32 $ 35 --------------------------------------------------------------------- --------------------------------------------------------------------- 7) BANK CREDIT FACILITIES Credit facility --------------------------------------------------------------------- Extendible revolving term facility (a) $ 40 Line of credit (b) 45 Operating credit facility (c) 800 --------------------------------------------------------------------- $ 885 --------------------------------------------------------------------- --------------------------------------------------------------------- a) The $40 million extendible revolving term facility is a 364-day facility with a one year term out, expiring April 24, 2008. This facility may be extended on an annual basis with the agreement of the bank. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. b) The $45 million line of credit is a one year revolving letter of credit facility. The amount of this facility was increased during the first quarter of 2007 to $45 million from $35 million at December 31, 2006. Letters of credit drawn on the facility mature April 30th each year and are automatically renewed, unless notification to cancel is provided by Canadian Oil Sands or the financial institution providing the facility at least 60 days prior to expiry. Letters of credit on this facility bear interest at a credit spread. Letters of credit of approximately $61 million have been written against the extendible revolving term facility and line of credit. c) The $800 million operating facility is a five year facility, expiring April 27, 2012. Amounts borrowed through this facility bear interest at a floating rate based on bankers' acceptances plus a credit spread, while any unused amounts are subject to standby fees. As at December 31, 2007, $16 million was drawn on this facility (2006 - nil). d) Each of the Trust's credit facilities is unsecured. These credit agreements contain typical covenants relating to the restriction on Canadian Oil Sands' ability to sell all or substantially all of its assets or to change the nature of its business. In addition, Canadian Oil Sands has agreed to maintain its total debt-to-total book capitalization at an amount less than 0.6 to 1.0, or 0.65 to 1.0 in certain circumstances involving acquisitions. 8) LONG-TERM DEBT On January 15, 2007, the Trust repaid $175 million of 3.95% medium term notes and $20 million of floating rate medium term notes. On May 15, 2007, the Trust repaid US$70 million of 7.625% Senior Notes. Canadian Oil Sands intends to refinance on a long-term basis the 5.75% medium term notes that are maturing in 2008. The Trust has $808 million of unutilized operating credit facilities at December 31, 2007 to draw on to refinance these obligations, and $800 million of these facilities do not expire until April 27, 2012. In accordance with EIC-122, debt maturing in 2008 has not been reclassified to current liabilities. 9) ASSET RETIREMENT OBLIGATION ("ARO") Three Months Ended Twelve Months Ended December 31 December 31 2007 2006 2007 2006 --------------------------------------------------------------------- Asset retirement obligation, beginning of period $ 186 $ 153 $ 173 $ 148 Acquired(1) - - 6 - Liabilities settled - - (1) (2) Accretion expense 3 2 11 9 Asset retirement obligation increases 37 18 37 18 --------------------------------------------------------------------- Asset retirement obligation, end of period $ 226 $ 173 $ 226 $ 173 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Canadian Oil Sands assumed the asset retirement obligation relating to the additional 1.25 per cent working interest acquired on January 2, 2007. The Trust and each of the other Syncrude owners are liable for their share of ongoing environmental obligations for the ultimate reclamation of the Syncrude Joint Venture and the ARO represents the present value estimate of Canadian Oil Sands' share of the cost to reclaim the mines. The total undiscounted estimated future cash flows required to settle the Trust's 36.74% (2006 - 35.49%) share of the Syncrude obligation increased to $743 million (2006 - $595 million), which primarily reflects the Trust's share of increased cost estimates to comply with Syncrude's new Alberta Environmental Protection and Enhancement Act Approval. The new requirements resulted in higher cost estimates for soil salvage, soil placement thickness and soil layering. Discounting these incremental cash flows resulted in a $37 million increase in the asset retirement obligation at December 31, 2007. 10) FUTURE INCOME TAX On June 12, 2007, the new Trust taxation rules previously announced by the government on October 31, 2006 became substantively enacted. As a result, the future income tax payable and corresponding future income tax expense on the Trust's temporary differences between the accounting basis and the tax basis of its assets and liabilities was recorded in the second quarter of 2007, which totalled $701 million. During 2007, the federal government substantively enacted various tax rate reductions, which lowered the corporate tax rates for the years 2008 to 2012 and beyond. The corporate tax rates were reduced from 20.5% in 2008 to an ultimate rate of 15% in 2012 and future years. These federal rate reductions also reduce the taxation rate applicable to trusts from 31.5% to 29.5% starting in 2011 and to 28% in 2012 and beyond. Canadian Oil Sands applied these rate reductions to its future income tax calculations in 2007, resulting in a total future income tax recovery of approximately $193 million, of which $153 million was recorded in the fourth quarter. 11) INTEREST, NET Three Months Ended Twelve Months Ended December 31 December 31 2007 2006 2007 2006 --------------------------------------------------------------------- Interest expense on long-term debt Interest income and other $ 20 $ 25 $ 91 $ 102 (3) (1) (6) (4) --------------------------------------------------------------------- Interest expense, net $ 17 $ 24 $ 85 $ 98 --------------------------------------------------------------------- --------------------------------------------------------------------- 12) UNITHOLDER DISTRIBUTIONS The Consolidated Statements of Unitholder Distributions is provided to assist Unitholders in reconciling cash from operating activities to Unitholder distributions. Pursuant to Section 5.1 of the Trust Indenture, the Trust is required to distribute all the income received or receivable by the Trust in a quarter less expenses and any other amounts required to be withheld by law or under the terms of the Trust Indenture. The Trust primarily receives income by way of a royalty and interest on intercompany loans from its operating subsidiary, Canadian Oil Sands Limited ("COSL"). The royalty is designed to capture the cash generated by COSL, after the deduction of all costs and expenses including operating and administrative costs, income taxes, capital expenditures, debt interest and principal repayments, working capital and reserves for future obligations deemed appropriate. The amount of royalty income that the Trust receives in any period has a considerable amount of flexibility through the use of discretionary reserves and debt borrowings or repayments (either intercompany or third party). Quarterly distributions are determined by the Board of Directors after considering the current and expected economic and operating conditions, ensuring financing capacity for Syncrude's expansion projects and/or Canadian Oil Sands acquisitions, and with the objective of maintaining an investment grade credit rating. CANADIAN OIL SANDS TRUST CONSOLIDATED STATEMENTS OF UNITHOLDER DISTRIBUTIONS (unaudited) Three Months Ended Twelve Months Ended December 31 December 31 ------------------- ------------------- 2007 2006 2007 2006 --------------------------------------------------------------------- Cash from operating activities $ 367 $ 412 $1,377 $1,142 Add (Deduct): Capital expenditures (55) (57) (183) (300) Acquisition of additional Syncrude working interest - - (231) - Acquisition of Canadian Arctic Gas Ltd. - (48) - (199) Disposition of properties - 28 4 28 Change in non-cash working capital (1) 4 3 (1) (47) Reclamation trust funding (3) (1) (7) (5) Change in cash and cash equivalents and financing, net (2) (49) (197) (168) (107) --------------------------------------------------------------------- Unitholder distributions $ 264 $ 140 $ 791 $ 512 --------------------------------------------------------------------- --------------------------------------------------------------------- Unitholder distributions per Trust Unit (3) $ 0.55 $ 0.30 $ 1.65 $ 1.10 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) From investing activities. (2) Primarily represents the change in cash and cash equivalents and net financing to fund the Trust's share of investing activities. (3) Unit information has been adjusted to reflect the 5:1 Unit split, which occurred on May 3, 2006. 13) SUPPLEMENTARY INFORMATION Three Months Ended Twelve Months Ended December 31 December 31 2007 2006 2007 2006 --------------------------------------------------------------------- Income tax paid $ - $ - $ 1 $ 5 --------------------------------------------------------------------- --------------------------------------------------------------------- Interest charges paid $ 13 $ 18 $ 94 $ 100 --------------------------------------------------------------------- --------------------------------------------------------------------- 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

Organization Profile

CANADIAN OIL SANDS TRUST

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