M A N A G E M E N T ' S   D I S C U S S I O N   A N D   A N A L Y S I S

The following  discussion of financial condition and results of operations was
prepared  as of March  28,  2006 and  should be read in  conjunction  with the
Consolidated  Financial  Statements and Notes thereto.  It offers Management's
analysis  of  our  financial  and  operating   results  and  contains  certain
forward-looking  statements  relating  but  not  limited  to  our  operations,
anticipated   financial   performance,   business  prospects  and  strategies.
Forward-looking  information  typically contains statements with words such as
"anticipate",  "estimate",  "expect",  "potential",  "could", or similar words
suggesting  future outcomes.  We caution readers and prospective  investors in
the  Company's  securities  not to place  undue  reliance  on  forward-looking
information as by its nature, it is based on current expectations that involve
a number of assumptions,  inherent risks and uncertainties,  which could cause
actual results to differ materially from those  anticipated by Western.  For a
description of the risks and  uncertainties  facing Western,  see "Outlook for
2006".

     For additional information relating to the risks and uncertainties facing
Western,  refer to  Western's  Annual  Information  Form  for the  year  ended
December 31, 2005, which is available on SEDAR at www.sedar.com.



O V E R V I E W

Western Oil Sands Inc. ("Western") owns 20 per cent of the Athabasca Oil Sands
Project ("AOSP"),  a multi-billion dollar Joint Venture that is exploiting the
recoverable  bitumen reserves and resources found in oil sands deposits in the
Athabasca  region of Alberta,  Canada.  Our partners are Shell Canada  Limited
("Shell"),   with  a  60  per  cent  interest,   and  Chevron  Canada  Limited
("Chevron"),  which holds the remaining 20 per cent.  The AOSP consists of two
key  facilities:  the Muskeg  River Mine located 70  kilometres  north of Fort
McMurray,  Alberta,  where the oil  sands  deposits  are  mined and  partially
upgraded;  and the Scotford Upgrader outside of Edmonton,  Alberta,  where the
bitumen is further  upgraded into  synthetic  crude oil and delivered into the
North American crude oil marketing system. The Mine and Upgrader are connected
by a 493-kilometre pipeline.

     At this time,  Western's 20 per cent  investment  in the AOSP is our most
material and only operating asset. We generate revenue from the sale of our 20
per cent portion of the synthetic crude oil and other products produced at the
Scotford  upgrader.  Approximately  one-third  of the volumes  produced  are a
mixture of light,  medium and heavy vacuum gas oil ("LMHVGO")  that is sold to
Shell  under a  long-term  contract  for use in their  adjacent  refinery.  In
addition,  our processes  produce two grades of synthetic  crude oil:  Premium
Albian  Synthetic  ("PAS") and Albian Heavy  Synthetic  ("AHS").  Our share of
these  products  is  marketed  and  sold  by  Western  to  various  refineries
throughout North America.

     Sustained  higher  commodity  prices,  together  with greater than design
production levels during 2005, combined to achieve record production, revenue,
net income and cash flow from  operations  for Western.  During the year,  our
capital  expenditure  program was financed  entirely out of cash flow.  Excess
cash was applied to reduce our bank  borrowings.  Western applied $175 million
to the repayment of bank credit  facilities during the year, which resulted in
a  significant  strengthening  of our  balance  sheet.  Our  improving  credit
profile,  combined  with the  implementation  of a new strategic oil commodity
risk management  program,  has put Western in a strong  financial  position to
fund its share of the  expansion  efforts  announced by the Joint Venture that
will occur over the next several years.

     During 2005,  Western achieved  successive  quarterly  production records
from the second quarter through to the fourth  quarter.  In the fourth quarter
of  2005,   production   averaged   approximately   35,600   barrels  per  day
(approximately  178,000  barrels  per day at the Project  level).  Operational
difficulties  at the Upgrader in the fourth  quarter of 2004 extended into the
first  quarter  of 2005 and  impacted  first  quarter  2005  performance.  The
quarterly  production rates  established  record annual average  production of
approximately  32,000  barrels  per day in 2005,  representing  an 18 per cent
increase over production  volumes reported in 2004. These production rates set
the stage for continued  operational  stability and growing  profitability for
the AOSP's existing assets.


<PAGE>

     Reliability and  availability of our existing AOSP  facilities,  together
with on-time,  on-budget execution of our AOSP expansion plans, is our primary
focus.  The objective is to take Western's  production  beyond 100,000 barrels
per day over the next eight to ten years.  This growth  strategy also includes
optimizing the value of our existing world-class assets through  technological
enhancements.  Furthermore, as Western matures and evolves as an organization,
our growth  strategy  includes  opportunistically  growing  our  business  and
leveraging  our  strengths  by taking  our core  competencies  and  skills and
applying them to new business opportunities.  In this regard, one of Western's
key  objectives  is to identify and capture  large,  long-life  projects  with
significant  hydrocarbon resource potential to create additional value for our
shareholders.


O P E R A T I N G   R E S U L T S

Western commenced commercial  operations on June 1, 2003, which was defined by
Management  as  attaining  50 per  cent  of the  Project's  productive  design
capacity of 155,000 barrels per day, with all aspects of the facilities  fully
operational.  Since that time,  Western has recorded revenues and expenses for
its share of operations from the Project. Prior to June 1, 2003, all revenues,
operating  costs and  interest  were  capitalized  as part of the costs of the
Project,  and  no  depreciation,   depletion  or  amortization  was  expensed.
Comparisons  to prior  years'  pre-operating  information  are provided in the
following discussion where appropriate.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------
Highlights                                                                    2005          2004           2003
-----------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>           <C>            <C>
Operating Data (bbls/d)
    Bitumen Production                                                      31,994        27,108         23,596
    Synthetic Crude Sales                                                   42,534        36,210         32,207
    Operating Expense per Processed Barrel ($/bbl)                           22.06         21.17          20.71
=================================================================================================================
Financial Data ($ thousands, except as indicated)
    Gross Revenue                                                          910,330       636,911        281,093
    Realized Crude Oil Sales Price - Oil Sands ($/bbl) (1) (2)               49.91         34.60          32.81
    Cash Flow from Operations (3)                                          244,231        23,044          5,803
    Cash Flow per Share - Basic ($/Share) (1) (4)                             1.52          0.15           0.04
    Net Earnings Attributable to Common Shareholders (6)                   149,449        19,452         15,003
    Net Earnings per Share ($/Share)
        Basic                                                                 0.93          0.12           0.10
        Diluted                                                               0.92          0.12           0.10
    EBITDAX (1) (5)                                                        307,008        87,587         47,615
    Net Capital Expenditures (7)                                            46,833        39,968        148,473
    Total Assets                                                         1,590,520     1,470,870      1,458,424
    Long-Term Debt                                                         565,655       662,620        860,580
    Long-Term Financial Liabilities (8)                                    706,880       716,094        914,773
    Weighted Average Shares Outstanding - Basic (Shares)               160,169,887   156,926,514    151,032,996
=================================================================================================================
</TABLE>

(1)  Please refer to page 44 for a discussion of non-GAAP financial measures.
(2)  The realized  crude oil sales price is the revenue  derived from the sale
     of Western's share of the Project's  synthetic crude oil, net of the risk
     management activities,  divided by the corresponding volume. Please refer
     to page 25 for calculation.
(3)  Cash flow from operations is expressed before changes in non-cash working
     capital.
(4)  Cash flow per share is calculated as cash flow from operations divided by
     weighted average common shares outstanding, basic.

<PAGE>

(5)  Earnings before interest, taxes, depreciation,  depletion,  amortization,
     stock-based  compensation,  accretion  on  asset  retirement  obligation,
     foreign exchange and risk management as calculated on page34.
(6)  Western has not paid cash dividends in any of the above referenced fiscal
     years.
(7)  Net capital  expenditures  are capital  expenditures net of any insurance
     proceeds received during the period.
(8)  Long-term financial  liabilities  includes long-term debt, option premium
     liability  and lease  obligations.  Prior  years are  restated to include
     lease obligations.



F I N A N C I A L   P E R F O R M A N C E

Revenue

Western achieved record gross crude oil sales revenue in fiscal 2005 totalling
$910.3  million  (2004 - $636.9  million),  including  $777.9  million (2004 -
$458.5 million) from  proprietary  production at an average  realized price of
$49.91 per barrel (2004 - $34.60 per barrel).  Gross  revenue rose 43 per cent
primarily  as a result of an 18 per cent  increase  in  production  during the
year,  combined  with a 44 per cent  increase in blended  price  realizations.
Gross revenue includes the effects of risk management  activities that reduced
revenue by $110.4  million  (2004 - $131.4  million),  and reduced the average
realized price by $7.11 per barrel during 2005 (2004 - $9.92 per barrel).

     Western's crude oil sales were subject to an overall quality differential
of  $12.27  per  barrel  (2004 - $8.44 per  barrel)  off of the  Edmonton  PAR
benchmark  crude oil price of $69.29  per barrel in 2005.  Forced  operational
outages at the  Upgrader  in the first  quarter of 2005  resulted  in a larger
percentage  of heavy crude in our overall  sales mix and,  since these streams
receive a lower price, overall sales price realizations decreased. Sales price
realizations  during 2005 were also  negatively  impacted by a widening of the
heavy oil  differential to West Texas  Intermediate  ("WTI") compared to 2004.
The heavy oil  differential  to WTI  widened to an average 39 per cent  during
2005  compared  to an  average  of 34 per cent in 2004,  and has  historically
represented  approximately  30 per cent of stated  posted WTI  prices.  As the
graph on page 24 indicates,  Western's  sales price  realizations  are largely
correlated  to movements in WTI.  Over the last two years,  the only  quarters
where this  relationship  was not  maintained was during the fourth quarter of
2004 and first quarter of 2005,  where forced  operational  outages  occurred,
resulting in Western's sales mix skewed to a greater proportion of heavy crude
oil.

     The AOSP is actively identifying  optimization  initiatives to reduce the
Project's exposure to heavy oil price differentials. We have observed that the
heavy oil differential to WTI tends to increase as WTI itself appreciates.  If
this relationship continues, we would expect heavy oil differentials to remain
wide in periods of robust  commodity  prices.  Western expects its sales price
realizations  to improve in 2006 largely due to the absence of any fixed-price
hedges, which ended in December 2005, allowing Western to fully participate in
actual crude oil prices during the upcoming  year. In total,  Western's  fixed
price  hedging  program,  which  commenced  during  2003,  reduced  revenue by
approximately  $250 million.  These hedges were executed in late 2002 and over
the course of fiscal 2003 during a significantly lower crude oil price regime.
The hedging  program (which  locked-in a fixed WTI price on Western's share of
production  from the AOSP  ranging  from 20,000  barrels per day down to 7,000
barrels per day at its completion in the last quarter of 2005) provided a base
line level of cash flow to meet future  debt  servicing  and  working  capital
commitments and protected the Company from a precipitous drop in oil prices.

     As  detailed  in the  "Financial  Risks"  section,  Western  completed  a
separate  strategic crude oil risk management program during the third quarter
of 2005 covering a portion of our  production  from 2007 through to the end of
2009. The put/call "collar" structure  employed  establishes a floor price for
up to two-thirds of our expected  production,  yet allows for participation in
increasing  oil prices  during this period  and,  thereby,  does not limit the
upside potential related to commodity price appreciation to the same degree as
the fixed-price swap contracts used previously.


<PAGE>

     Western  generated  net  revenue of $591.4  million in 2005  compared  to
$321.0  million in 2004,  representing  an 84 per cent  increase.  Net revenue
reflects the costs of purchased feedstocks and transportation costs downstream
of Edmonton.  Feedstocks  are crude oil products  introduced  at the Upgrader.
Some  feedstocks are introduced into the  hydrocracking/hydrotreating  process
and others are used as  blendstock  to create  various  qualities of synthetic
crude oil products.  The cost of these feedstocks depends on world oil markets
and the spread between heavy and light crude oil prices.

-----------------------------------------------------------------------------
Net Revenue
($ thousands, except as indicated)                         2005         2004
-----------------------------------------------------------------------------

Revenue
    Oil Sands (1)                                       777,876      458,502
    Marketing and Transportation                        132,454      178,409
=============================================================================
    Total Revenue                                       910,330      636,911

Purchased Feedstocks and Transportation
    Oil Sands                                           185,693      137,810
    Marketing and Transportation                        133,241      178,116
=============================================================================
    Total Purchased Feedstocks and Transportation       318,934      315,926

Net Revenue
    Oil Sands (1)                                       592,183      320,692
    Marketing and Transportation                           (787)         293
=============================================================================
    Total Net Revenue                                   591,396      320,985

Synthetic Crude Sales (bbls/d)                           42,534       36,210
Crude Oil Sales Price ($/bbl) (2)                         49.91        34.60
=============================================================================

(1)  Oil sands revenue and net revenue are presented net of Western's  hedging
     activities.
(2)  Realized crude oil sales price ($/bbl) is calculated as oil sands revenue
     less any  transportation  costs divided by synthetic  crude sales volume.
     For the year ended 2005,  $3.0 million (2004 - nil) had been incurred for
     transportation costs related to oil sands.


O P E R A T I N G   C O S T S

We believe that, to a certain  extent,  our operating  costs are a function of
longer-term WTI prices. In 2005, WTI averaged  US$56.56 per barrel,  which put
upward pressure on certain cost components,  including natural gas.  Operating
costs  for  oil  sands   operations   typically   decline  over  time  as  the
technological  and  engineering  challenges  are addressed and resolved and as
efficiency and effectiveness  programs are completed.  These  efficiencies are
being realized at the AOSP, and we expect to see a continued reduction in unit
operating  costs  over  the  coming  years;  however,  this may be  offset  by
continued  increases  in the cost of natural  gas and of basic  materials  and
supplies caused by major demand pull in critical supply markets and variations
in the ore body with respect to bitumen  grade and strip ratio (ore to waste).
Given our  state-of-the-art  technology,  and what we assess as a superior ore
body, we believe Western can be one of the lowest-cost  producers of synthetic
crude oil in the Canadian oil sands.

     Western's  share of Project  operating  costs totalled  $250.4 million in
2005 (2004 - $213.0 million).  Included in this total are the costs associated
with removing overburden at the Mine and transporting bitumen from the Mine to
the Upgrader. On a per processed barrel of bitumen basis, unit operating costs
were $22.06 per barrel based on average  production of 31,994  barrels per day
in 2005  compared to $21.17 per barrel based on average  production  of 27,108
barrels per day in 2004.


<PAGE>

     Higher  unit  operating  costs in 2005  were  largely  due to  increasing
natural gas costs for fuel,  utilities  and hydrogen  supply as well as higher
input costs for  materials  and  supplies  in an  escalating  commodity  price
environment.  Natural gas costs per unit  increased 19 per cent over 2004 as a
result of higher  underlying  gas prices.  We also observed  higher prices for
supplies  and  materials  and  contract  services  as a result  of the  heated
commodity environment,  as these suppliers were themselves experiencing higher
demand for their goods and services  leading to higher costs.  Unit  operating
costs in 2005  were  also  impacted  by  repair  costs  incurred  in the first
quarter,  stemming from the forced  operational  outages that commenced in the
fourth  quarter of 2004 and  extended  into the first  quarter  of 2005.  Unit
operating costs per processed  barrel of bitumen were $25.44 per barrel in the
first  quarter of 2005.  Over the next three  successive  quarters,  where the
Project  achieved  record  production  levels,  unit operating  costs averaged
$21.22 per processed  barrel of bitumen,  of which $5.10 per barrel relates to
natural gas.

     Operating  costs  are,  and  will  continue  to be,  a key  metric  among
companies  active in the mineable oil sands  industry.  Companies that control
costs will drive better financial results.  Different oil sands producers have
different  cost  structures  and accounting  treatments  that require  careful
analysis to make meaningful  comparisons.  Western, for example,  includes the
cost of transporting  processed bitumen from Fort McMurray to Edmonton as part
of  overall  operating  costs,   whereas  other  industry  players  net  these
transportation  costs from oil sands  revenue.  Western  also  includes in its
operating  costs the cost to remove the  overburden in its mining  operations,
while some other oil sands producers capitalize such costs. Nevertheless,  all
companies  active in the energy  industry  are coming to terms with the higher
commodity  price  environment  and associated  increased  costs for materials,
supplies and natural gas. Even though the entire  industry cost  structure has
shifted upwards,  Western will continue to evaluate all methods to control and
reduce its cost structure.  As the majority of the AOSP's  operating costs are
fixed, to the extent the Project can maintain continuous reliable  operations,
total unit  operating  costs will  decrease as the costs are spread out over a
greater production base.

------------------------------------------------------------------------------
Operating Costs
($ thousands, except as indicated)                         2005         2004
------------------------------------------------------------------------------

Operating Expenses for Bitumen Sold
    Operating Expense - Income Statement                250,389      212,993
    Operating Expense - (Inventoried)/Expensed in
        Purchased Feedstocks                             11,704       (3,058)
==============================================================================
    Total Operating Expenses for Bitumen Sold           262,093      209,935
------------------------------------------------------------------------------
Sales (barrels per day)
    Total Synthetic Crude Sales                          42,534       36,210
    Purchased Upgrader Blendstocks                        9,979        9,112
==============================================================================
    Synthetic Crude Sales Excluding Blendstocks          32,555       27,098
------------------------------------------------------------------------------
Operating Expenses per Processed Barrel ($/bbl) (1)       22.06        21.17
==============================================================================

(1)  Operating  expenses per processed  barrel  ($/bbl) is calculated as total
     operating  expenses for bitumen  sold  divided by  synthetic  crude sales
     excluding blendstocks. This calculation recognizes that, intrinsic in the
     Project's  operations,  bitumen  production  from  the Mine  receives  an
     approximate    three    per   cent    uplift   as   a   result   of   the
     hydrotreating/hydroconversion  process,  which is included  in  synthetic
     crude sales excluding blendstocks.


O P E R A T I N G   N E T B A C K S

Despite the forced  operational  outages  experienced in the fourth quarter of
2004 that extended into the first quarter of 2005,  Western  achieved a robust
netback per barrel  excluding  commodity  hedge impacts,  compared to previous
quarters.  Heavy oil  differentials  widened  towards the end of the year and,
combined with the continued strength in the US/Cdn exchange rate, put pressure
on our fourth quarter results.  The heavy oil differential widened in part due
to the seasonal  reduction in demand by refineries as they undertake  year-end
maintenance  programs. We expect to achieve materially higher netbacks in 2006
due to the expiration of our fixed-priced swap hedging program on December 31,
2005,  assuming that commodity prices maintain current levels.  Hedging losses
of $110.4 million in 2005 materially decreased Western's netbacks.


<PAGE>

Royalties

Royalties  amounted  to $4.0  million  or $0.34 per  barrel of bitumen in 2005
compared to $3.0 million or $0.30 per barrel of bitumen in 2004.  Higher gross
royalties  reflect record  production  levels in 2005,  together with a higher
deemed bitumen price,  the latter of which serves as the basis for the royalty
calculation.  Initially, royalties are calculated at one per cent of the gross
revenue  from  the  bitumen  produced  (based  on its  deemed  value  prior to
upgrading)  until  recovery of all capital  costs  associated  with the Muskeg
River Mine and  Extraction  Plant,  together with a return on capital equal to
the Government of Canada's  federal  long-term  bond rate.  After full capital
cost recovery, the royalty is calculated as the greater of one per cent of the
gross revenue on the bitumen produced or 25 per cent of the net revenue on the
bitumen  produced.  Western fully expects to  participate in the expansions of
the AOSP. As such,  Western  anticipates  that additional  capital incurred to
construct  the  expansions  will be added  to the  capital  base  for  royalty
purposes.  Western  believes  certain  capital  relating to the  extraction of
bitumen will be  "ring-fenced"  for royalty  purposes,  which,  in turn,  will
extend our  royalty  horizon.  Assuming a  long-term  WTI price of US$55.00 to
US$60.00 and a US/Cdn  exchange rate of $0.85, we estimate our royalty horizon
on the  Project  to be  approximately  2010,  after  which  we will be  paying
royalties  at the higher  rates.  The royalty  horizon may be  accelerated  or
postponed  depending on future prices of crude oil, foreign exchange rates and
the timing and inclusion of capital expenditures.


R E S E R V E S,   R E S O U R C E S   A N D   L A N D

Under the terms of the Joint Venture  Agreement for the AOSP,  Western and its
Joint Venture  Participants  have in place a Participation  and Area of Mutual
Interest  Agreement  ("AMI").  The AMI stipulates that the Project Owners have
rights to participate in any additional leases that are acquired by any one of
the Joint Venture Participants in the Athabasca region.

     Within the Project we have the  following:  proved and probable  reserves
that are  associated  with the existing  operations  at the Muskeg River Mine;
resources on lands  within the Joint  Venture  that have been  evaluated;  and
finally, undeveloped lands which have been acquired by all three Owners during
the past year that are included  under the terms of the AMI and are subject to
evaluation for possible future development.

Reserves

GLJ Petroleum  Consultants Ltd. ("GLJ") has  independently  estimated that the
proved  and  probable  reserves  on the west side of Lease 13 are 1.6  billion
barrels  (310  million  barrels net to  Western).  These  proved and  probable
reserves  translate into a reserve life index of  approximately 27 years based
on an anticipated undiluted bitumen production rate of 155,000 barrels per day
(31,000 barrels per day net to Western). Substantial reserve additions will be
made as the AOSP moves through the gating  process for the upcoming  phases of
expansion.  Resources  from our future  expansions  will be booked as reserves
when the  expansion  phases are  permitted,  funding is  approved  and certain
stipulations pursuant to the Joint Venture Agreement are satisfied.  The table
below  summarizes  the  Project's  reserves  and our share of those proved and
probable  reserves  as at December  31,  2005 on a  synthetic  crude oil basis
utilizing GLJ's forecast of escalating  prices and costs.  Synthetic crude oil
is dry bitumen, uplifted by three per cent for hydrocracking/hydrotreating.

     The following  information relating to our reserves and present values of
estimated future net cash flow constitutes forward-looking statements as it is
based upon  assumptions  relating to, among  others,  volumes of oil in place,
recoverability  of bitumen,  production  rates,  royalty rates,  operating and
development costs, capital expenditures, commodity prices and foreign exchange
rates.  For a description of the risks and  uncertainties  facing Western that
could  impact on the  volume and value of the  reserves  reported  below,  see
"Outlook for 2006".

<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
Reserves Summary                            Gross    Working
--------------------------------------------------------------------------------------------------------------------------

                                                                                 Present Value of Estimated Future
                                          Project   Interest   Net After         Net Cash Flow before Income Taxes

                                         Reserves   Reserves     Royalty           0%         10%        15%         20%
--------------------------------------------------------------------------------------------------------------------------
                                         (MMbbls)   (MMbbls)    (MMbbls)                     ($ millions)
<S>                                      <C>        <C>        <C>          <C>           <C>        <C>         <C>
Proved                                        974        195         179       3,650       2,014      1,611       1,337
Probable                                      577        115         104       2,799         671        386         248
==========================================================================================================================
Proved Plus Probable                        1,551        310         283       6,449       2,685      1,997       1,585
==========================================================================================================================

<CAPTION>
Reserves Reconciliation (Working Interest)
Proved Plus
(MMbbls)                                                                                             Proved    Probable
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                                  <C>       <C>
December 31, 2004                                                                                       204         317
Production                                                                                              (12)        (12)
Revisions                                                                                                 3           5
==========================================================================================================================
December 31, 2005                                                                                       195         310
==========================================================================================================================
</TABLE>


Resources

The AOSP has several  leases that have been  formally  evaluated  for resource
potential.  These are Leases 88, 89, 90, 9 and 17 and the  remainder  of Lease
13.  Western   engaged  Norwest   Corporation   ("Norwest")  to  conduct  this
assessment. They provided high, best and low estimates of discovered resources
for each  area,  with the  exception  of Lease 17 which  only  includes a high
estimate.  The best case estimate for the discovered resources on a total AOSP
basis  exceeds  8.2  billion  barrels in place or 1.6  billion  barrels net to
Western.  Except  in the case of Lease 17  where  data is  limited,  Norwest's
report  is  based  on  several   critical   assumptions  in  order  to  record
resources-in-place,  namely,  minimum  bitumen  by weight of seven per cent to
total  weight,  minimum  mining  thickness of three  metres and maximum  total
volume to bitumen in place  ("TV:BIP")  of 12:1.  The details of the  specific
leases are summarized in the table below.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------------
Estimate of Discovered Resources (1) (2)                                              High          Best            Low
(MMbbls in place)                                                                    (P90)         (P50)          (P10)
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>           <C>            <C>
Remainder of Lease 13                                                                5,251         5,028          3,194
Lease 90                                                                               269           253            162
Leases 88 and 89                                                                     2,382         2,038            856
Lease 9 and 17 (3)                                                                   2,110           899            431
--------------------------------------------------------------------------------------------------------------------------
Total                                                                               10,012         8,218          4,643
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1   The table above represents total Project interest in the leases which are
     currently  held by  Shell.  Under  the  AMI,  Western  has the  right  to
     participate in these leases to a 20 per cent level.
(2)  "Discovered Resources" are those quantities of oil and gas estimated on a
     given date to be remaining  in, plus those  quantities  already  produced
     from, known accumulations. Discovered resources are divided into economic
     and uneconomic categories,  with the estimated future recoverable portion
     classified   as  reserves   and   contingent   resources,   respectively.
     (Source:Canadian  Oil and Gas  Evaluation  Handbook,  Volume  1,  Section
     5.2.2.)
(3)  Norwest  only  inferred  resources  to  Lease  17  (high  estimate  only)
     reflecting a probability of only 10 per cent that the resource  equals or
     exceeds the estimated  amount given the limited  amount of data available
     on this lease.  Major assumptions used in the  classification of inferred
     resources for Lease 17 were average  in-place  bitumen  content of 10 per
     cent to total weight and ore  thickness of  approximately  15 metres over
     less than half the lease area.  Due to the level of  uncertainty  on this
     lease,  it  should  not be  assumed  that all or any part of an  inferred
     resource will be upgraded as a result of continued exploration.

<PAGE>

Undeveloped Land

During 2005, Shell acquired  additional  mineable oil sands acreage  including
leases 15, 309, 310, 351, 352, 631 and 632. These leases were acquired through
public land auctions held by the  Government of Alberta.  Pursuant to the AMI,
Western has rights to participate to a 20 per cent interest in the development
of these leases.

     A second addition to the undeveloped  land base are five heavy oil leases
recently  purchased by Chevron.  It is believed these leases would be amenable
to extract bitumen through in-situ recovery methods.  Western has the right to
participate to a 20 per cent undivided interest in these leases. Our right may
be exercised  upon Chevron  providing us with formal  notice of the  purchase,
followed by our response within 60 days of that notice regarding our intent to
participate, together with the applicable payment.

     A further addition to this already  extensive land position is Lease 353,
which Western itself  acquired  during 2005,  representing  8,225 acres.  This
lease  is also  considered  in-situ  in  nature.  Western  holds a 60 per cent
interest in this lease as both Shell and Chevron have  elected to  participate
to a 20 per  cent  interest.  Western  significantly  increased  its  internal
organizational  capabilities in 2004 and 2005 by adding senior technical staff
to develop our in-situ strategy.

     Combining  all of the leases under the AMI,  the acreage  position in the
Athabasca  region now approaches  284,000 acres (60,000 acres net to Western),
more  than   doubling  the  land  base   compared  to  2004.  Of  this  total,
approximately 71 per cent represents  mineable  leases,  with the remaining 29
per cent considered in-situ. The leases recently acquired by all Joint Venture
partners have not yet been evaluated for resource potential;  however, several
are located adjacent to leases where resource evaluations have been conducted.
An  extensive  core-hole  drilling  program  will be  conducted  over the next
several  years on all of the newly  acquired  leases to evaluate  the resource
potential.  The  leases  recently  acquired  by  Shell  could  potentially  be
developed  as an  extension to the AOSP's  continuous  construction  expansion
strategy.

     The  exploration  and  development of this  significant  land base,  both
mineable  and  in-situ,  could  involve a  substantial  and  material  capital
commitment  on the  part  of  Western  to  maintain  our  rights.  Assessments
regarding Western's  involvement are always made in the context of maintaining
the integrity of our financial position and creating shareholder value.


C O R P O R A T E   R E S U L T S

Research and Business Development

A small  portion of  Western's  capital  budget is  directed  to new  business
development  activities.  These activities  include:  research and development
efforts with the  objective of  identifying  ways to add value to our existing
assets;  the  addition of some  internal  technical  capabilities  in order to
evaluate opportunities as they arise either through our Joint Venture partners
or independently; and finally, as part of Western's long-range strategy, plans
include  expanding  our  organizational   capabilities  to  evaluate  business
opportunities,   domestically   or   internationally,   by  taking   our  core
competencies  and skills and  applying  them to new  ventures  that  represent
long-life projects with significant  hydrocarbon  resource potential.  Western
incurred $10.7 million for research and business development expenses in 2005,
of which $5.0 million relates specifically to AOSP-related  research projects.
In 2004, Western recorded $4.7 million for research and business  development,
which related entirely to the impairment of a previously  capitalized research
project.  Amounts  are higher  compared  to the prior  year  period as Western
continues to add significant  technical and  professional  staff to source and
investigate business development activities.

General and Administrative Expenses

General and  administrative  expenses  ("G&A")  were $11.3  million in 2005 or
$0.97 per barrel  compared  to $8.1  million or $0.82 per barrel in 2004.  The
increase  is  largely  a  function  of  Western   analyzing  certain  business
development  activities that result in higher levels of professional and legal
fees,  travel and other  corporate  expenses  that arise in  conducting  these
evaluations.  It also reflects  additional  professional costs incurred during
2005 due to increased public company compliance requirements compared to 2004.


<PAGE>

Insurance Expenses

Insurance expenses were $8.0 million in 2005 compared to $9.4 million in 2004.
Western  maintains  insurance  policies  covering  property  damage,  business
interruption,   commercial   general  liability  and  directors  and  officers
liability,  in addition to various  corporate  policies.  Insurance expense in
2005 is  lower  than the  previous  year due to a  reduction  in the  premiums
associated with our policies and the strengthening of the Cdn/US exchange rate
as these premiums are paid in US dollars. There were no material modifications
in coverage compared to the prior year.

     We are  expecting  insurance  expenses to increase in 2006 as a result of
higher  limits  on such  policies  as  business  interruption,  together  with
increased  premiums charged by insurance  carriers on our corporate  policies,
given worldwide events in the insurance marketplace.

Interest Expense

During 2005,  total interest  charges were $58.2  million,  $3.0 million lower
than 2004.  The 2005 expense of $58.2  million is  comprised of $54.3  million
related to interest  charges on our debt  obligations  (2004 - $59.1 million),
$2.6 million (2004 - $2.0 million) on our capital lease  obligations  and $1.3
million  (2004 - $nil) on our option  premium  liability.  The option  premium
liability relates to Western's new strategic crude oil risk management program
implemented  in the  third  quarter  of 2005 and the  decision  to  defer  the
premiums  associated  with  the put  and  call  options  purchased  and  sold,
respectively.  Imbedded in the prices of the  deferred  options is a financing
charge that is reported as interest expense.

     Western's  debt  obligations  include US$450 million Senior Secured Notes
and a $340 million Revolving Credit Facility.  The average  percentage cost of
our debt  increased over last year due to Western  aggressively  repaying debt
under  its  Revolving  Credit  Facility.  As this  debt is  priced  at a lower
interest  rate,  the average  overall  interest rate will  increase  since the
Senior Notes represent a larger  percentage of the outstanding debt. The Notes
bear  interest at 8.375 per cent and are not callable  before  their  maturity
date of May 1, 2012.  Western's  ability to meet  fixed debt  servicing  costs
continues  to improve  which can be measured by the interest  coverage  ratio.
This  ratio has  improved  nearly  seven-fold  over the last two  years,  when
initially Western's leverage was significantly higher than at the end of 2005.
Interest  expense on a per barrel  basis has also  decreased as debt is repaid
and  production   achieves   sustained  rates  meeting  or  exceeding   design
specifications.

     The table on page 32 summarizes our interest  expense and average cost of
debt for the past two fiscal years.

-------------------------------------------------------------------------------
Interest and Long-Term Debt Financing
($ thousands, except as indicated)                       2005         2004
-------------------------------------------------------------------------------
Interest Expense
    Interest Expense on Long-Term Debt                 54,324       59,118 (2)
    Interest on Obligations under Capital Lease         2,562        2,036
    Interest on Option Premium Liability                1,279            -
===============================================================================
    Total Interest Expense                             58,165       61,154
===============================================================================
Long-Term Debt Financing
    US$450 Million Senior Secured Notes (1)           524,655      541,620
    Revolving and Senior Credit Facilities             41,000      216,000 (2)
===============================================================================
    Total Long-Term Debt                              565,655      757,620
===============================================================================
Average Long-Term Debt Level                          661,638      809,100
Average Cost of Long-Term Debt (3)                       8.21%        7.31%
===============================================================================

<PAGE>

(1)  Under  Canadian  GAAP,  the Senior Secured Notes are recorded in Canadian
     dollars  at  exchange  rates  in  effect  at  each  balance  sheet  date.
     Unrealized  foreign  exchange  gains or losses are then  included  on the
     Consolidated Statement of Operations.
(2)  For  comparative  purposes,  amounts  include the $95  million  principal
     outstanding  under the $100  million  Senior  Credit  Facility,  which is
     classified for accounting purposes as short-term  liabilities pursuant to
     its maturity on April 23, 2005.
(3)  Calculated  by dividing  the interest  expense on  long-term  debt by the
     average long-term debt balance outstanding during the year.


Depreciation, Depletion and Amortization

In 2005,  Western  recorded  $50.7  million  as  depreciation,  depletion  and
amortization   expense  compared  to  $44.5  million  in  2004.  Depletion  is
calculated  on a unit of  production  basis for our share of  Project  capital
costs,  while  previously  deferred  financing  charges  are  amortized  on  a
straight-line  basis  over  the  remaining  life of the debt  facilities.  The
increase  for  2005 is  primarily  a  result  of an 18 per  cent  increase  in
production in 2005 versus 2004.

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------
Depreciation, Depletion &Amortization
Year ended December 31                                              2005                          2004
---------------------------------------------------------------------------------------------------------------

                                                      ($ thousands)       $/bbl    ($ thousands)        $/bbl
---------------------------------------------------------------------------------------------------------------
<S>                                                   <C>                <C>            <C>            <C>
Depreciation and Depletion                                   48,206        4.13           41,933         4.23
Amortization                                                  2,532        0.22            2,582         0.26
===============================================================================================================
Total Depreciation, Depletion and Amortization               50,738        4.35           44,515         4.49
===============================================================================================================
</TABLE>

Foreign Exchange

In 2005, WTI averaged  US$56.56 per barrel  compared to US$41.40 per barrel in
2004,  representing a 37 per cent increase.  This significant  appreciation in
the commodity  price was offset  somewhat by a  strengthening  in the Canadian
dollar  relative to the US dollar.  For Western,  the  negative  impact of the
foreign  exchange  rate  increase  on  revenue  was  somewhat  offset by lower
interest  costs  expressed  in Canadian  dollars on our US dollar  denominated
Senior Secured Notes and a reduced liability (as measured in Canadian dollars)
associated  with this debt. In 2005,  Western  recorded an unrealized  foreign
exchange  gain of $17.0  million  compared to a gain of $40.0  million in 2004
relating to the conversion of the Senior Secured Notes to Canadian dollars. As
reference  points,  the noon-day closing foreign exchange rate on December 31,
2005 was $0.8577  US/Cdn  compared to $0.8308  US/Cdn on December 31, 2004. In
terms of average  noon-day rates for the respective  periods,  fiscal 2005 was
$0.8254 US/Cdn compared to $0.7683 US/Cdn for fiscal 2004.

Income Taxes

Western has sizeable tax pools totalling $1.4 billion that were accumulated in
conjunction  with our 20 per  cent  share of the  construction  costs  for the
Muskeg River Mine and Extraction  Plant and the Scotford  Upgrader.  These tax
pools will be used to offset future taxable income and extend the time horizon
before we pay cash taxes.

     For the year ended  December 31, 2005,  Western  recorded a future income
tax liability of $56.4 million  compared to a future income tax asset of $14.5
million at December 31, 2004. Western recognized  approximately  $71.0 million
of future income tax expense during the year as we had record profitability in
2005. During 2005, we expensed $3.0 million (2004 - $1.7 million) with respect
to the  Large  Corporations  Tax.  No other  current  taxes  are  payable  and
Western's cash tax horizon is estimated to be 2010 given a long-term WTI price
of US$55.00 to US$60.00 and a US/Cdn foreign exchange rate of $0.85. Western's
forecasted  cash tax horizon is predicated on the successful  execution of the
AOSP expansion initiatives that would see gross AOSP production exceed 500,000
barrels per day.


<PAGE>

     Commencing in the latter part of 2005,  discussions were held between the
AOSP  and  the   Canada   Revenue   Agency   ("CRA")   regarding   the  proper
characterization of certain expenditures  included in the Canadian exploration
expenses  in those  years.  These  discussions  may  result in a change to the
treatment of certain expenditures renounced pursuant to Western's flow-through
share  offerings in prior  years.  Refer to the section  titled  "Flow-Through
Shares" and Western's financial statements (Note19).

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------
Tax Pools
December 31 ($ thousands)                                        2005           2004
--------------------------------------------------------------------------------------
<S>                                                         <C>            <C>
Canadian Exploration Expense                                   89,140        141,327
Canadian Development Expense                                   23,657         33,795
Canadian Exploration and Development Overhead Expense               -              -
Cumulative Eligible Capital                                     7,925          7,479
Capital Cost Allowance                                        126,001         89,194
Accelerated Capital Cost Allowance                          1,090,155      1,087,056
======================================================================================
Total Depreciable Tax Pools                                 1,336,878      1,358,851
Loss Carry Forwards                                            14,000        163,740
Financing and Share Issue Costs                                 9,596         15,130
======================================================================================
Total Tax Pools                                             1,360,474      1,537,721
======================================================================================
</TABLE>


Net Earnings

Net earnings increased  seven-fold,  reaching $149.4 million ($0.93 per share)
in 2005, compared to $19.5 million ($0.12 per share) in 2004. Earnings for the
year reflect $17.0 million  ($14.1  million net of tax) of unrealized  foreign
exchange  gains on our US$450  million  Senior  Secured Notes, a $13.5 million
($9.1 million net of tax) unrealized gain on risk management  activities and a
future income tax expense of $71.0 million.  Earnings before interest,  taxes,
depreciation, depletion and amortization,  stock-based compensation, accretion
on asset  retirement  obligation,  foreign  exchange gains and risk management
gains  were  $307.0  million.  Cash flow from  operations,  before  changes in
non-cash  working  capital,  was  $244.2  million  ($1.52  per  share) in 2005
compared to $23.0  million  ($0.15 per share) in 2004.  Excluding the negative
impact of  fixed-price  crude swaps,  earnings  and cash flow from  operations
would have been  $259.8  million  and  $354.6  million,  respectively.  Robust
commodity prices,  together with sustained reliable operations over the course
of the  year,  resulted  in a new  annual  record  for  EBITDAX  for  Western.
Excluding the negative  impact of the fixed-price  crude swaps,  EBITDAX would
have equalled $417.4 million. Western's fixed price hedging program expired at
the end of fiscal 2005 and,  therefore,  Western will participate to a greater
extent in actual  commodity prices than it experienced in 2004 and 2005 should
prices remain at these levels.

The table below provides the reconciliation  between net earnings attributable
to common shareholders,  cash flow from operations (before changes in non-cash
working capital) and EBITDAX.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
Reconciliation:Net Earnings to EBITDAX
December 31 ($ thousands)                                                 2005          2004           2003
--------------------------------------------------------------------------------------------------------------
                                                                                                 (restated)
<S>                                                                    <C>            <C>        <C>
Net Earnings Attributable to Common Shareholders                       149,449        19,452         15,003
Add (Deduct):
    Depreciation, Depletion and Amortization                            50,738        44,515         27,531
    Accretion on Asset Retirement Obligation                               562           471            471
    Stock-Based Compensation                                             3,149           967            278
    Impairment of Long-lived Assets                                          -         4,733              -
</TABLE>

<PAGE>

<TABLE>
<S>                                                                    <C>            <C>        <C>
    Unrealized Foreign Exchange Gain                                   (17,803)      (39,960)       (35,280)
    Unrealized Risk Management Gain                                    (13,450)            -              -
    Future Income Tax Expense (Recovery)                                70,956        (7,104)        (4,330)
    Interest Expense on Option Premium Liability                         1,278             -              -
    Charge for Convertible Notes                                             -             -          2,130
    Cash Settlement on Asset Retirement Obligations                        (52)            -              -
    Cash Settlement on Performance Share Units                            (596)          (30)             -
==============================================================================================================
Cash Flow from Operations, before Changes in
    Non-Cash Working Capital                                           244,231        23,044          5,803
Add (Deduct):
    Interest (excluding interest on Option Premium Liability)           56,887        61,154         38,429
    Realized Foreign Exchange Loss                                       2,242         1,610            304
    Large Corporations Tax                                               3,000         1,749          3,079
    Cash Settlement on Asset Retirement Obligations                         52             -              -
    Cash Settlement on Performance Share Units                             596            30              -
==============================================================================================================
EBITDAX                                                                307,008        87,587         47,615
==============================================================================================================
</TABLE>

Please refer to page 44 for a discussion of non-GAAP financial measures.


Quarterly Information

The following table summarizes key financial  information on a quarterly basis
for the last two fiscal years.

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------------
Quarterly Information
($ millions, except per share amounts)                                Q1          Q2          Q3         Q4       Total
-----------------------------------------------------------------------------------------------------------------------------
<S>                                                                 <C>         <C>         <C>        <C>         <C>
2005
Net Revenue                                                           91.7       148.2       185.7      165.8       591.4
Capital Expenditures, Net                                             17.5       (12.9)       16.0       26.2        46.8
Long-Term Debt                                                       773.3       755.5       597.5      565.7       565.7
Cash Flow from Operations (1)                                         10.8        68.0        95.0       70.4       244.2
Cash Flow per Share (2) (5) (6)                                       0.07        0.42        0.59       0.44        1.52
Earnings (Loss) Attributable to Common Shareholders (3) (4)           (1.9)       28.7        79.3       43.3       149.4
Earnings (Loss) per Share - Basic (3) (6)                            (0.01)       0.18        0.50       0.27        0.93
- Diluted (3) (6)                                                    (0.01)       0.18        0.49       0.27        0.92
=============================================================================================================================

2004
Net Revenue                                                           82.7        93.3       104.1       40.9       321.0
Capital Expenditures, Net                                              5.5         7.3        13.5       13.8        40.0
Long-term Debt                                                       852.7       715.2       638.8      662.6       662.6
Cash Flow from Operations (1)                                          9.0        19.4        32.5      (37.9)       23.0
Cash Flow per Share (2) (5) (6)                                       0.06        0.12        0.21      (0.24)       0.15
Earnings (Loss) Attributable to Common Shareholders                   (5.7)       (9.2)       42.4       (8.0)       19.5
Earnings (Loss) per Share - Basic (6)                                (0.04)      (0.06)       0.27      (0.05)       0.12
- Diluted (6)                                                        (0.04)      (0.06)       0.26      (0.05)       0.12
=============================================================================================================================
</TABLE>

(1)  Cash flow from operations is expressed before changes in non-cash working
     capital.
(2)  Cash flow per share is calculated as cash flow from operations divided by
     weighted average common shares outstanding,  basic. 2004 amounts restated
     to reflect 3:1 share split effected in May 2005.
(3)  Includes  unrealized  foreign  exchange  gains (losses) on US$450 million
     Senior  Secured  Notes and Option  Premium  Liability:  (Q1 (loss) - $2.7
     million,  Q2 (loss) - $7.2 million,  Q3 - $30.2 million,  Q4(loss) - $2.5
     million).
(4)  Includes unrealized risk management gains (losses) on strategic crude oil
     program (Q1 - nil; Q2 - nil; Q3 - $1.7 million; Q4 - $11.8 million).
(5)  Please refer to page 44 for a discussion of non-GAAP financial measures.
(6)  Per share  amounts  pre-May 2005 have been  restated to reflect 3:1 share
     split effective May 30, 2005. Total amounts may not add due to rounding.

<PAGE>


L I Q U I D I T Y   A N D   F I N A N C I A L   P O S I T I O N

Western's  liquidity and  financial  position has  strengthened  significantly
since its inception. In particular, 2005 represented a record year in terms of
production, earnings and cash flow. Cash flow from operations was used to fund
all of our capital  expenditures during 2005. Excess cash flow of $197 million
was primarily applied to repay bank credit facilities.  As a result, Western's
overall debt to capitalization ratio has improved  substantially.  At year-end
2005, this ratio was 50 per cent, down from its high of 66 per cent at the end
of 2003. The  implementation of a strategic crude oil risk management  program
announced in the third quarter of 2005,  covering fiscal years 2007 through to
2009,  will provide  certainty of cash flow during this time period to provide
the funding of a majority of our expansion  capital needs in light of upcoming
capital expenditures associated with the first of multiple phases of expansion
of the AOSP.  Incremental debt may be required to fund future expansion phases
and other new business development initiatives as they arise.

Debt Financing

In 2005, we maintained  our US$450 million of Senior Secured Notes as they are
non-callable with a maturity of May 1, 2012. We were also successful in making
two amendments to our bank credit facilities. First, in March 2005, we amended
the $240 million  Revolving  Credit Facility (the "$240 million  Revolver") to
consolidate  its  commitments  and the $100 million  Senior  Credit  Facility,
whereby all terms and covenants of the $240 million  Revolver apply to the new
combined facility.  This consolidation feature was specifically  structured as
part of the $240  million  Revolver at its  inception.  Second,  this new $340
million  Revolving  Credit Facility  ("Revolving  Credit  Facility") was again
amended  in  October  2005,  with  respect to  pricing,  to reflect  Western's
improved financial  profile.  The amendments reduced the pricing to nil to 225
basis points over the bank prime lending rate, bankers acceptances or US LIBOR
notes, as applicable,  which formerly ranged from 100 to 200 basis points.  At
December 31, 2005,  $41 million  (2004 - $216  million) had been drawn on this
facility, with $258 million in unused capacity.  Additionally,  as at December
31, 2005,  letters of credit issued in the amount of $8.9 million (2004 - $8.1
million) were outstanding under the Revolving Credit Facility.

     The size of the Revolving  Credit  Facility is a function of the value of
the  reserves  attributable  to  Western.  Therefore,  based  on  the  reserve
evaluation  as at  December  31,  2005,  Western  has full  access to the $340
million limit under the Revolving  Credit  Facility.  As Western and its Joint
Venture  Participants  commit to expansions  and the  associated  reserves are
attributed  proratably  to each  partner,  Western  may  have the  ability  to
increase its debt capacity beyond the current limits.

Equity Financing

Cash flow from  operations was more than sufficient to fund the modest capital
expenditures and working capital  commitments during 2005. We will continue to
assess all forms of financing  vehicles,  both in the debt and equity  capital
markets,  to ensure  Western's  capital  structure is highly  efficient in any
given circumstance.

     The share  performance graph compares the yearly change in the cumulative
total shareholder return of a $100 investment made on December 31, 2000 in the
Company's  Common Shares with the cumulative total return of the S&P/TSX Total
Return  Composite  Index and the S&P/TSX  Capped  Energy  Index,  assuming the
reinvestment  of  dividends,  where  applicable,  for the  comparable  period.
Western  has  significantly  outperformed  both  indices  since the  Company's
inception.


<PAGE>

-------------------------------------------------------------------------------
Equity Capital
At December 31                                                           2005
-------------------------------------------------------------------------------
Issued and Outstanding:
    Common Shares                                                 160,518,041
Outstanding:
    Stock Options                                                   3,527,932
-------------------------------------------------------------------------------
Fully Diluted Number of Shares                                    164,045,973
-------------------------------------------------------------------------------


Capital Expenditures

Capital  expenditure  programs are conducted under the Joint Venture Agreement
whereby we  participate  in the  operations  of the Project to our 20 per cent
working  interest,  and we are  responsible  for our  respective  share of the
costs.  Western also incurs capital expenditures of its own accord as a result
of new business development  initiatives.  Net capital  expenditures  totalled
$46.8 million in 2005  compared to $40.0 million in 2004.  The majority of the
gross increase in capital expenditures relates primarily to increased business
development  activity  which rose to $13.3  million in 2005  compared  to $3.8
million in 2004.

-------------------------------------------------------------------------------
Capital Expenditures
December 31 ($ millions)                                     2005        2004
-------------------------------------------------------------------------------
Project-Related Capital
    Profitability Capital                                    31.2        16.1
    Growth Initiatives                                        9.0         7.1
    Long-lead Items                                           5.6         -
    Sustaining Capital                                        5.8        15.8
===============================================================================
Total Project-Related Capital                                51.6        39.0
Business Development and General Corporate Expenditures      13.3         3.8
Capitalized Insurance Costs                                   4.4         3.6
Insurance Proceeds                                          (22.5)       (6.4)
===============================================================================
Net Capital Expenditures                                     46.8        40.0
===============================================================================

Analysis of Cash Resources

Cash balances  totalled $5.6 million at the end of 2005,  slightly higher than
the $3.7  million at December 31, 2004.  Cash inflows  included net  operating
cash flow of $244.2  million,  insurance  proceeds of $22.5 million and equity
proceeds of $2.7  million from the exercise of stock  options.  Cash  outflows
included  repayments of long-term debt and obligations under capital leases of
$176.3  million,  capital  expenditures  of $69.4 million,  a working  capital
decrease of $21.7 million and an increase in deferred charges of $0.2 million.

     Record cash flow was generated in 2005 and cash flow in excess of capital
expenditures  was applied to reduce  outstanding  bank  facilities.  Western's
strategy is to continue to apply  excess cash flow to bank  facilities  to the
extent of outstanding  balances.  In 2006, our capital  expenditure program is
projected to increase to $250 million,  representing  a combination of current
base Project  capital,  capital  associated with the first AOSP expansion,  as
well as capital allocated to identifying new business  opportunities  where we
can utilize our expertise to deliver further  shareholder value. To the extent
possible, we will strive to maintain a minimal cash balance.


<PAGE>

Contractual Obligations and Commitments

Western has assumed  various  contractual  obligations  and commitments in the
normal course of our operations.  Summarized  below are significant  financial
obligations  that are known as of February 16, 2006, and represent future cash
payments that are required  under  existing  contractual  agreements.  We have
entered  into these  agreements  either  directly or as a partner in the Joint
Venture.  Feedstocks are included in the table below to comply with continuous
disclosure obligations in Canada;  however,  Western could sell these products
back  to the  market  and  eliminate  any  negative  impact  in the  event  of
operational curtailments.

<TABLE>
<CAPTION>
Contractual Obligations and Commitments (1)
                                                                          Payments Due by Period
-------------------------------------------------------------------------------------------------------------------------
                                                   Less Than                                       After
($)                                                   1 Year     1 - 3 Years   4 - 5 Years       5 Years          Total
-------------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>          <C>           <C>             <C>             <C>
US$450 Million Senior Secured Notes                        -              -              -       524,655        524,655
Revolving Credit Facility (2)                              -              -              -        41,000         41,000
Obligations under Capital Lease                        1,340          2,680          2,680        43,566         50,266
Option Premium Liability                                   -         95,642              -             -         95,642
Feedstocks                                           106,423        128,758         18,242        64,138        317,561
Pipelines and Utilities                               39,715         68,337         69,890       556,036        733,978
Mobile Equipment Lease                                 3,647         11,941         26,740             -         42,328
-------------------------------------------------------------------------------------------------------------------------
Total Contractual Obligations                        151,125        307,358        117,552     1,229,395      1,805,430
-------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  In  addition,  we  have an  obligation  to fund  Western's  share  of the
     Project's  Pension  Fund and have made  commitments  related  to our risk
     management  program:   see  Notes  17  and  18,   respectively,   of  the
     Consolidated Financial Statements.
(2)  The Revolving  Credit  Facility is a three-year  bank  facility  maturing
     initially  on October  31,  2008,  extendible  annually  at the  lenders'
     discretion. Management considers this to be part of our long-term capital
     structure.

Insurance Claims

At the beginning of the year, Western had two large claims outstanding: at the
Joint  Venture  level,  a $500 million  ($100  million net to Western) loss of
profits claim stemming from the fire at the Mine on January 6, 2003,  commonly
referred to as Section III, and a  stand-alone  Western  claim of $200 million
pursuant to our Cost Overrun and Project Delay Policy commonly  referred to as
Section IV. In the second quarter of 2005, the Joint Venture was successful in
settlement proceedings with the named insurers on Section III in the amount of
$220  million ($44 million net to  Western).  To date,  Western,  has received
$19.4 million of its share of this  settlement  amount as certain  insurers on
Section  III are also named  insurers  on  Section  IV,  which  have  withheld
insurance  proceeds  payable to Western.  We hope to receive  the  outstanding
amounts  upon  conclusion  of Section IV  arbitration  proceedings.  Costs and
premiums   associated  with  Section  III  were  capitalized  as  Western  was
pre-commercial operations at that time and, as such, amounts received pursuant
to this settlement were reported as a reduction in capital assets.

     Arbitration  proceedings  under the terms of Section IV of Western's cost
overrun and Project delay insurance  policy have been initiated to resolve the
disputes with  insurers  surrounding  the claims for payment  pursuant to this
policy. In order to preserve  Western's rights regarding this policy,  Western
has filed  insurance  claims for the full  limit of the  policy,  namely  $200
million,  and we will also be seeking  interest and  punitive  and  aggravated
damages.  A number of  procedural  motions have been heard to date and further
motions  are  expected  to  occur  prior  to  the  commencement  of  the  main
arbitration hearing. Some of the decisions relating to the preliminary motions
have been  appealed in the past and one is currently  in appeal,  resulting in
delays  to the  commencement  of the main  arbitration  hearing,  which is now
expected  to  occur  in  2007.  We  continue  to work  toward  a  satisfactory
conclusion to these proceedings.

     Similar to Section III,  there are also amounts being withheld by certain
insurers  relating  to the January 6, 2003  physical  property  damage  claim,
commonly referred to as Section I. To date, Western has received $16.1 million
on this  claim,  with  $19.4  million  outstanding.  The  principal  amount of
Western's  outstanding  insurance  claims is $244 million.  Other than amounts
collected up to December 31, 2005, no outstanding  amounts are recorded in our
financial statements nor are they included in any of our financing strategies.


<PAGE>

Flow-Through Shares

In  connection  with the  issuance  of  flow-through  shares in 2001 and 2002,
Western  renounced  Canadian  exploration  expenses in the aggregate amount of
$29.2  million  and  $19.5  million,  respectively.  Under  the  mechanics  of
renouncing qualifying expenditures pursuant to flow-through shares, individual
shareholders  can reduce  their  income  subject  to  personal  income  taxes.
Commencing in the latter part of the year,  discussions  were held between the
AOSP and the CRA regarding the proper characterization of certain expenditures
included  in the  Canadian  exploration  expenses in those  years.  If the CRA
successfully  asserts a change in the  characterization of these expenditures,
any  resulting   reduction  in  the   renunciations   could  impact  Western's
obligations under the indemnity provisions in the subscription  agreements and
in turn, will impact Western's reported results.  The subscription  agreements
for  such   flow-through   shares   stipulate  that  Western  has  indemnified
subscribers for an amount equal to the tax payable and any associated interest
by the subscribers if such  renunciations are reduced under the Income Tax Act
(Canada).

Fourth Quarter 2005

Western  achieved  a third  consecutive  quarter of record  production  in the
fourth quarter of 2005,  averaging  35,572 barrels per day.  Earnings and cash
flow for the fourth  quarter were robust when  compared to previous  quarters.
Record  fourth   quarter   production,   however,   did  not  translate   into
corresponding  record  earnings  or cash flow due to several  factors.  First,
similar  to the  fourth  quarter of 2004,  the heavy oil  differential  to WTI
increased in the last quarter of the year to  approximately  42 per cent. This
adversely  impacted overall sales price realizations as a portion of our sales
stream  received a larger  discount  compared to the prior quarter,  where the
average differential to WTI was approximately 32 per cent. Second, the average
WTI price for the fourth quarter was $60.02 per barrel  compared to $63.19 per
barrel for the third quarter of 2005. As underlying  crude oil prices decline,
our cash flow and profitability  decrease  accordingly,  as our operations are
sensitive to fluctuations in crude oil prices.  Third, the continued  strength
in the US/Cdn exchange rate adversely impacted financial results.  The average
exchange  rate  for  the  fourth   quarter  was   US/Cdn$0.8524   compared  to
US/Cdn$0.8325  for the third quarter of 2005. To the extent this exchange rate
strengthens,  Western  receives fewer Canadian dollars on its US dollar sales.
Due to these factors, our sales price realizations  totalled $50.65 per barrel
in the fourth quarter compared to $58.79 per barrel for the third quarter.  As
far as operating costs are concerned, natural gas prices increased 57 per cent
in the fourth  quarter  despite  the  decline  in WTI  prices.  NYMEX  closing
settlement  prices averaged  US$12.91/Mcf  for the fourth quarter  compared to
US$8.21/Mcf for the third quarter,  resulting in relatively  higher  operating
costs than what would normally be expected in a decreasing WTI environment.


O U T L O O K   F O R   2 0 0 6

We caution  readers and prospective  investors of the Company's  securities to
not place undue reliance on  forward-looking  information as by its nature, it
is based on current expectations regarding future events that involve a number
of  assumptions,  inherent risks and  uncertainties,  which could cause actual
results to differ  materially from those  anticipated by Western.  These risks
include,  but are not limited to, risks of commodity prices in the marketplace
for crude oil and natural gas; risks associated with the extraction, treatment
and upgrading of mineable oil sands deposits;  risks surrounding the level and
timing of capital  expenditures  required  to  fulfill  the  Project's  growth
strategy;   risks  of  financing  these  growth  initiatives  at  commercially
attractive  levels;  risks of being unable to  participate  in  expansion  and
corresponding  loss of  voting  rights  in the  AOSP;  risks  relating  to the
execution  of  the  Project's  optimization  strategy;   risks  involving  the
uncertainty  of  estimates  involved in the reserve  and  resource  estimation
process and ore body configuration/geometry,  uncertainty in the assessment of

<PAGE>

asset retirement  obligations,  uncertainty in the estimation of future income
taxes,  and  uncertainty in treatment of capital for royalty  purposes;  risks
surrounding health, safety and environmental matters; risk of foreign exchange
rate  fluctuations;  risks and  uncertainties  associated  with  securing  the
necessary  regulatory approvals for expansion  initiatives;  risks surrounding
major  interruptions in operational  performance  together with any associated
insurance   proceedings   thereto;  and  risks  associated  with  identifying,
negotiating  and completing our other business  development  activities,  both
those  that  relate to oil sands  activities  and  those  that do not,  either
domestically or abroad.

     In 2006, we look forward to achieving continued operational  improvements
as we continue to seek ways to optimize performance at the AOSP. First quarter
results will be impacted by unplanned production  interruptions resulting from
a tear in the main conveyor belt at the Mine that transports  bitumen ore from
the  primary  crushers  to  the  extraction  plant.  Operations  resumed  full
production  design rates in late March on completion of the belt  replacement.
2006 operations will also be impacted by the first full planned  turnaround of
the  entire  Project  during the  second  quarter of this year.  Much care and
planning has been directed to this effort to ensure an  expeditious  return to
full production in mid-2006. Western continues to maintain production guidance
of 145,000 to 150,000  barrels per day (29,000 to 30,000  barrels per day, net
to Western).

     Western's   capital   expenditure   program  for  2006  is  estimated  at
approximately  $250  million,  which is comprised of $71 million for AOSP base
Project improvement capital, $137 million for AOSP growth expenditures and $42
million for  Western-led  corporate  development  initiatives.  Of this latter
amount,  the majority of the  budgeted  capital  relates to oil sands  related
initiatives and downstream opportunities.

     Western does not have any physical  barrels subject to hedging  contracts
for fiscal 2006 and is  well-placed  to take full  advantage of the  continued
strength in  commodity  prices  during the year  should this occur.  Financial
results  for 2006 are  expected  to be more highly  correlated  to  underlying
movements in crude oil prices due to the absence of financial risk  management
instruments.  In addition,  we will  continue to monitor our 2007 to 2009 risk
management positions.

     In 2005, Shell acquired other mineable leases in the Athabasca region and
Western has an option to earn a working  interest in these  additional  leases
upon satisfying certain provisions of the Joint Venture Agreement. Taking into
account these additional leases, together with the right to participate in the
Chevron  heavy  oil  leases  along  with  Western's  operated  in-situ  lease,
translates into a land position,  net to Western,  which has more than doubled
over the past year.  An  extensive  core-hole  drilling  program is planned to
evaluate  these  new  leases  over the next  several  years,  in  addition  to
previously  held leases,  to determine  the resource  potential  available for
future development.

     The AOSP is our core asset and primary  focus.  The expansion  plans that
are underway will bring  Western's  production  from the Project to 100,000 to
120,000  barrels  per day over  the next  eight  to ten  years.  In  addition,
Western's long-term growth strategy includes maintaining under evaluation four
to six  potentially  significant  project  opportunities,  each  of  which  is
designed  to  create  long-term  shareholder  value.  These  projects  include
research  and  development  efforts  to  add  value  to our  existing  assets,
downstream initiatives to reduce our exposure to heavy oil differentials,  and
identifying and evaluating  opportunities in resource development of oil sands
and other ventures with significant long-life hydrocarbon resource potential.


R I S K   A N D   S U C C E S S   F A C T O R S   R E L A T I N G   T O
O   W E S T E R N

Western  faces a number  of risks  that we need to manage  in  conducting  our
business affairs. The following discussion identifies some of our key areas of
exposure and, where  applicable,  sets forth measures  undertaken to reduce or
mitigate  these  exposures.  A complete  discussion  of risk  factors that may
impact our business is provided in our Annual Information Form.


<PAGE>

Financial Risks

The table below  details the  sensitivities  of our cash flow and net earnings
per share to certain relevant operating factors of the Project for 2006.

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------------------
SENSITIVITY ANALYSIS
                                                                              Basic                         Basic          Basic
                                                                          Cash Flow       Cash Flow      Earnings       Earnings
Variable                        Sensitivity Case           Variation    ($ millions)   per Share ($)  ($ millions)  per Share ($)
----------------------------------------------------------------------------------------------------------------------------------
<S>                             <C>                   <C>                <C>              <C>          <C>             <C>
Production                                30,000      1,000 bbls/day          19.49            0.12         11.90           0.07
Oil Price (US$WTI/bbl)                     56.00         US$1.00/bbl          10.25            0.06          6.87           0.04
Non-Gas Operating Costs                    21.75           $1.00/bbl          10.97            0.07          7.36           0.05
Natural Gas Price (Cdn$/mcf) (1)           10.02           $0.10/Mcf           0.60            0.00          0.40           0.00
Foreign Exchange (2)                        0.86         US/Cdn 0.01           5.93            0.04          0.12           0.04
==================================================================================================================================
</TABLE>

(1)  Each  $1.00 per  thousand  cubic  feet  change in gas price  results in a
     change of $0.44 per barrel in operating costs.
(2)  Excludes  unrealized  foreign  exchange  gains  or  losses  on  long-term
     monetary  items.  The  impact of the  Canadian  dollar  strengthening  by
     US$0.01 would  increase net earnings by $2.7  million,  based on December
     31, 2004 US dollar denominated debt levels.

     Our  financial  results  will  depend  on,  amongst  other  factors,  the
prevailing price of crude oil and the Canadian/US  currency exchange rate. Oil
prices and currency  exchange  rates  fluctuate  significantly  in response to
supply  and demand  factors  beyond  our  control  and could have an impact on
future financial results.  Any prolonged period of low oil prices could result
in a decision by the Joint Venture Owners to suspend or reduce production. Any
such  suspension  or reduction of production  would result in a  corresponding
decrease in our future  revenues  and  earnings  and could  expose  Western to
significant additional expense as a result of certain long-term contracts.  In
addition,  because  natural  gas  comprises  a  substantial  part of  variable
operating  costs,  any  prolonged  period of high  natural  gas  prices  could
negatively impact our future financial results.

     Our debt level and restrictive covenants will have an important impact on
our future operations.  Our ability to make scheduled payments or to refinance
our debt obligations will depend upon our financial and operating performance,
which,  in turn,  will depend on  prevailing  industry  and  general  economic
conditions  beyond our control.  There can be no assurance  that our operating
performance,  cash flow and capital  resources will be sufficient to repay our
debt and other obligations in the future.

     To mitigate  our exposure to these  financial  risks and provide a stable
financial  footing  as we enter  the  first  phase of the AOSP  expansion,  we
recently completed a strategic crude oil risk management program. This program
was  the  culmination  of  extensive  internal  analysis  and  review  and the
recommended  approach was approved by our Board of Directors.  The  overriding
objective  of the risk  management  program  was to ensure the ability to fund
significant  capital  expenditures  in the event of a precipitous  drop in the
crude oil price.  The  program  itself  was a series of put and call  options.
Western  purchased  puts at various  levels and  financed  in part the cost of
these puts by selling call options on lower volumes over the same time period.
The net cost of the program was US$3.74 per put barrel. All options bought and
sold were executed on a deferred  basis.  Hence,  Western made no upfront cash
payment  for these  options  but will do so as each  monthly  option  expires.
Western  deferred the options in order to properly match the  underlying  cash
flow, but, more  importantly,  the implicit  interest rate within the deferred
options  pricing  was lower than  Western's  incremental  borrowing  rate.  An
interest  expense  associated  with this program is a result of this  deferral
strategy. The program is summarized as follows:


<PAGE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------
Risk Management Activities                                          Period (calendar year)
--------------------------------------------------------------------------------------------------
                                                              2007          2008           2009
--------------------------------------------------------------------------------------------------
<S>                                                         <C>           <C>            <C>
Put Options Purchased (bbls/d)                              20,000        20,000         20,000
Call Options Sold (bbls/d)                                  10,000        15,000         15,000
Average Put Strike Price (US$/bbl)                           52.50         54.25          50.50
Average Call Strike Price (US$/bbl)                          92.50         94.25          90.50
==================================================================================================

<CAPTION>
($ thousands)                                                               2005           2004
--------------------------------------------------------------------------------------------------
<S>                                                                      <C>             <C>
Risk Management Asset - Beginning of Period                                    -              -
Net Premium                                                               84,976              -
Increase in Fair Value                                                    13,450              -
==================================================================================================
Risk Management Asset - End of Period                                     98,426              -
==================================================================================================
</TABLE>

     We must finance our share of the Project's  operating costs in light of a
volatile   commodity  price   environment  and  ramp-up   challenges.   Should
insufficient cash flow be generated from operations,  additional financing may
be required to fund capital projects and future expansion  projects.  If there
is a  business  interruption,  we may need  additional  financing  to fund our
activities until Business Interruption Insurance proceeds are received.

Operational and Business Risks

We are currently a single asset  company.  This asset is our investment in oil
sands through the AOSP. As such, the vast majority of our capital expenditures
are directly or indirectly  related to oil sands construction and development,
with  the  majority  of  our  operating  cash  flow  derived  from  oil  sands
operations.

     We are  subject  to the  operational  risks  inherent  in the  oil  sands
business.  Any unplanned  operational outage or slowdown can impact production
levels,  costs  and  financial  results.  Factors  that  could  influence  the
likelihood of this include,  but are not limited to,  uncertainties within the
ore body, extreme weather conditions and mechanical difficulties.

     We sell our share of synthetic  crude oil  production  to  refineries  in
North  America.  These  sales  compete  with the sales of both  synthetic  and
conventional crude oil. Other suppliers of synthetic crude oil exist and there
are  several  additional  projects  being  contemplated.   If  undertaken  and
completed,  these projects will result in a significant increase in the supply
of synthetic crude oil to the market. In addition, not all refineries are able
to  process or refine  synthetic  crude oil.  There can be no  assurance  that
sufficient  market  demand  will exist at all times to absorb our share of the
Project's synthetic crude oil production at economically viable prices.

     As an owner in the AOSP,  we actively  participate  in  operational  risk
management  programs  implemented  by the Joint  Venture to mitigate the above
risks.  Our  exposure  to  operational  risks is also  managed by  maintaining
appropriate  levels of  insurance.  To that end,  in October  2005,  we placed
US$800 million of Property and Business  Interruption  Insurance,  up from the
US$500  million  that was placed  last year as well as our  US$100  million of
Liability  Insurance  to protect  our  ownership  interest  against  losses or
damages to the Owners'  facilities,  to preserve our  operating  income and to
protect against our risk of loss to third parties.

     The Project  depends upon  successful  operation of facilities  owned and
operated  by third  parties.  The Joint  Venture  Owners  are party to certain
agreements  with  third  parties to  provide  for,  among  other  things,  the
following services and utilities:

o    Pipeline transportation is provided through the Corridor Pipeline;
o    Electricity  and steam are provided to the Mine and the Extraction  Plant
     from the Muskeg River cogeneration facility;
o    Transportation of natural gas to the Muskeg River  cogeneration  facility
     is provided by the ATCO pipeline;
o    Hydrogen is provided to the Upgrader from the hydrogen manufacturing unit
     ("HMU") and Dow Chemicals Canada Inc. ("Dow"); and
o    Electricity  and steam are  provided to the  Upgrader  from the  Upgrader
     cogeneration facility.


<PAGE>

     All of these  third-party  arrangements  are  critical to the  successful
operation of the Project.  Disruptions  related to these facilities could have
an adverse impact on future financial results.

     We may be faced with competition from other industry  participants in the
oil sands  business.  This  could  take the form of  competition  for  skilled
people, increased demands on the Fort McMurray infrastructure (housing, roads,
schools,  etc.) or higher  prices for the products  and  services  required to
operate and maintain the plant.  We have  significant  plans for expansion and
the strong  working  relationship  the  Project has  developed  with the trade
unions will be an important factor in our future activities.  Our relationship
with our employees and  provincial  building  trade unions is important to our
future because poor productivity and work disruptions may adversely affect the
Project - whether in construction or in operations.

     Western has announced its business strategy of investigating,  at any one
time, several separate projects that could  significantly  enhance shareholder
value.  Some of  these  projects  may be  located  outside  of  Canada.  These
potential investments may involve such risks as uncertain political, economic,
legal, regulatory and tax environments.

Environmental Risks

Canada is a signatory to the United  Nations  Framework  Convention on Climate
Change and has  ratified  the Kyoto  Protocol  established  thereunder  to set
legally  binding  targets to reduce  nationwide  emissions of carbon  dioxide,
methane,  nitrous oxide and other  so-called  greenhouse  gases  ("GHG").  The
Project will be a significant producer of some GHGs covered by the treaty. The
Government  of Canada has put forward a Climate  Change Plan for Canada  which
suggests further legislation will set GHG emission reduction  requirements for
various  industrial  activities,  including  oil  and gas  production.  Future
federal  legislation,  together with existing  provincial  emission  reduction
legislation, such as in Alberta's Climate Change and Emissions Management Act,
may require the reduction of emissions  and/or  emissions  intensity  from the
Project. The direct or indirect costs of such legislation may adversely affect
the Project.  There can be no assurance that future  environmental  approvals,
laws or regulations  will not adversely  impact the Owners' ability to operate
the Project or increase or maintain production or will not increase unit costs
of  production.  Equipment  from  suppliers  that  can  meet  future  emission
standards  or other  environmental  requirements  may not be  available  on an
economic basis, or at all, and other methods of reducing emissions to required
levels may significantly increase operating costs or reduce output.

     We will be responsible for compliance with terms and conditions set forth
in the  Project's  environmental  and  regulatory  approvals  and all laws and
regulations  regarding the  decommissioning and abandonment of the Project and
reclamation  of its  lands.  The  costs  related  to these  activities  may be
substantially  higher  than  anticipated.  It is not  possible  to  accurately
predict these costs since they will be a function of  regulatory  requirements
at the time and the  value of the  equipment  salvaged.  In  addition,  to the
extent  we do not meet the  minimum  credit  rating  required  under the Joint
Venture  agreement,  we must  establish and fund a reclamation  trust fund. We
currently  do not  hold  the  minimum  credit  rating.  Even if we do hold the
minimum credit rating in the future,  it may be determined  that it is prudent
or be required by applicable  laws or regulations to establish and fund one or
more  additional  funds to  provide  for  payment  of future  decommissioning,
abandonment and reclamation  costs. Even if we conclude that the establishment
of such a fund is prudent or required,  we may lack the financial resources to
do so.

     The Joint  Venture  partners  have  established  programs  to monitor and
report on environmental performance including reportable incidents, spills and
compliance issues. In addition,  comprehensive  quarterly reports are prepared
covering all aspects of health, safety and sustainable development on Lease 13
and the Upgrader to ensure that the Project is in compliance with all laws and
regulations  and that  management is accountable  for  performance  set by the
Joint Venture Owners.


<PAGE>

N O N - G A A P   F I N A N C I A L   M E A S U R E S

Western  includes cash flow from operations per share,  netback per barrel and
earnings before interest,  taxes,  depreciation,  depletion and  amortization,
stock-based  compensation,  accretion on asset retirement obligation,  foreign
exchange gains and risk management gains ("EBITDAX") as investors may use this
information  to better  analyze our  operating  performance.  We also  include
certain per barrel  information,  such as  realized  crude oil sales price and
operating  costs,  to provide per unit  numbers  that can be compared  against
industry  benchmarks,  such as the  Edmonton  PAR  benchmark.  The  additional
information  should not be  considered  in isolation  or as a  substitute  for
measures  of  operating  performance  prepared  in  accordance  with  Canadian
Generally Accepted Accounting Principles ("GAAP"). Non-GAAP financial measures
do not have any  standardized  meaning  prescribed  by  Canadian  GAAP and are
therefore  unlikely to be  comparable to similar  measures  presented by other
issuers.  Management  believes  that,  in addition to Net Earnings  (Loss) per
Share  and Net  Earnings  (Loss)  Attributable  to Common  Shareholders  (both
Canadian  GAAP  measures),  Cash Flow from  Operations  per Share and  EBITDAX
provide a better basis for evaluating our operating performance,  as they both
exclude  fluctuations on the US dollar  denominated Senior Secured Notes, risk
management   gains  (losses)  and  certain  other  non-cash  items,   such  as
depreciation, depletion and amortization, and future income tax recoveries. In
addition,  EBITDAX  provides  a useful  indicator  of our  ability to fund our
financing costs and any future capital requirements.


M A N A G E M E N T   C O N T R O L S   A N D   P R O C E D U R E S

As of December 31, 2005, an evaluation was carried out, under the  supervision
of and with the participation of management, including the President and Chief
Executive  Officer and Chief Financial  Officer,  of the  effectiveness of our
disclosure  controls and procedures as defined under  Multilateral  Instrument
52-109.  Based on that evaluation,  the President and Chief Executive  Officer
and Chief Financial  Officer  concluded that the design and operation of these
disclosure controls and procedures were effective.


C R I T I C A L   A C C O U N T I N G   E S T I M A T E S

Western's  critical  accounting  estimates are defined as those estimates that
have a  significant  impact on the  portrayal  of our  financial  position and
operations  and that require  management to make  judgments,  assumptions  and
estimates in the  application of Canadian  GAAP.  Judgments,  assumptions  and
estimates are based on historical experience and other factors that Management
believes  to be  reasonable  under  current  conditions.  As events  occur and
additional information is obtained, these judgments, assumptions and estimates
may be subject to change. We believe the following are the critical accounting
estimates used in the preparation of our Consolidated Financial Statements.

Property, Plant and Equipment ("PP&E")

Western   capitalizes   costs   specifically   related  to  the   acquisition,
exploration,   development   and   construction   of  the  Project  and  other
initiatives.   This  includes  interest,   which  is  capitalized  during  the
construction  and  start-up  phase for each  project.  Depletion  on crude oil
properties is provided over the life of proved and probable reserves on a unit
of production basis,  commenced when the facilities are substantially complete
and after commercial  production has begun.  Other PP&E assets are depreciated
on a straight-line basis over their useful lives, except for lease acquisition
costs and certain Mine assets,  which are amortized and  depreciated  over the
life of proved and probable reserves. Reserve estimates can have a significant
impact  on  earnings,  as  they  are a key  component  to the  calculation  of
depletion.  A  downward  revision  in the  reserve  estimate  would  result in
increased depletion and a reduction of earnings.


<PAGE>

     PP&E assets are reviewed for  impairment  whenever  events or  conditions
indicate that their net carrying amount may not be recoverable  from estimated
future cash flows. If an impairment is identified, the assets are written down
to the estimated fair market value. The calculation of these future cash flows
is dependent  on a number of  estimates,  which  include  reserves,  timing of
production,  crude oil price,  operating cost  estimates and foreign  exchange
rates.  As a result,  future cash flows are subject to significant  management
judgment.

Asset Retirement Obligation

Western  recognizes an asset and a liability for asset retirement  obligations
in the period in which they are incurred by  estimating  the fair value of the
obligation.  We  determine  the fair value by first  estimating  the  expected
timing and amount of cash flow, using  third-party costs that will be required
for  future  dismantlement  and site  restoration,  and then  calculating  the
present value of these future  expenditures using a credit-adjusted  risk-free
rate appropriate for Western.  Any change in timing or amount of the cash flow
subsequent  to  initial  recognition  results  in a change  in the  asset  and
liability,  which then impacts the  depletion  on the asset and the  accretion
charged on the liability. Estimating the timing and amount of third-party cash
flow to  settle  this  obligation  is  inherently  difficult  and is  based on
Management's current experience.

Derivative Financial Instruments

Financial  instruments  that  do not  qualify  as  hedges,  or have  not  been
designated as hedges under  Accounting  Guideline  13, are recorded  using the
mark-to-market  method of accounting  whereby  instruments are recorded in the
Consolidated  Balance Sheet as either an asset or a liability  with changes in
fair value  recognized  in net  earnings.  The fair  values of such  financial
instruments  are based on an  estimate  of the  amounts  that  would have been
received or paid to settle  these  instruments  prior to  maturity.  Financial
instruments that do qualify as hedges under  Accounting  Guideline 13, and are
designated as hedges, are not recognized on the Consolidated Balance Sheet and
gains and losses on the hedge are deferred and  recognized  in revenues in the
period the hedge sale transaction occurs.

Income Tax

Western  follows the liability  method of accounting  for income taxes whereby
future  income  taxes are  recognized  based on the  differences  between  the
carrying  values  of  assets  and  liabilities  reported  in the  Consolidated
Financial  Statements and their respective tax basis. Future income tax assets
and  liabilities are recognized at the tax rates at which  Management  expects
the temporary  differences to reverse.  Management  bases this  expectation on
future earnings,  which require estimates for reserves,  timing of production,
crude oil price,  operating cost estimates and foreign  exchange  rates.  As a
result,  future  earnings are subject to significant  Management  judgment and
changes.

Arrangements Containing a Lease

Through  its 20 per cent  ownership  interest  in AOSP,  Western is party to a
number  of  long-term   third-party   arrangements  to  provide  for  pipeline
transportation of bitumen and upgraded products, and to provide electrical and
thermal energy.  With the issuance of the Emerging Issues  Committee  Abstract
150 (") the  Corporation  is required to  determine  whether any  arrangements
agreed to, committed to or modified after January 1, 2005 contain a lease that
is within the scope of CICA  Section  3065  "Leases".  To date,  none of these
long-term third-party contracts were agreed to, committed to or modified after
January 1, 2005 and  therefore,  the  Corporation  is not required to consider
whether they  contain a lease that is within the scope of CICA  Section  3065.
However,  the AOSP or Western may request  modification of these agreements in
the future to meet certain  requirements related to the AOSP growth plans. Any
modifications   may  result  in  certain   of  these   long-term   third-party
arrangements  being  treated  as  capital  leases,   thereby  increasing  both
Western's assets and liabilities on our Consolidated Balance Sheet.