EXHIBIT 3
                                                                      ---------


MANAGEMENT'S DISCUSSION AND ANALYSIS


The following  discussion of financial  condition and results of operations was
prepared as of February  22,  2007 and should be read in  conjunction  with the
Consolidated  Financial  Statements and Notes thereto.  It offers  Management's
analysis  of the  financial  and  operating  results of Western  Oil Sands Inc.
("Western") 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 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;  size and scope of expansions;  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  Athabasca  Oil  Sands  Project
("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 asset retirement  obligations,  uncertainty in
the  estimation  of future  income  taxes,  uncertainty  in the  estimation  of
stock-based  compensation  and  employee  future  benefits 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. Risks associated with our
international  initiatives  include,  but are not  limited  to,  political  and
economic  conditions  in the  countries  in which we intend to  operate,  risks
associated with acts of insurgency or terrorism,  changes in market conditions,
political  risks,  including  changes in law or  government  policy,  the risks
associated  with  negotiating  with  foreign  governments  and risks  generally
associated with international activity.

      For additional information relating to the risks and uncertainties facing
Western, refer to Western's Annual Information Form for the year ended December
31, 2006 which is available on SEDAR at www.sedar.com.


OVERVIEW

Western Oil Sands Inc. ("Western") is a Canadian corporation whose vision is to
create  shareholder  value through the  opportunity  capture and development of
large, world-class hydrocarbon resources. Western's primary asset is its 20 per
cent  undivided  interest in the Athabasca Oil Sands  Project  ("AOSP").  Shell
Canada Limited  ("Shell") and Chevron Canada Limited  ("Chevron") are the other
Joint  Venture  Owners,  holding  a 60  per  cent  and 20  per  cent  interest,
respectively. The Joint Venture's strategy is to exploit the mining and in-situ
recoverable  bitumen reserves and resources found in oil sands deposits located
in the Athabasca region of Alberta. The initial Joint Venture asset is a mining
and extraction  operation (the Muskeg River Mine) on the west side of Lease 13,
70  kilometres  north of Fort  McMurray,  together  with  associated  upgrading
infrastructure (the Scotford Upgrader) northeast of Edmonton,  Alberta. Current
operations, with the assistance of certain third-party facilities,  including a
493 kilometre  pipeline  connecting the Mine and the Upgrader,  use established
processes to mine oil sands deposits,  extract and upgrade the bitumen into two
streams of synthetic  crude oil,  namely Premium Albian  Synthetic  ("PAS") and
Albian Heavy  Synthetic  ("AHS"),  and vacuum gas oil  ("VGO").  VGO is sold to
Shell under a  long-term  contract  for use in its  adjacent  refinery.  In the

<PAGE>

second  quarter  of 2006,  the first  full plant  turnaround  was  successfully
executed.  Following the turnaround,  production  levels returned to the record
levels  established  during the last quarter of 2005.  Production  optimization
initiatives are planned to continue on the base Project,  with the objective of
achieving  production volumes of approximately  200,000 barrels per day (40,000
barrels  per day net to  Western)  by  2009.  In  terms  of the  base  Project,
reliability  and  availability of the existing AOSP facilities will continue to
be a key focus for the Joint Venture.

      During  2006 and in years  prior,  Western  and the other  Joint  Venture
Owners devoted  considerable time, effort and commitment of capital in planning
and completing the early stage  execution of Expansion 1 of the AOSP. This work
culminated in Western, and the Joint Venture Owners, sanctioning Expansion 1 in
the fourth  quarter of 2006.  Expansion  1 is a 100,000  barrel per day (20,000
barrels  net to  Western)  fully  integrated  expansion  of the  existing  AOSP
facilities,  with new oil sands mining  operations  on Lease 13 and  associated
additional  bitumen  upgrading at the Scotford  Upgrader.  It also includes the
construction  of common upstream  infrastructure  that will be sized to support
future mining  expansions,  consistent with the recent  announcements  from the
Joint Venture that  regulatory  applications  will be filed to seek approval to
produce up to 770,000 barrels per day from Expansions3  through5.  Construction
of a new 42-inch  Corridor  Pipeline  connecting Fort McMurray to Edmonton also
began  in  2006.  This new  pipeline  will  facilitate  the  movement  of up to
1,000,000 barrels per day of production when fully complete.

      Also during 2006,  Western made  noteworthy  progress with respect to its
in-situ development initiative which represents an exciting new opportunity for
Western to create  additional  shareholder  value.  It is estimated that 80 per
cent of the bitumen  resources  in Alberta are in-situ in nature and  currently
too deep to mine through  surface mining  techniques.  In August 2006,  Western
announced  its  decision  to  participate  to its 20 per cent  interest  in the
Chevron-operated Ells River Project in the Athabasca region which has potential
for in-situ  development.  The Ells River  Project is located on  approximately
75,000 gross acres of property  purchased by Chevron in 2005 and 2006.  Chevron
has  assembled a technical  team that is  dedicated  to  feasibility  and other
technical  evaluations  going forward.  Chevron has planned a significant  core
hole  evaluation  drilling  program  over  the  winter  of 2007 to  assess  the
potential of these leases.  In addition,  Western expanded its acreage position
in the Athabasca  region and will operate its own in-situ  project which covers
approximately  21,000 gross acres,  approximately  14,000 acres net to Western.
Early stage planning for Western's in-situ leases is underway and this includes
a core hole evaluation  drilling  program of  approximately 19 wells during the
2007 winter drilling season.

      Western  announced  during  2006  that  it  is  independently  evaluating
alternative  downstream  solutions  beyond  Western's  involvement in the fully
integrated  operation of AOSP  Expansion 1, with the goal of improving  product
yields and sales price  realizations at a lower capital  intensity than current
configurations.  To meet these  goals,  Western  is  committed  to a  long-term
strategy which  involves  commercially-attractive,  cost-effective,  downstream
integration  for  upgrading  bitumen  into light  synthetic  crude oil products
anticipated  to be produced from  Western's  extensive and emerging  mining and
in-situ resources.

      In addition to these key initiatives,  Western,  through its wholly-owned
subsidiary,  WesternZagros  Limited  ("WesternZagros"),  negotiated the initial
form of an  Exploration  and  Production  Sharing  Agreement  ("EPSA") with the
Kurdistan  Regional  Government  ("),  subject to finalization of key terms and
ratification by the KRGto comply with expected  federal  legislation.  The EPSA

<PAGE>

provided for the exploration of conventional  oil and gas in the Federal Region
of  Kurdistan  in  northern  Iraq.  WesternZagros  continues  to  work  towards
ratification  of an  EPSA  with  the KRG  which  is  expected  to  include  the
finalization  of terms including its contract area and the  corresponding  work
program commitments.

      Commodity  prices continued to hover at or near record levels during most
of 2006 and, consequently,  Western achieved near-record cash flow, despite the
56-day  turnaround  in the  second  quarter  of 2006.  As a  result,  Western's
financial  position has substantially  improved as it embarks on Expansion 1 of
the AOSP. Noteworthy operating and financial achievements during 2006 include:

      o  Fourth  quarter  production  averaged  35,515  barrels  per day net to
Western, comparable to the record production of 35,600 barrels per day achieved
in the fourth quarter of 2005;

      o Annual  production  averaged  27,500  barrels  per day net to  Western,
despite the two-month production interruption due to the full turnaround at the
Mine and Upgrader in the second quarter;

      o Near-record  annual cash flow from operations of $228.4  million,  with
record  quarterly  cash  flow from  operations  of  $110.5million  in the third
quarter;

      o Capital  expenditures  of $301.3  million  which were funded  primarily
through  cash  flow  from  operations  supplemented  by a  modest  increase  in
Western's Revolving Credit Facility;

      o Proved and probable reserves  increased 86 per cent from the prior year
to 577 million  barrels  and a best  estimate of  contingent  resources  of 891
million barrels;

      o The lands  associated  with  Western's  proved  and  probable  reserves
represent only  approximately  11 per cent of the more than 69,000 net acres in
which Western has the right to participate;

      o The permit application for the Muskeg River Mine expansion was approved
in December 2006;

      o  Environmentally,  the  Muskeg  River Mine  remains  the only oil sands
mining  operating to have  achieved the  internationally  recognized  ISO 14001
certification; and

      o Over 12 million plus  exposure  hours  recorded in 2006 within the AOSP
resulted  in only a  relatively  minor lost time  incident  and the  recordable
injury frequency rate improved significantly following the turnaround.


EXPANSION 1

During the fourth quarter of 2006, Western,  along with the other Joint Venture
Owners,  announced  its approval of  Expansion 1 of the AOSP.  Expansion 1 is a
100,000 barrel per day (20,000 barrels per day net to Western) fully integrated
expansion of the existing AOSP facilities, with new oil sands mining operations
on the east side of Lease 13, an expansion of the extraction  facilities at the
Muskeg  River Mine and an  expansion  of the  existing  Upgrader  located  near
Edmonton.  The capital cost  estimate for  Expansion 1 is  approximately  $11.2
billion   ($2.2billion  net  to  Western).   Of  the  $11.2  billion  estimate,
approximately  75 per cent is allocated for the actual costs of components  and
construction  labour, 20 per cent represents  owners' costs and  contingencies,
with the  remaining  five per cent  representing  the  conversion  of the total
capital cost to money-of-the-day  prices. Mine production is scheduled to begin
in late 2009 with Upgrader production beginning in late 2010.

      As at the end of December 2006, expenditures of $225.6 million related to
Expansion 1 were  capitalized on Western's  balance sheet.  In order to proceed

<PAGE>

with its  planned  schedule,  the  Project  committed  to major  long lead time
equipment  and  also  incurred  other  pre-construction  expenditures  in 2006.
Western has  budgeted  capital  expenditures  of $555  million for its share of
Expansion  1 for 2007.  For  Expansion  1,  construction  efforts  to date have
focused on  utilities  work  relating to the  construction  of  permanent  camp
facilities,  piling and  foundation  activities  for many of the key components
including the primary  separation cell and de-aerator area and  construction of
potable  water  and  sewage  treatment  plants.  One of  the  key  cost  saving
strategies in the  construction  of the  facilities is the  fabrication of many
modules  off-site.  Efforts in this regard are  proceeding as planned with over
600 modules earmarked for such  construction.  To date, the Project has secured
the  necessary  skilled  labour  required  for an  operation  of  this  nature.
Approximately   2,000   full-time   equivalent   individuals,   representing  a
combination  of  construction  contractors  and  employees of the  engineering,
procurement and construction management  contractors,  are currently working on
this  major  initiative  on behalf  of the Joint  Venture.  This  workforce  is
expected to increase  substantially as the Project moves into full construction
over the next several years.


RESERVES, RESOURCES AND LAND

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

      Within the  Project,  Western  has the  following:  proved  and  probable
reserves which are associated with the existing  operations at the Muskeg River
Mine;  proved and probable  reserves  associated  with Expansion 1 of the AOSP;
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 few  years  which  are  included  under  the  terms of the AMI and are
subject to evaluation for possible future development.


Reserves

GLJ Petroleum  Consultants Ltd. ("GLJ"),  in its report dated February 7, 2007,
independently  estimated  the proved and probable  reserves on the total of the
west side of Lease 13,  which is the current  Muskeg  River Mine,  and the east
side of Lease 13 which  comprises  Expansion  1. All  combined,  there  are 2.9
billion barrels (577 million  barrels  Western working  interest) of proved and
probable  reserves  associated  with the current  Muskeg River Mine and the new
Jackpine  Mine.  (Expansion  1).  Based on GLJ's  forecasted  AOSP's  undiluted
bitumen  production  rate of 175,000  barrels per day for 2007, the proved plus
probable  reserves have a reserve life index of 44 years.  Western  anticipates
substantial  future  reserve  additions as the AOSP Joint Venture moves through
the gating process for the upcoming phases of additional  mining  expansions of
the AOSP,  in  addition  to  potential  reserves  associated  with the  in-situ
projects  that Western and Chevron are pursuing.  Resources  from future mining
expansions will be booked as reserves when the expansions 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 Western's share of
those proved and probable reserves as at December 31, 2006 on a synthetic crude
oil basis utilizing GLJ's forecast of prices and costs.  Synthetic crude oil is

<PAGE>

dry  bitumen,  uplifted by two per cent for proved  reserves and three per cent
for probable reserves as a result of the  hydrocracking/hydrotreating  process.
The following  information relating to Western's reserves and present values of
estimated future net cash flow constitutes  forward-looking statements as it is
based on  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 the volume and value of the reserves  reported below, see "Outlook
for 2007" and "Risk and Success Factors Relating to Western" and, additionally,
the "Risks and  Uncertainties"  contained in Western's Annual  Information Form
for the year ended December 31, 2006.

<TABLE>
<CAPTION>
RESERVES SUMMARY

                                                    Working                  Working Interest
                               Gross    Working    Interest         Present Values 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                         2,479        496         454      12,663      2,957       1,613         913
Probable                         405         81          71       3,554        911         607         452
----------------------------------------------------------------------------------------------------------
Proved Plus Probable           2,884        577         525      16,217      3,868       2,220       1,365
==========================================================================================================
</TABLE>

<TABLE>
<CAPTION>
RESERVES RECONCILIATION (WORKING INTEREST)

                                                                                              Proved Plus
                                                                                        Proved    Probable
-----------------------------------------------------------------------------------------------------------
                                                                                       (mmbbls)    (mmbbls)
<S>                                                                                        <C>         <C>
December 31, 2005                                                                          195         310
Production                                                                                 (10)        (10)
Revisions                                                                                    1           2
Muskeg River Mine Expansion                                                                 90           7
AOSP Expansion 1 Addition                                                                  220         268
-----------------------------------------------------------------------------------------------------------
December 31, 2006                                                                          496         577
===========================================================================================================
</TABLE>


Resources

Within the AOSP,  several  leases have been  formally  evaluated  for  resource
potential including Leases 88, 89, 90, 9 and the remainder of Lease 13. Western
will  disclose  resource  potential on a per project basis rather than lease by
lease, as the mine plans straddle lease boundaries and contingent resources are
related to a specific  mine plan.  Disclosure  in this  manner will also create
alignment with regulatory permits and proposed mine plans.

      In respect of an ongoing  delineation  drilling program on Leases 88, 89,
90,  9 and the  remainder  of  Lease13,  Western  engaged  Norwest  Corporation
("Norwest") to prepare volumetric  estimates of recoverable  bitumen associated
with mining pits. GLJ used these geological and mining assessments to determine
contingent  resources.  Lease 17 was not included in the  determination  of any
future mine plans as  insufficient  core hole  drilling  was  conducted on this
lease during last year's  winter  drilling  season to fully assess its resource
potential.

<PAGE>

      As per the Canadian Oil and Gas Evaluation Handbook ("COGEH"), contingent
resources  are those  quantities of oil and gas estimated on a given date to be
potentially   recoverable  from  known  accumulations  but  are  not  currently
economic.  GLJ  has  categorized  the  potentially   recoverable  resources  as
contingent in view of ownership,  regulatory  applications and owner commitment
issues  and not as a  result  of  current  economics.  Western  believes  these
contingent resources will be economic to develop in the future. Over time, with
additional project development and financial  commitment,  Western would expect
these contingent resources to be converted to reserves.

      Western  has  an  enviable  land  position  and  asset  base.  Currently,
regulatory  upstream  approvals allow for 470,000 barrels of bitumen per day to
be extracted from a combination of the Muskeg River Mine and the Jackpine Mine.
This permitting capacity would allow significant expansions of the AOSP. Future
evaluation  drilling will be conducted to delineate  the resource  potential on
other leases. In advance of this, Shell intends to file regulatory applications
that would add an  incremental  300,000  barrels  per day of mining  permitting
capacity,  bringing  the  total to  770,000  barrels  per day.  At this  level,
sufficient  approvals would be in place to advance AOSP Expansions 3 through 5.
These plans would take Western's share of production to 154,000 barrels per day
from  mining  expansions  alone.  These  volumes do not  include  any  resource
potential for expansions  beyond  Expansion5 which could  potentially  occur on
leases that have not yet been  evaluated.  The transition  and disclosure  from
acreage to resources,  and  ultimately  reserves,  will evolve over time as the
Joint Venture Owners continue to drill and sanction expansions of the AOSP.

      The best case  estimate  for  contingent  resources  (in  addition to the
reserves  discussed  above) on a total AOSP Joint  Venture  basis  exceeds  4.4
billion  barrels of which  Western's  share would be 891 million  barrels.  All
contingent resources are reported on a synthetic crude oil basis. This data was
based on several key  assumptions in order to calculate  contingent  resources,
namely,  minimum  bitumen by weight of seven per cent to total weight,  minimum
mining  thickness  of three  metres  and a range of total  volume to bitumen in
place ("TV:BIP") of 12:1, consistent with regulated operating criteria,  and up
to a TV:BIP ratio of 16:1 as a high estimate.  The upgrading yield  assumptions
are consistent with the reserve estimate.

      The following  table  summarizes  the reserves and  contingent  resources
associated with Western's interest in the AOSP:

<TABLE>
<CAPTION>
WESTERN'S SHARE OF MINEABLE SYNTHETIC CRUDE OIL VOLUMES (mmbbls)
                                                                                        P + P Reserves Plus
                                  Contingent Resources (1)            Reserves         Contingent Resources
-----------------------------------------------------------------------------------------------------------
                                                                       Proved Plus
Project Areas                    Low       Best        High     Proved    Probable        Best        High
-----------------------------------------------------------------------------------------------------------
<S>                              <C>        <C>         <C>         <C>        <C>         <C>         <C>
Muskeg River Mine (2)            188        228         291         275        309         537         600
Jackpine (3)                     314        458         645         220        268         726         913
Pierre River (4)(5)              102        205         306           -          -         205         306
-----------------------------------------------------------------------------------------------------------
Total                            604        891       1,242         495        577       1,468       1,819
===========================================================================================================
</TABLE>

(1)   Contingent resources have been evaluated for Leases 13, 88, 89, 90 and 9.
Categories of Low, Best and High are used as recommended in the COGEH.

(2)   Includes  the west  side of Lease  13, 90 and  Sharkbite  areas.  Reserve
status has been assigned only to the west side of Lease 13.

(3)   Includes  the east side of Lease 13 and  Leases 88 and 89 and  represents
Expansions  1 through 3. Reserve  status has only been  assigned to part of the
east side of Lease 13.

(4)   Includes  volumes  only for Lease 9.  Lease 17 was not  included  in this
determination as core hole drilling to assess resource  potential  continues on
this lease.

<PAGE>

(5)   Represents Expansions 4 and 5.

      In addition to the above,  Western's  view is that the Ells River Project
could contain resources (with pay thickness of greater than 18 metres) suitable
for in-situ  development  in excess of 7.4 billion  barrels of original  oil in
place  (approximately  1.5  billion  barrels  net to  Western).  Based  on this
estimate,  production  from the Ells River Project,  combined with volumes from
Western's  in-situ  project (in which the Company  holds an average 64 per cent
land  interest),  could support  production in excess of 50,000 barrels per day
net to Western. These in-situ volumes, together with production associated with
the recently  announced future mineable  expansions,  would increase  Western's
total bitumen  production to more than 200,000  barrels per day within the next
15 to 20 years.

      An extensive  winter core hole drilling  program is  continuing  over the
next  several  years on the Muskeg River Mine,  Jackpine  Mine and Pierre River
Mine areas as well as on the Ells River  Project and Western's  in-situ  lands.
Western would anticipate that as drilling progresses, discovered resources will
be identified, and that contingent resource volumes will continue to be amended
as delineation  drilling extends onto previously  sparsely  drilled leases.  In
addition,  as Western  continues to  participate  in  expansion  opportunities,
potential   future   development  of  these  project  areas  will  provide  for
substantial growth opportunities in our proved and probable reserve base.


Unevaluated Land

The current land position  assembled by all Joint Venture  Owners  approximates
300,000 acres (69,000 acres net to Western).  Of this total,  approximately  68
per cent represents  mineable leases, with the remaining 32 per cent considered
prospective for in-situ development.  Only a fraction of Western's  undeveloped
land position has been evaluated.  The lands  associated with Western's  proved
and  probable  reserves  represent  approximately  11 per cent of the more than
69,000 net acres of total  undeveloped  land in which  Western has the right to
participate.  As  delineation  of these lands  continues,  Western  expects its
reported resources and reserves to increase and will be updated accordingly.

      During  2006,  Western  and  Chevron  acquired  additional  leases in the
Athabasca region of northern Alberta. These leases are included under the terms
of the AMI. Chevron acquired five in-situ leases,  namely Leases 348, 349, 350,
673 and 675, located approximately 50 kilometres northwest of Fort McMurray and
comprise  approximately  75,000 acres  (15,000  acres net to Western).  Western
exercised its right to participate in the Chevron in-situ leases in August 2006
and provided a payment for its pro rata share of the lease  acquisition  costs.
Chevron  has   communicated   that  these  leases  have  potential  to  produce
approximately 100,000 barrels per day (20,000 barrels net to Western). Chevron,
a world leader with respect to heavy oil development, has assembled a dedicated
team to explore and assess this opportunity.

      In terms of  Western's  in-situ  land  position,  Leases 442 and 472 were
acquired in 2006.  Taken  together with Lease 353,  which was acquired in 2005,
Western's operated land position has grown to over 21,000 acres  (approximately
14,000  acres net to  Western).  Western  holds an average 64 per cent  working
interest in these in-situ  lands.  Pursuant to the AMI, the other Joint Venture
Owners elected to participate in Lease 353 to a 20 per cent interest,  with one
other Joint Venture Owner  electing to  participate  in Leases 442 and 472. The
participating owners have provided payment for their share of lease acquisition
costs to secure their respective working interests.

<PAGE>

      Western  also has the  right to  participate  in the  development  of the
leases  acquired by Shell until 2009 for future mining  expansions of the AOSP.
The leases  could  potentially  be  developed as an extension to the 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  by  Western  to  continue  to grow its land  position  and  capture
opportunities  to add resources.  Assessments  regarding our  involvement  will
always be made in the context of  maintaining  the  integrity of our  financial
position and creating  shareholder  value. To manage this growing land position
and  evaluate   potential   opportunities,   we  expanded  our   organizational
capabilities in 2006,  particularly  in the area of heavy oil development  with
key management appointments, including Mr. Graig Ritchie as Vice President, Oil
Sands and Mr. Matt Swartout as Senior Drilling Manager.



OPERATING RESULTS

Fiscal  2006  represents  the third  full  year of  commercial  operations  for
Western.  The  Project's  original  nameplate  productive  capacity was 155,000
barrels per  calendar  day. As a result of  successful  and ongoing  production
optimization  initiatives  at both the  Mine  and  Upgrader,  the  Project  has
increased the calendar day average  production to a range of 165,000 to 175,000
barrels  per day in  recent  quarters,  with a  near-term  goal  of  increasing
production to  approximately  200,000  barrels per day by 2009.  For short-term
intervals the mine has achieved  production  rates in excess of 215,000 barrels
per day.  During the second  quarter of 2006,  operations  were impacted by the
first full plant turnaround  which extended to a 56-day period.  The turnaround
schedule was longer than anticipated  because it was determined that additional
maintenance  and repair work was required in order to remove  large  amounts of
coke  from the  reactor  vessels  at the  Upgrader.  With  efforts  focused  on
increasing  the  reliability  of  the  base  Project,   consistent  and  stable
operations  should follow  which,  in turn,  optimizes the  efficiency of these
major  facilities.  Full  turnarounds are expected to be required on a three to
four year cycle.

<TABLE>
<CAPTION>
HIGHLIGHTS

                                                                      2006          2005             2004
---------------------------------------------------------------------------------------------------------
<S>                                                            <C>           <C>              <C>
Operating Data (bbls/d)
   Bitumen Production                                               27,500        31,994           27,108
   Synthetic Crude Sales                                            37,326        42,534           36,210
   Operating Expense per Processed Barrel ($/bbl) (1)                28.38         22.06(9)         21.17
---------------------------------------------------------------------------------------------------------
Financial Data ($ thousands, except as indicated)

   Gross Revenue                                                   983,560       910,330          636,911
   Realized Crude Oil Sales Price - Oil Sands ($/bbl) (1)(2)         60.51         49.91            34.60
   Cash Flow from Operations (1)(3)                                228,449       244,231           23,044
   Cash Flow per Share - Basic ($/Share) (1)(4)                       1.42          1.52             0.15
   Net Earnings Attributable to Common Shareholders (6)             63,370       149,449           19,452
   Net Earnings per Share ($/Share)
      Basic                                                           0.39          0.93             0.12
      Diluted                                                         0.39          0.92             0.12
   EBITDAX (1)(5)                                                  276,916       307,008           87,587
   Net Capital Expenditures (7)                                    301,273        46,833           39,968
   Total Assets                                                  1,794,159     1,590,520        1,470,870
   Long-term Debt                                                  601,385       565,655          662,620
   Long-term Financial Liabilities (8)                             723,174       706,880          716,094
   Weighted Average Shares Outstanding - Basic (Shares)        160,991,406   160,169,887      156,926,514
=========================================================================================================
</TABLE>

<PAGE>

(1)   Please refer to page 56 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 35 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.

(5)   Earnings before interest, taxes, depreciation,  depletion,  amortization,
stock-based  compensation,  accretion on asset retirement  obligation,  foreign
exchange and risk management as calculated on page 43.

(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.

(9)   Operating  costs  per  processed  barrel  for 2006  were  $24.50,  net of
turnaround costs of $3.88 per processed barrel.


FINANCIAL PERFORMANCE

Revenue

Western  achieved  record  gross crude oil sales  revenue of $983.6  million in
fiscal 2006 compared to $910.3 million in 2005,  including $825.4 million (2005
- $777.9 million) from  proprietary  production at an average realized price of
$60.51 per barrel  (2005 - $49.91  per  barrel).  Record  sales  revenues  were
achieved largely due to a 21 per cent increase in Western's  realized crude oil
price as a result of the continued strength in world crude oil prices partially
offset by a 14 per cent decrease in bitumen  production due to the full planned
plant  turnaround  and repair of a conveyor belt during the year.  During 2006,
Western had no proprietary  barrels subject to financial hedge instruments and,
consequently,  enjoyed  the full  appreciation  of the  underlying  21 per cent
increase in West Texas  Intermediate  ("WTI") light sweet crude oil through our
synthetic  crude oil sales. A careful and  deliberate  decision was made to not
hedge any barrels in 2006 as the capital  expenditures  were not large relative
to the capital  spending  profile in subsequent  years. In 2005, gross revenues
were  reduced by $110.4  million  due to  out-of-the-money  fixed  priced  swap
contracts on a portion of Western's  proprietary  production  and, as a result,
Western's crude oil price realization was reduced by $7.11 per barrel.

      Western's crude oil sales were subject to an overall quality differential
of $12.82  per  barrel  (2005 - $12.27  per  barrel)  off of the  Edmonton  PAR
benchmark   crude  oil  price  of  $73.33  per  barrel  in  2006.  The  quality
differential has increased marginally from the prior year due to a heavier than
normal  sales  mix  associated  with  the  period  prior  to,  and  immediately
following, the full plant turnaround.  During this period, the Upgrader was not
running at optimal  conversion  rates resulting in a heavier blend of synthetic
crude  oil.  This was  offset by a  general  narrowing  of the heavy  crude oil
differential  during 2006 which helped  maintain  higher oil sands revenues and
realized  synthetic  crude oil sales prices.  The heavy crude oil  differential
averaged 35 per cent of WTI prices, or $22.58 per barrel in 2006 compared to 39
per cent or $21.83  per  barrel  in 2005.  Western  has  generally  observed  a
narrowing of the heavy oil differential over the last year thought to be due to
in part by crude oil pipeline  reversals  enabling  western  Canadian heavy oil
producers to ship to  additional  markets in the Midwest and Gulf Coast regions
of the  United  States.  Increasingly,  refineries  in the  United  States  are
purchasing  additional  heavy  crude oil to capture  the value  inherent in the
differential by processing heavy oil into  higher-valued  refined products such
as  gasoline,  diesel  and jet  fuel.  As the  graph on page 32  indicates  and

<PAGE>

notwithstanding the above,  Western's realized prices remain closely correlated
to underlying  movements in WTI. During 2006,  Western  experienced its highest
price  realizations  since  production  start-up  primarily  due to the factors
outlined above as well as a marked  improvement in the reliability of the plant
which, when the plant turnaround is excluded,  allowed the Project to produce a
lighter  overall  sales mix through  better  conversion  of bitumen  into light
synthetic crude oil at the Upgrader.

      With the objective of providing greater cash flow certainty for the years
of significant  capital  expenditures,  Western  executed an extensive  hedging
program  covering 2007 to 2009,  with entirely  different  hedging  products or
derivative  instruments  employed  for  this  program.  Western  implemented  a
pay-collar strategy,  whereby a series of put and call options were both bought
and sold to establish a floor price for a portion of planned production, with a
corresponding  ceiling  that  Western  would  receive on a similar  but smaller
number of barrels. The range of these collars provides a weighted average floor
price of US$52.42 on 20,000 barrels per day over the three years and a weighted
average  ceiling of US$92.41  on an average of 13,333  barrels per day over the
same time period.  This program  provides greater cash flow certainty given the
substantial capital commitments associated with Expansion1 of the AOSP over the
next three years.  In addition,  the collar  strategy does not limit the upside
potential  related to commodity  price  appreciation  to the same degree as the
fixed price swap contracts that Western employed in the past.

      Western  generated  net  revenue of $630.0  million in 2006  compared  to
$591.4 million in 2005,  representing  a seven per cent  increase.  Net revenue
reflects the costs of purchased  feedstocks and transportation costs downstream
of Edmonton.  Feedstocks are third-party  crude oil products  introduced at the
Upgrader. Some feedstocks are used in the hydrocracking/hydrotreating  process,
while others are used as blendstock to further  optimize  various  qualities of
synthetic  crude oil  products.  The cost of these  feedstocks  depends  on oil
markets and the spread between heavy and light crude oil prices.


NET REVENUE

($ thousands, except as indicated)                          2006       2005
---------------------------------------------------------------------------

Revenue
   Oil Sands (1)                                         825,418    777,876
   Marketing and Transportation                          158,142    132,454
---------------------------------------------------------------------------
   Total Revenue                                         983,560    910,330
Purchased Feedstocks and Transportation
   Oil Sands                                             196,066    185,693
   Marketing and Transportation                          157,456    133,241
---------------------------------------------------------------------------
   Total Purchased Feedstocks and Transportation         353,522    318,934
Net Revenue
   Oil Sands (1)                                         629,352    592,183
   Marketing and Transportation                              686       (787)
---------------------------------------------------------------------------
   Total Net Revenue                                     630,038    591,396
Synthetic Crude Sales (bbls/d)                            37,326     42,534
Crude Oil Sales Price ($/bbl) (2)                          60.51      49.91
============================================================================

(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. In 2006,
$1.1million  (2005 - $3.0 million) had been incurred for  transportation  costs
related to oil sands.

<PAGE>

Operating Costs

Western's  share of the Project's  operating  costs totalled  $286.3 million in
2006 (2005 - $250.4 million)  including $40.2 million  associated with the cost
of the  turnaround.  Also  included  in this amount are 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
$28.38 per barrel based on average production of 27,500 barrels per day in 2006
compared to $22.06 per barrel based on average production of 31,994 barrels per
day in 2005.  Excluding  the  impact of the  turnaround,  operating  costs were
$24.50 per processed  barrel for 2006  compared to $22.06 per processed  barrel
for the prior year period.  However,  unit operating costs per processed barrel
in 2006 are impacted by lower  annual  production  rates  compared to the prior
year period.

      Higher unit  operating  costs in 2006 were  largely  due to higher  input
costs for materials and supplies in an escalating  commodity price environment,
offset in part by lower  natural gas costs during 2006 compared to the previous
year.  On a unit  basis,  natural  gas costs  were $4.07 per  processed  barrel
compared to $5.04 per  processed  barrel in 2005.  This 19 per cent decrease is
consistent  with the 18 per cent  decrease in the market  price for natural gas
over the same time periods,  indicating a similar gas intensity for the Project
over the last several years. Unit operating costs in 2006 were also impacted by
repair  costs  and  associated  lost  production  stemming  from a tear  in the
conveyor belt at the Mine in the first quarter.

      Operating costs, on both an absolute basis and on a per unit basis,  were
impacted  significantly  by the first full  turnaround  of the Project in 2006.
This process  extended  for a period of 56 days during the second  quarter and,
for a large part of that time, little or no production was recorded. Turnaround
activities  added  $3.88  per  processed  barrel in 2006.  Given  that the cost
structure of the operation is predominantly  fixed,  many of the costs incurred
when the Project is in full operation  continued  during the  turnaround.  As a
result,  operating  costs  per  unit  increased  substantially  in  2006  and a
comparison to the prior year period is not meaningful. For accounting purposes,
Western has expensed all of the costs  associated with the turnaround,  whereas
other oil sands producers capitalize certain components of turnaround costs and
amortize them over the period to the next  turnaround.  Western's  share of the
turnaround costs was $40.2 million. The turnaround proved to be more costly and
longer in duration than originally  budgeted due to additional  maintenance and
repair work at the Upgrader in order to remove  large  amounts of coke from the
reactor  vessels.  Consequently,  the Project was delayed in  returning to full
production. Operating costs returned to expected levels towards the latter part
of 2006.  Following the  turnaround,  operating costs were $20.38 per processed
barrel over the last two quarters of the year on a bitumen  production  base of
slightly more than 34,000 barrels per day net to Western over this time period.

      Western believes its operating costs are impacted somewhat by longer-term
WTI prices and  associated  energy costs.  In 2006,  WTI averaged  US$66.22 per
barrel  compared  to  US$56.56  per barrel for 2005  which  resulted  in upward
pressure on certain  cost  components  as  suppliers  of these  components  and
services  themselves  experienced  higher cost structures largely due to higher
energy costs and other  commodity  prices.  Ultimately,  this  contributed to a
higher cost structure for oil sands operations. Despite the upward pressures on
operating  costs in a rising  commodity  cycle,  unit operating costs typically
decline over time as the technological and engineering challenges are addressed
and  resolved  and  as  production  optimization   initiatives  are  completed.
Production  optimization  activities  requiring  relatively  modest  amounts of
capital are  planned to continue  over the life of the Project at both the Mine
and the Upgrader in order to increase  throughput and/or reduce absolute costs.

<PAGE>

Production at the Mine has more  consistently  met or exceeded  200,000 barrels
per  day  on a  stream  basis  which  demonstrates  the  effectiveness  of  our
production  optimization  activities.  Ongoing  efforts  with  respect to these
activities  should  result in sustained  upstream  calendar day  production  of
approximately 200,000 barrels per day by 2009. Corresponding initiatives at the
Upgrader  are  planned  to be  undertaken  to  process  this  higher  level  of
production as well as improving product quality.

      Western  recognizes that operating costs are a key metric among companies
active in the mineable oil sands  industry;  however,  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 its overall  operating  costs,  whereas other industry players either do not
have  this  cost  category  or net these  transportation  costs  from oil sands
revenue.  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. While the entire industry's cost
structure has shifted upwards,  the Joint Venture will continue to evaluate all
methods  to  control  and  reduce  its  costs.  As the  majority  of the AOSP's
operating  costs are fixed, to the extent the Project can maintain and increase
production,  total  unit  operating  costs  should  decrease  as the  costs are
distributed  over a  growing  production  base.  We  believe  the  AOSP has the
potential to be one of the lowest cost  producers of all the Canadian oil sands
mining projects.

<TABLE>
<CAPTION>
OPERATING COSTS

($ thousands, except as indicated)                                                  2006              2005
-----------------------------------------------------------------------------------------------------------
<S>                                                                              <C>               <C>
Operating Expenses for Bitumen Sold
   Operating Expense - Income Statement                                          246,164           250,389
   Operating Expense - (Inventoried)/Expensed in Purchased Feedstocks              7,765            11,704
   Turnaround Costs - Income Statement                                            40,161                --
-----------------------------------------------------------------------------------------------------------
   Total Operating Expenses for Bitumen Sold                                     294,090           262,093
-----------------------------------------------------------------------------------------------------------
Sales (barrels per day)
   Total Synthetic Crude Sales                                                    37,326            42,534
   Purchased Upgrader Blendstocks                                                  8,932             9,979
-----------------------------------------------------------------------------------------------------------
   Synthetic Crude Sales Excluding Blendstocks                                    28,394            32,555
-----------------------------------------------------------------------------------------------------------
Operating Expenses per Processed Barrel ($/bbl) (1)                                28.38             22.06
-----------------------------------------------------------------------------------------------------------
Operating Expenses per Processed Barrel Excluding Turnaround Costs ($/bbl)(2)      24.50             22.06
===========================================================================================================
</TABLE>

(1)   Operating  expenses per processed  barrel ($/bbl) are 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.

(2)   Operating  expenses per  processed  barrel  excluding  the effects of the
turnaround, taken by total operating expenses for bitumen sold, less turnaround
expenses divided by synthetic crude sales excluding blend stocks.


Operating Netbacks

Western's  2006 operating  netback was $33.84 per dry bitumen barrel  produced,
down from  $38.32 per dry bitumen  barrel  produced  (excluding  hedges) in the
prior year period.  This decrease is largely due to the $40.2 million  incurred
for the turnaround in the second quarter as well as the costs  associated  with
replacing the conveyor  belt during the first quarter of 2006.  The netback for

<PAGE>

2006,  however,  was considerably  higher than the netback achieved in 2004 and
2003 due to the significant  increase in underlying crude oil prices over these
time periods. Netbacks in the second half of 2006 improved substantially,  with
a netback of $45.77 per dry bitumen  barrel  produced in the third  quarter and
$37.12 per dry bitumen barrel produced in the fourth  quarter.  The decrease in
the operating  netback was  partially  offset by the narrowing of the heavy oil
differential  from the prior year period as  additional  markets  for  Canadian
heavy oil are opening in the United States through existing pipeline reversals,
together with refineries reconfiguring their assets to process a larger portion
of heavy oil to capitalize on the heavy crude oil differential.


Royalties

Royalties  were $4.1 million or $0.40 per barrel of bitumen in 2006 compared to
$4.0 million or $0.34 per barrel in 2005. Higher gross royalties are the result
of higher  deemed  bitumen  prices  for 2006  which  serve as the basis for the
royalty calculation,  partially offset by reduced production during 2006 due to
the  turnaround.  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 AOSP,
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.

      During 2006,  Western  announced its  participation in Expansion 1 of the
AOSP and we fully expect to participate in subsequent  mining expansions of the
AOSP. As such,  Western assumes that additional  capital  incurred to construct
future  expansions  will be added to the  capital  base for  royalty  purposes,
extending our royalty horizon in the absence of any  legislative  amendments to
the royalty regime. At current  commodity  prices,  Western does not anticipate
conversion  to the 25 per cent of net  bitumen  revenues  for the next  several
years.  The move to the higher  royalty  rate may be  accelerated  or postponed
depending on future crude oil prices, foreign exchange rates and the timing and
inclusion of capital  expenditures  and the Alberta  government's  treatment of
bitumen extraction expansion efforts.



CORPORATE RESULTS

Research and Business Development

A portion of  Western's  annual  budget is directed to  research  and  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 internal  technical  capabilities in order to evaluate
opportunities as they arise either through the Joint Venture or  independently;
and  finally,  as  part  of  our  long-term  strategy,   plans  to  expand  our
organizational  capabilities  to evaluate  opportunities  related to downstream
integration.  A portion of these  expenditures  also  relate to  WesternZagros'
initiative  in  Kurdistan.  Western  incurred  $34.9  million for  research and
business  development  in 2006 (2005 - $10.7  million),  of which $22.4 million
(2005 - $5 million) relates specifically to AOSP-related research projects. The
majority  of the  balance  of $12.5  million is  related  Western-led  research
activities related to oil sand extraction and recovery methodologies, increased
administrative  costs associated with building the organizational  capabilities
to  assess  in-situ   opportunities,   downstream  integration  strategies  and

<PAGE>

initiatives  and costs related to  progressing  the  negotiation of our EPSA in
Kurdistan.


General and Administrative Expenses

General and administrative expenses ("G&A") were $28.5 million in 2006 compared
to $14.5  million in the prior  period.  Of this amount,  $12.1 million (2005 -
$3.1  million)  relates  to  stock-based   compensation.   Net  of  stock-based
compensation,  G&A expenses  were $16.4  million  compared to $11.4  million in
2005.  The increase  from the prior year period is largely a function of higher
office rent and increased  salaries and benefits  stemming from a near doubling
in the number of employees in 2006.  It also reflects  additional  professional
costs  incurred  during  2006  due  to  increased  public  company   compliance
requirements compared to 2005.


Insurance Expenses

Insurance expenses were $11.5 million in 2006 compared to $8.0 million in 2005.
Western  maintains  insurance  policies  covering  property  damage,   business
interruption,  commercial general liability,  directors and officers liability,
in addition to various corporate policies.  Insurance expense is higher in 2006
compared to the previous  year due to an increase in coverage  associated  with
Western's business interruption policy.  Western's insurance placement strategy
is to obtain sufficient coverage on business  interruption to ensure sufficient
cash flow is received after a major loss. As such,  when  underlying  commodity
prices increase,  this desired level of coverage is more costly. Another factor
impacting the cost of the business interruption policy is worldwide loss events
which cause insurance  carriers to re-adjust premiums charged on such policies.
These factors were partially offset by the strengthening of the US/Cdn exchange
rate  as  these  premiums  are  paid in US  dollars.  There  were  no  material
reductions in coverage compared to the prior year. Indeed, additional coverages
are being secured both on a Joint Venture  basis  relating to the  construction
and start-up of  Expansion  1,  together  with  policies  relating to Western's
operation of an in-situ project. As such, Western  anticipates  insurance costs
to increase as these operations grow.


Interest Expense

During 2006,  total  interest  charges  decreased by $5.4 million,  or nine per
cent, to $52.8 million compared to $58.2 million in 2005. Of the total interest
charges  in  2006,  $2.8  million  relating  to  Expansion  1 was  capitalized.
Capitalized  interest  will increase in the future to the extent that we employ
debt  financing  to fund  our  share  of the  capital  costs  of  Expansion  1.
Capitalized  interest will continue to be recorded until the assets  associated
with  Expansion 1 begin  commercial  operations.  This is  consistent  with the
treatment of interest  charges  associated  during the construction of the base
Project.  Of the remaining  $50.0 million in interest  charges  recorded on our
income  statement,  $43.4  million  is  related  to  interest  charges  on debt
obligations  (2005 - $54.3  million),  $2.8million  (2005  - $2.6  million)  to
capital  lease  obligations  and $3.8 million  (2005 - $1.3  million) to option
premium liability.  The option premium liability relates to Western's 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 which is reported as interest expense.

      Western's debt obligations include US$450 million of Senior Secured Notes
and a $340 million  Revolving Credit Facility.  Western's average interest rate
decreased  marginally  from 2005.  This  decrease  is due to two  factors:  the
strengthening  of the US/Cdn  exchange rate as interest  payments on our US$450

<PAGE>

million  denominated  debt are  recorded  in  Canadian  dollars  for  financial
reporting  purposes  and  lower  interest  rates on  amounts  drawn  under  the
Revolving Facility resulting from amendments  executed in the fourth quarter of
2005.  These  positive  factors were  partially  offset by interest  charges on
larger drawn amounts under the Revolving  Facility.  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 to a
factor  over five  times in 2006  from  under  one time in 2003,  a  seven-fold
increase  with no  material  deterioration  in this ratio in a full  turnaround
year. As we begin to fund our share of the capital costs of Expansion 1, and to
the extent that debt facilities are used to finance this expansion, ratios such
as interest coverage may fall from present levels; however, we intend to manage
these  levels to ensure our  continued  participation  in Expansion 1 and other
AOSP or  Western-driven  growth  initiatives.  Interest expense on a per barrel
basis also decreased  substantially due to the addition of reserves  associated
with  Expansion 1 from previous  years.  We  anticipate  this ratio to increase
somewhat as debt is placed on the balance  sheet to fund our share of Expansion
1. Western  believes all of its key growth  initiatives can be supported by its
financial performance and its ability to access capital markets.

The following  table  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)                         2006       2005
----------------------------------------------------------------------------
Interest Expense
   Interest Expense on Long-term Debt                    46,190     54,324
   Interest on Obligations under Capital Lease            2,823      2,562
   Interest on Option Premium Liability                   3,799      1,279
----------------------------------------------------------------------------
   Total Financing Charges                               52,812     58,165
----------------------------------------------------------------------------
Long-term Debt Financing
   US$450 Million Senior Secured Notes (1)              524,385    524,655
   Revolving and Senior Credit Facilities                77,000     41,000
----------------------------------------------------------------------------
   Total Long-term Debt                                 601,385    565,655
----------------------------------------------------------------------------
Average Long-term Debt Level                            583,520    661,638
Average Cost of Long-term Debt (2)                         7.92%      8.21%
============================================================================

(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)   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  2006,  Western  recorded  $61.6  million  as  depreciation,  depletion  and
amortization  expense  compared  to  $50.7million  in  2005.  This 21 per  cent
increase is primarily the result of two separate  decisions to write-off  early
stage pilot  projects.  At the Joint Venture level,  Western had a $9.4 million
write-off  relating to certain AOSP production  optimization and  profitability
projects in the  pre-feasibility  stage  (predominantly  at the Mine) that were
discontinued as future benefits were not conclusive. An additional write-off of
$5.6  million  occurred  as a  result  of oil  sands  activities  that  Western
independently  pursued and, due to technical reasons,  elected not to continue.
Depletion is calculated on a unit of  production  basis for Western's  share of
Project  capital  costs,  while  previously   deferred  financing  charges  are

<PAGE>

amortized  on a  straight-line  basis  over  the  remaining  life  of the  debt
facilities.  The  increase  for  2006 is  partially  offset  by the 14 per cent
decrease in production in 2006 versus 2005 as a result of the turnaround in the
second quarter of 2006.

<TABLE>
<CAPTION>
DEPRECIATION, DEPLETION AND AMORTIZATION

Year ended December 31                                   2006                       2005
-----------------------------------------------------------------------------------------------
                                            ($ thousands)       $/bbl  ($ thousands)      $/bbl
-----------------------------------------------------------------------------------------------
<S>                                               <C>            <C>         <C>           <C>
Depreciation and Depletion                        44,022         4.39        48,206        4.13
Accelerated Depreciation and Depletion            14,979         1.49            --          --
Amortization                                       2,559         0.25         2,532        0.22
-----------------------------------------------------------------------------------------------
Total Depreciation, Depletion
   and Amortization                               61,560         6.13        50,738        4.35
===============================================================================================
</TABLE>

Foreign Exchange

In 2006,  WTI averaged  US$66.22 per barrel  compared to US$56.56 per barrel in
2005,  representing a 17 per cent increase. This increase in WTI is one factor,
out of many,  that may have  contributed to the  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 2006, we recorded an  unrealized  foreign  exchange gain of $0.2
million  compared to a gain of  $17.8million in 2005 relating to the conversion
of the Senior Secured Notes and option premium  liability to Canadian  dollars.
As reference points, the noon-day closing foreign exchange rate on December 31,
2006 was $0.8581  US/Cdn  compared to $0.8577  US/Cdn on December 31, 2005.  In
terms of average  noon-day  rates for the respective  periods,  fiscal 2006 was
$0.8817 US/Cdn compared to $0.8254 US/Cdn for fiscal 2005.


Income Taxes

Western has significant 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 Western pays cash taxes.

      As at December 31, 2006,  Western  recorded a future income tax liability
of $73.1  million  compared to $56.4  million at  December  31,  2005.  Western
recognized  approximately $16.7 million of future income tax expense during the
year as we  experienced  profitable  operations  despite  the nearly  two-month
turnaround. During 2006, no amounts were expensed for the Large Corporation Tax
(2005 - $3.0  million) as this tax was  eliminated in early 2006 by the federal
government.  No other current taxes are payable and our cash tax horizon is not
expected to occur for several  years as  additional  capital  incurred  for the
construction  of Expansion 1  contributes  to the  existing tax pools,  thereby
offsetting  taxable  income in future years beyond  which  current  pools would
cover.

<PAGE>

TAX POOLS

December 31 ($ thousands)                                    2006          2005
-------------------------------------------------------------------------------
Canadian Exploration Expense                              109,623        89,140
Canadian Development Expense                               39,994        23,657
Cumulative Eligible Capital                                 7,370         7,925
Capital Cost Allowance                                    175,892       126,001
Accelerated Capital Cost Allowance                      1,085,421     1,090,155
-------------------------------------------------------------------------------
Total Depreciable Tax Pools                             1,418,300     1,336,878
Loss Carry Forwards                                         9,055        14,000
Financing and Share Issue Costs                             3,902         9,596
-------------------------------------------------------------------------------
Total Tax Pools                                         1,431,257     1,360,474
===============================================================================


Net Earnings

Net earnings  were $63.4  million  ($0.39 per share) in 2006 compared to $149.4
million  ($0.93 per share) in 2005.  This  year-over-year  decrease is in large
part due to the full turnaround  completed  during 2006,  together with a $72.1
million  unrealized  risk  management loss ($49.9 million after tax) associated
with marking to market  Western's  strategic crude oil hedging program for 2007
through to 2009 compared to an unrealized risk management gain of $13.5 million
in 2005 ($8.9 million after tax). Earnings for the year reflect $0.3 million of
unrealized  foreign  exchange  gains on our US$450 million Senior Secured Notes
and  option  premium  liability,  a  $72.1  million  unrealized  loss  on  risk
management  activities  and a future  income  tax  expense  of  $16.7  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 $276.9  million.  Cash flow from
operations,  before  changes in non-cash  working  capital,  was $228.4 million
($1.42 per share) in 2006 compared to $244.2 million ($1.52 per share) in 2005.
Robust commodity prices,  together with sustained reliable  operations over the
course of the year,  excluding the effects of the full turnaround,  resulted in
substantial  EBITDAX which was  predominantly  used to assist in the funding of
early stage capital for Expansion 1.

<TABLE>
<CAPTION>
NET EARNINGS

December 31 ($ thousands)                                                2006        2005        2004
------------------------------------------------------------------------------------------------------
<S>                                                                    <C>        <C>          <C>
Net Earnings                                                           63,370     149,449      19,452
After Tax Impact of:
   Unrealized Risk Management (Gain)/Loss                              49,927      (8,928)         --
   Unrealized Foreign Exchange Gain                                      (181)    (14,810)    (33,243)
------------------------------------------------------------------------------------------------------
Net Earnings (Loss) Excluding Unrealized Gain (Loss)                  113,116     125,711     (13,791)
------------------------------------------------------------------------------------------------------
Net Earnings (Loss) Excluding Unrealized Gain (Loss) Per Share ($)
      Basic                                                              0.70        0.78       (0.09)
      Diluted                                                            0.69        0.77       (0.09)
======================================================================================================
</TABLE>


RECONCILIATION: NET EARNINGS TO EBITDAX

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

<TABLE>
<CAPTION>
December 31 (thousands)                                            2006        2005        2004
------------------------------------------------------------------------------------------------
<S>                                                              <C>        <C>          <C>
Net Earnings Attributable to Common Shareholders                 63,370     149,449      19,452
Add (Deduct):
   Depreciation, Depletion and Amortization                      61,560      50,738      44,515
   Accretion on Asset Retirement Obligation                       1,256         562         471
   Stock-based Compensation                                      12,083       3,149         967
   Impairment of Long-lived Assets                                   --          --       4,733
   Unrealized Foreign Exchange Gain                                (212)    (17,803)    (39,960)
   Unrealized Risk Management (Gain)/Loss                        72,118     (13,450)         --
   Future Income Tax Expense (Recovery)                          16,668      70,956      (7,104)
   Interest Expense on Option Premium Liability                   3,801       1,278          --
   Cash Settlement on Asset Retirement Obligations                  (91)        (52)         --
   Cash Settlement on Performance Share Units                    (2,104)       (596)        (30)
------------------------------------------------------------------------------------------------
Cash Flow From Operations, Before Changes
   in Non-Cash Working Capital                                  228,449     244,231      23,044
Add (Deduct):
   Interest (excluding interest on Option Premium Liability)     46,216      56,887      61,154
   Realized Foreign Exchange Loss                                   163       2,242       1,610
   Current Taxes (Recovery)                                        (107)      3,000       1,749
   Cash Settlement on Asset Retirement Obligations                   91          52          --
   Cash Settlement on Performance Share Units                     2,104         596          30
------------------------------------------------------------------------------------------------
EBITDAX                                                         276,916     307,008      87,587
================================================================================================
</TABLE>

Please refer to page 56 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>
2006
Net Revenue                            139.2       95.6      206.2     189.0     630.0
Capital Expenditures, Net               35.3       55.8       96.4     113.7     301.3
Long-term Debt                         525.2      532.8      546.9     601.4     601.4
Cash Flow from Operations (1)           47.8      (20.8)     110.5      91.1     228.4
Cash Flow per Share (2)(5)               0.30      (0.13)      0.69      0.57      1.42
Earnings (Loss) Attributable to
   Common Shareholders (3)(4)(7)       (24.8)     (23.0)      84.4      26.8      63.4
Earnings (Loss) per Share
   Basic (3)(7)                         (0.15)     (0.14)      0.52      0.17      0.39
   Diluted (3)(7)                       (0.15)     (0.14)      0.52      0.16      0.39
---------------------------------------------------------------------------------------

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                         777.3      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                  (1.9)      28.7       79.3      43.3     149.4
Earnings (Loss) per Share
   Basic (6)                            (0.01)      0.18       0.50      0.27      0.93
   Diluted (6)                          (0.01)      0.18       0.49      0.27      0.92
---------------------------------------------------------------------------------------
</TABLE>

<PAGE>

(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.

(3)   Includes  unrealized  foreign  exchange  gains(losses)  on US$450 million
Senior Secured Notes and Option Premium Liability:  (Q1 - $(0.6) million,  Q2 -
$27.3 million, Q3 - $(0.1) million, Q4 - $(26.3) million).

(4)   Includes  unrealized risk management  gains/(loss) on strategic crude oil
program (Q1 -$(67.7)  million,  Q2 -$(44.5) million,  Q3 - $33.3 million,  Q4 -
$6.8 million)

(5)   Please refer to page 56 for a discussion of Non-GAAP financial measures.

(6)   Per share  amounts  for the first  quarter  2005  have been  restated  to
reflect 3:1 share split effective May 30, 2005.

(7)   2006  quarterly  net earnings  (loss) and earnings per share amounts have
been  restated  to  reflect   accounting   treatment   change  to   stock-based
compensation.

(8)   Total amounts may not add due to rounding.



LIQUIDITY AND FINANCIAL POSITION

Western  maintained a strong financial  position in 2006, largely due to robust
commodity  prices  during  the  majority  of the  year,  combined  with  strong
production in the months following the turnaround. It is important to note that
this credit profile was  maintained  after  considering  the full impact of the
plant  turnaround,  where little or no production was recorded for a portion of
the second  quarter,  and while  operating  and capital  costs of the  business
continued during this period.  This financial position provides us with a solid
foundation to finance our share of the capital costs  associated with Expansion
1, while maintaining the base Project.

      During  2006,  Western's  capital  costs of $301.3  million  were  funded
primarily through cash flow from operations of $228.4 million.  The balance was
funded by $36 million of  incremental  borrowings  under the  Revolving  Credit
Facility and working  capital.  Total amounts drawn under the Revolving  Credit
Facility were $77 million at year-end.  At December 31, 2006,  Western had $253
million in unused working  capital  capacity.  A key barometer of the financial
strength of a company is its debt to total  capitalization  ratio. For Western,
this ratio has  continued  to improve  from a high of 66 per cent in 2003 to 48
per cent in 2006.  This level  provides  the basis for  additional  borrowings,
should Western elect to do so, to fund upcoming capital  initiatives  including
Expansion 1 of the AOSP and activities related to in-situ evaluation.

      Western  implemented a strategic crude oil risk management program in the
third  quarter of 2005 which  establishes  a weighted  average  floor  price of
US$52.42 on 20,000  barrels per day of  production  from 2007  through to 2009.
This  program  provides  greater cash flow  certainty  during those years where
significant AOSP capital expenditures for Expansion 1 are expected. Incremental
debt may be required to fund future expansion  phases and other  initiatives as
they  arise.  Throughout  these  expansion  efforts,  we expect to  maintain  a
fiscally  prudent  capital  structure  which employs both debt and  potentially
equity  capital  should  the  need  arise.  Western's  view  is that it is well
positioned  to fund its share of the AOSP  Expansion  1,  together  with future
upstream  expansions  of the AOSP,  while at the same time be in a position  to
finance  growth  associated  with  Western's  in-situ  development,  downstream
initiative and Kurdistan opportunity.


Debt Financing

In 2006,  Western maintained its US$450 million of Senior Secured Notes as they
are  non-callable  with a maturity of May 1, 2012.  We were also  successful in
amending our Revolving Credit Facility in May 2006. This amendment  altered the

<PAGE>

nature  of  some  of  the  covenants  in the  underlying  credit  agreement  to
facilitate the development of Western's key strategic  initiatives.  We did not
increase the capacity of our Revolving Facility in 2006;  however,  the size of
the  current  Facility  is a  function  of the  present  value of our  share of
reserves from the AOSP.  Under Western's  current debt capital  structure,  all
bank  borrowings  rank in priority to the  holders of  Western's  US$450million
Notes.  Based on the reserve  evaluation  as at December 31, 2006,  Western has
full access to the $340 million  limit under the  Revolving  Facility.  Western
anticipates it can fund the capital costs  associated with the AOSP Expansion 1
through a combination of cash flow from operations and  incremental  borrowings
and  is  actively   evaluating  various  debt  structures  to  accomplish  this
objective.

      Western  benefited  from the pricing  amendment  finalized  in the fourth
quarter of 2005 as  underlying  interest  rates  softened  and Western  carried
minimal balances  throughout the course of 2006.  Western currently pays nil to
225 basis points over the bank's prime lending rate, bankers  acceptances or US
Libor notes, as applicable,  on amounts drawn under the Revolving Facility.  At
December 31, 2006, $77 million  (December 31, 2005 - $41million) had been drawn
on this  facility  with  $253  million  in  unused  working  capital  capacity.
Additionally,  as at December 31, 2006,  letters of credit issued in the amount
of $9.6 million  (December 31, 2005 - $8.9 million) were outstanding  under the
Revolving Credit Facility.


Equity Financing

Cash flow from  operations,  together  with a modest  increase in the Revolving
Facility,  was sufficient to fund the capital  expenditures and working capital
commitments during 2006. Western will continue to assess all forms of financing
vehicles to ensure our capital structure  leverages off the existing asset base
in a  prudent  manner  as  we  pursue  an  independent  downstream  integration
opportunity for our share of bitumen  production beyond  Expansion1,  including
both mineable and in-situ volumes.

      The share  performance graph compares the yearly change in the cumulative
total  shareholder  return of a $100  investment  made on December  31, 2000 in
Western'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 its inception with a compound
rate of return of 37 per cent.


EQUITY CAPITAL

At December 31                                                             2006
-------------------------------------------------------------------------------
Issued and Outstanding:
   Common Shares                                                    161,378,399
Outstanding:
   Stock Options                                                      3,633,264
-------------------------------------------------------------------------------
Fully Diluted Number of Shares                                      165,011,663
===============================================================================


Capital Expenditures

Net capital  expenditures  totalled  $301.3  million in 2006  compared to $46.8
million in 2005. Of this total,  AOSP  initiatives  accounted for $251 million,
including  $187.4  million  for  Expansion  1 which  includes  $2.8  million in
capitalized interest.  Under the terms of the Joint Venture Agreement,  Western

<PAGE>

is  responsible  for its 20 per cent  share of the  capital  costs  related  to
Expansion 1. Western also incurs capital expenditures related to the evaluation
of in-situ  leases for its operated  properties as well as Chevron's Ells River
Project,  both of which are included in the Joint Venture  pursuant to the AMI.
Capital  expenditures of $15.2 million related to WesternZagros'  initiative in
Kurdistan  were also  incurred  in 2006.  The  AOSP,  and the  expansion  plans
associated  with  this  asset,   will  continue  to  drive  Western's   capital
expenditures going forward,  particularly as the AOSP embarks on its continuous
construction expansion strategy.

<TABLE>
<CAPTION>
December 31 ($ millions)                                                    2006   2005
----------------------------------------------------------------------------------------
<S>                                                                        <C>     <C>
Project Related Capital
   Profitability Capital, Production Optimization and Mobile Equipment      42.7   31.2
   Growth Initiatives                                                      184.6   14.6
   Sustaining Capital                                                       23.8    5.8
----------------------------------------------------------------------------------------
Total Project Related Capital                                              251.1   51.6
Kurdistan Project                                                           15.2    9.5
In-situ Projects (Ells River and Western-operated)                          25.0    0.8
Business Development and General Corporate Expenditures                      3.4    3.0
Capitalized Insurance Costs                                                  3.8    4.4
Capitalized Interest                                                         2.8   --
----------------------------------------------------------------------------------------
Gross Capital Expenditures                                                 301.3   69.4
Insurance Proceeds                                                          --    (22.5)
----------------------------------------------------------------------------------------
Net Capital Expenditures                                                   301.3   46.8
========================================================================================
</TABLE>

Analysis of Cash Resources

Cash balances totalled $3.1 million at the end of 2006, slightly lower than the
$5.6 million as at December 31, 2005. Cash inflows  included net operating cash
flow of $228.4  million,  drawdowns of long-term debt of $36.0 million,  equity
proceeds  of $4.9  million  from the  exercise  of stock  options and a working
capital decrease of $30.8 million.  Cash outflows included capital expenditures
of $301.3 million and obligations under capital leases of $1.3 million.

      Modest  draws  under  the  Revolving  Facility  were  necessary  to  fund
Western's  share  of  capital  expenditures  during  2006.  Additional  capital
expenditures  are  anticipated  as  construction  of  Expansion 1  accelerates.
Western's  2007 capital  expenditure  program is forecasted to be $715 million,
which will be funded in part by cash flow from  operations  and  existing  bank
lines.  It it likely  that  additional  sources of funding  will be required to
provide for any shortfall in cash  requirements for 2007, as well as subsequent
years leading up to the  completion  of  Expansion1.  Western also  anticipates
several years of negative free cash flow, which is the difference  between cash
flow from operations less capital expenditures.  Western will critically assess
and determine the most attractive financing structures to bridge this financing
gap.


Contractual Obligations and Commitments

Western has assumed  various  contractual  obligations  and  commitments in the
normal course of its operations.  Summarized  below are  significant  financial
obligations  as of February  22,  2007,  and  represent  future  cash  payments
required under existing contractual agreements.  Western has entered into these
agreements either directly or as an Owner 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.

<PAGE>

<TABLE>
<CAPTION>
CONTRACTUAL OBLIGATIONS AND COMMITMENTS

                                                             Payments Due By Period

($)                                     <1 Year    1 - 3 Years    4 - 5 Years  After 5 Years        Total
----------------------------------------------------------------------------------------------------------
<S>                                     <C>            <C>            <C>          <C>          <C>
US$450 Million Senior Secured Notes         --              --            --         524,385      524,385
Revolving Credit Facility (1)               --              --            --          77,000       77,000
Obligations Under Capital Lease           1,341          2,680          2,680         42,227       48,928
Option Premium Liability                 25,971         69,775             --             --       95,426
Feedstocks                              106,352         39,612         20,726         58,727      225,417
Pipelines and Utilities                  33,300         78,801         86,347        558,641      757,089
Mobile Equipment Lease                    5,242         32,174          8,625             --       46,041
Exploration Work                          8,728            500             --             --        9,228
----------------------------------------------------------------------------------------------------------
Total Contractual Obligations           180,434        223,542        118,378      1,260,980    1,783,334
==========================================================================================================
</TABLE>
(1)   The Revolving  Credit Facility is a three-year bank facility  maturing on
October 31, 2009,  extendible annually at the lenders'  discretion.  Management
considers this to be part of our long-term capital structure.

(2)   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.


Insurance Claims

At the end of 2006, Western had only one large claim outstanding,  namely, $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, and they have
withheld insurance  proceeds payable to Western.  Western is optimistic that it
will 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.  Similar to Section III,  there are 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.

      Arbitration  proceedings  under the terms of Section IV of Western's Cost
Overrun  and Project  Delay  insurance  policy  continue  with formal  hearings
expected to commence  during 2007. A judgement is expected  subsequent  to this
process,  although Western makes no representations as to the timing or results
of  this  arbitration.  In  preparation  of the  arbitration  process,  several
examinations  for discovery have been conducted with key  individuals  over the
last several  months.  In order to preserve  Western's  rights  regarding  this
policy, Western filed insurance claims for the full limit of the policy, namely
$200  million,  and Western  will also be seeking  interest  and  punitive  and
aggravated damages.

      Due to the  proceedings  with Section IV,  amounts  that were  previously
settled  at the  Joint  Venture  level,  but  where  common  carriers  exist on
Western's  proprietary  policy,  have not yet been paid to our pro rata  share.
With the  addition  of Section 1 (fire and freeze  damage),  Section III (Joint
Venture delay and start-up) and Section IV, Western has a total of $244 million
($1.52 per share) outstanding in insurance claims. Other than amounts collected
up to December  31,  2006,  no  outstanding  amounts are  recorded in Western's
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   Canada   Revenue   Agency   ("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 2006

The  completion of the first full  turnaround at both the Mine and the Upgrader
in the second quarter of 2006 set the stage for strong production in the latter
half of 2006. Fourth quarter production  averaged 35,500 barrels per day net to
Western,  representing the second consecutive quarter of significant production
volumes. Production in the fourth quarter nearly eclipsed the record set in the
third quarter of 2005, where production  averaged 35,600 barrels per day net to
Western.

      During the fourth  quarter,  cash flow from  operations  of $91.1 million
financed virtually all the capital  expenditures  during the quarter;  however,
both underlying crude prices and heavy crude oil  differentials  contributed to
lower  overall  price  realizations.  Crude oil  averaged  US$60.21 per barrel,
considerably lower than the average crude prices experienced in the prior three
quarters. The crude oil heavy differential widened to approximately 35 per cent
of WTI  compared  to the  prior  two  quarters,  where  observed  differentials
approximated 26 per cent to 28 per cent of WTI. As underlying  crude oil prices
decline,  there  is  a  corresponding  decrease  in  Western's  cash  flow  and
profitability  since Western's  revenues are sensitive to fluctuations in crude
oil prices.

      A weakening of the US/Cdn  exchange rate,  which results in more Canadian
funds received on US  denominated  crude sales,  partially  offset the negative
impacts of the changes in crude oil prices and the heavy oil differential.  The
average  exchange  rate for the fourth  quarter was  US/Cdn$0.8778  compared to
US/Cdn$0.8919  for the third quarter of 2006. Due to these  factors,  Western's
sales  price  realizations  totalled  $55.08 per  barrel in the fourth  quarter
compared to $67.42 per barrel for the third  quarter.  In the fourth quarter of
2006,  operating costs were reduced to $20.12 per processed  barrel compared to
$22.38 per processed  barrel in the third  quarter.  This reduction in per unit
costs is  largely  the result of  increased  production  in the fourth  quarter
compared to the previous  quarter which  provides  greater  economies of scale,
partially offset by a six per cent increase in underlying natural gas prices in
the fourth quarter.  AECO gas closing  settlement prices averaged $6.44 Cdn/mcf
for the fourth quarter compared to $6.10 Cdn/mcf for the third quarter.

<PAGE>

OUTLOOK FOR 2007

Western  cautions  readers and  prospective  investors of our securities not to
place undue  reliance on  forward-looking  information  as by its nature,  this
information  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 securing adequate and timely downstream
solutions for future volumes;  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 or expansion strategy; risk that
the other Joint Venture  Owners may not meet their  obligations to the Project,
expansions  thereof or related  agreements  with  Western;  risk that the other
Joint  Venture  Owners may not agree with  Western on matters  relating  to the
Project  including  Expansion 1; risks  involving the  uncertainty of estimates
involved  in  the  reserve  and  resource   estimation  process  and  ore  body
configuration/geometry,  uncertainty  in the  assessment  of  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; risk of changes in governmental
regulation  that could affect the viability of the Project;  risks  surrounding
major  interruptions  in  operational  performance  together  with adequacy and
timeliness of insurance  coverage thereto;  risks associated with political and
regulatory instability in Kurdistan;  risks associated with ratification of the
EPSA including the  possibility of changes to its terms;  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.

      For 2007,  Western remains focused on its key  initiatives:  the AOSP and
the  execution  of  Expansion 1; in-situ  evaluation  and  development  of both
Western's  in-situ  leases  and  the   Chevron-operated   Ells  River  Project;
evaluating and identifying downstream integration opportunities; and supporting
WesternZagros as it pursues its initiative in Kurdistan.

      Western's  2007  capital  budget is $715  million,  $655 million of which
relates  directly to the AOSP, $35 million is budgeted for in-situ  exploration
and development for both Chevron's and Western's in-situ leases, $20 million is
directed to WesternZagros'  initiative in Kurdistan and $5 million is allocated
to other corporate  capital items. Of the total budget,  $555 million or 78 per
cent is allocated to Expansion 1 of the AOSP. Capital expenditures  relating to
Expansion  1 are  expected to continue to grow over the next couple of years as
development  efforts  accelerate.  Western  anticipates its share of production
from the AOSP to  average  approximately  33,000 to 35,000  barrels  per day in
2007. Western is evaluating  capitalization  strategies and structures in order
to fund our share of forecasted capital  expenditures  which, for AOSPExpansion
1, is anticipated to be comprised solely of cash flow from operations  together
with incremental borrowings. If commodity prices continue to weaken as observed
in the early part of 2007,  Western's  strategic hedging program implemented in
fall  of  2005  provides  downside  protection  on the  majority  of  our  2007
production  and maintains a base level of cash flow.  This program is monitored
on an ongoing basis to ensure its specific  components  continue to achieve the
overall objectives.

<PAGE>

      Western  anticipates  research  and business  development  expenses to be
approximately $67 million in 2007, with 52 per cent of this amount dedicated to
projects at the Joint Venture  level.  The balance is earmarked for  technology
efforts  which  may  benefit   mining  and  in-situ   extraction  and  recovery
techniques,  assessments and reviews  associated with  identifying a downstream
opportunity for Western's share of bitumen production,  in-situ development and
corporate administrative expenses stemming from efforts in Kurdistan.

      In  2007,   Western  will  continue  to  pursue  downstream   integration
opportunities  to  maximize  value from its  growing  oil sands  resources  and
undeveloped acreage position. Related to these initiatives,  Western intends to
explore and pursue  alternatives  that enhance the full value of our assets and
future growth  potential.  This may result in an acquisition or sale of assets,
merger or other corporate transaction. Western's advisors, Goldman, Sachs & Co.
and TD Securities Inc. will be assisting in these  activities which may involve
contacting  third  parties.  There  can be no  assurances  that  any  of  these
activities  will result in the  consummation  of an agreement or transaction or
result in any change to Western's current ongoing business strategy.



FUTURE EXPANSIONS

Subsequent to year end, on January 24, 2007,  Western  announced  future growth
plans  for the  AOSP  with  proposed  permit  applications  that  would  enable
production  from  Expansions 3 through 5 of the Project.  These plans would see
mineable  production  increasing to  approximately  770,000  barrels per day or
154,000  barrels  per  day  net  to  Western.  These  volumes,   together  with
anticipated  production  of in excess of 50,000  barrels  per day from  in-situ
development would increase  Western's share of total bitumen production to more
than  200,000  barrels  per day  over  the  next 15 to 20  years.  We also  see
potential  for mining  expansions,  beyond  Expansion  5, based on the resource
potential of the unevaluated leases associated with the AOSP.

      Seeking early  stakeholder  and regulator  support is  fundamental to the
AOSP's growth strategy. The public disclosure documents were issued in order to
start the process of the AOSP's next phase of oil sands development,  including
the proposed  Jackpine Mine Expansion,  and an additional  mine,  called Pierre
River Mine, on the west side of the Athabasca River. The AOSP's growth strategy
includes the approved  Muskeg River Mine permit at 270,000  barrels per day and
the approved Jackpine Mine permit at 200,000 barrels per day. The Jackpine Mine
Expansion is a proposed  expansion of the Jackpine Mine to 300,000  barrels per
day,  representing  Expansions  1 through 3. The Pierre  River Mine  represents
Expansions  4 and 5,  initially  on Leases 9 and 17.  Actual  timing  for these
expansion projects will depend on market conditions,  key economic  indicators,
the ability to meet  sustainable  development  criteria  and the outcome of the
regulatory process.



RISK AND SUCCESS FACTORS RELATING TO WESTERN

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 following  table details the  sensitivities  of Western's cash flow and net
earnings  per share to certain  relevant  operating  factors of the Project for
2007.

<TABLE>
<CAPTION>
SENSITIVITY ANALYSIS

                                                             Basic                     Normalized
                                                          Cash Flow     Cash Flow       Earnings     Earnings
Variable                   Base Case         Variation  ($ millions)    per Share ($) ($ millions)  per Share ($)
-----------------------------------------------------------------------------------------------------------------
<S>                           <C>       <C>                   <C>            <C>         <C>           <C>
Production (bbls/d)           34,000    1,000 bbls/day        19.37          0.12        11.76         0.07
Oil Prices                    $60.00           US$1.00        12.02          0.07         7.55         0.05
Non-Gas Operating Costs       $16.53         $1.00/bbl        12.60          0.08         8.64         0.05
Gas Prices (1)                $ 7.71         $0.10/mcf         0.80          0.00         0.51         0.00
Foreign Exchange (2)          $ 0.87      US/Cdn $0.01         7.25          0.04         6.22         0.04
=================================================================================================================
</TABLE>
(1)   Each  $1.00 per  thousand  cubic  feet  change in gas price  results in a
change of $ 0.50 per barrel in operating cost.

(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 $4.1  million  based on December 31, 2006,  US
dollar denominated debt levels.


      Western's  financial  results  depend  on,  amongst  other  factors,  the
prevailing price of crude oil and the US/Cdn currency exchange rate. Oil prices
and currency  exchange rates fluctuate  significantly in response to supply and
demand  factors  beyond  our  control,  which  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
financial  results.  Hedging  activities  could  result  in losses or limit the
benefit of certain commodity price increases.

      Western's  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   depends  on  our  financial  and  operating
performance which, in turn, depends 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  Western's  exposure to these  financial  risks and provide a
stable  financial  footing as we enter  Expansion 1 of the AOSP, we completed a
strategic crude oil risk management  program.  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 is a series of put and call options.  Western  purchased puts at
various  levels and financed the cost of these puts,  in part,  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>

                                                     Period (calendar year)
-------------------------------------------------------------------------------
                                                  2007        2008        2009
-------------------------------------------------------------------------------
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
===============================================================================

($ thousands)                                                 2006        2005
-------------------------------------------------------------------------------
Risk Management Asset - Beginning of Period                 98,426          --
Net Premium                                                     --      84,976
Unrealized Gain (Loss) on Risk Management Asset             72,118      13,450
-------------------------------------------------------------------------------
Risk Management Asset - End of Period                       26,308      98,426
Less: Current Portion                                        7,601          --
-------------------------------------------------------------------------------
                                                            18,707      98,426
===============================================================================

      Western is required to finance its 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,  Western may require additional
financing to fund its activities until Business Interruption Insurance proceeds
are received.


Operational and Business Risks

Western  currently has only one producing  asset. As such, the vast majority of
our  capital  expenditures  is  directly  or  indirectly  related  to oil sands
construction,  development  and expansion,  with all of our operating cash flow
derived from oil sands operations.

      Western is 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.

      Western sells its 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 may 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  Western's share of
the Project's  synthetic crude oil production at economically viable prices.

      As an Owner in the AOSP,  Western  actively  participates  in operational
risk management programs implemented by the Joint Venture to mitigate the above
risks.  Western's  exposure to operational risks is also managed by maintaining
appropriate  levels of insurance.  To that end, in October 2006, Western placed
US$900 million of Property and Business Interruption  Insurance, up from US$800
million in 2005 as well as 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 on  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:

<PAGE>

      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 HMU and Dow Chemicals
Canada Inc., or Dow; and

      o     Electricity  and  steam  are  provided  to the  Upgrader  from  the
Upgrader cogeneration facility.

      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.

      Western 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,  equipment  and services
required to operate and maintain the plant.  The Joint Venture has  significant
expansion plan, and the strong working  relationships the Project has developed
with the trade unions will be an important factor in its future activities. The
Joint Venture's  relationship with its employees and provincial  building trade
unions  is  important  to  its  future  because  poor   productivity  and  work
disruptions  may adversely  affect the Project - whether in  construction or in
operations.

      In 2006, WesternZagros,  a wholly-owned subsidiary of Western,  announced
an initiative to explore for  conventional oil and gas in the Federal Region of
Kurdistan,  in northern Iraq. Oil and gas exploration activities have their own
inherent risks. However,  risks regarding this initiative are heightened due to
the political and economic instability in Iraq.  Agreements between the central
government an the regional provinces have yet to been finalized,  including the
petroleum  law,  which  results in risks related to 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". The Project may
be a significant  producer of some greenhouse gases covered by the treaty.  The
Government  of Canada has put forward a Climate  Change  Plan for Canada  which
suggests  further  legislation  will set greenhouse  gases  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.

<PAGE>

      Western 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
Western  does not meet the  minimum  credit  rating  required  under  the Joint
Venture Agreement, we must establish and fund a reclamation trust fund. Western
currently  does not hold the  minimum  credit  rating.  Even if we did 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 such a fund is
prudent or required, we may lack the financial resources to do so.

      The Joint Venture Owners 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 are  accountable  for  performance set by the
Joint Venture Owners.



NON-GAAP FINANCIAL MEASURES

Western includes cash flow from operations per share,  netback per barrel,  net
earnings excluding  unrealized  gain/(loss),  net earnings excluding unrealized
gain/(loss)  per share  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.  Western also includes 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,  normalized net
earnings,  normalized net earnings per share and EBITDAX provide a better basis
for evaluating its 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 financing costs and any future capital
requirements.


CRITICAL ACCOUNTING ESTIMATES

Western's  critical  accounting  estimates are defined as those  estimates that
have a  significant  impact on the  portrayal  of its  financial  position  and

<PAGE>

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
believe  to be  reasonable  under  current  conditions.  As  events  occur  and
additional information is obtained, these judgments,  assumptions and estimates
may be subject to change. Our critical  accounting  policies and estimates have
been  reviewed  and  approved  by our Audit  Committee,  in  consultation  with
Management. We believe the following are the critical accounting estimates used
in the preparation of our Consolidated  Financial  Statements.  Our significant
accounting  policies  can be  found  in  note 2 to the  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.  Conventional  crude oil and  in-situ  properties  are
accounted  for in  accordance  with the full  cost  method,  whereby  all costs
associated  with the  acquisition  of,  exploration  for and the development of
crude oil and in-situ  reserves,  including  asset  retirement  obligations are
capitalized and accumulated within cost centres on a country-by-country  basis.
Such costs  include land  acquisition,  geological  and  geophysical  activity,
drilling and testing of productive  and  non-productive  wells,  carrying costs
directly  related  to  unproved  properties,  major  development  projects  and
administrative   costs  directly   related  to  exploration   and   development
activities.

      Depletion on crude oil properties is provided over the life of proved and
probable  reserves  on a unit  of  production  basis  and  commences  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.

      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
are  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.


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.

<PAGE>

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.


Stock-based Compensation Plans

Western   recognizes   stock-based   compensation   as  part  of  general   and
administrative  expense in the  Consolidated  Statements  of Operation  for all
common share options  ("options") and  Performance  Share Units ("PSU's") after
January 1, 2003,  with a corresponding  increase in Contributed  Surplus in the
Consolidated  Balance  Sheets.  The expense is based upon the fair value of the
options and PSU's  determined  at the grant date  utilizing  the  Black-Scholes
option  pricing  model  and the  Monte-Carlo  Simulation  model,  respectively.
Western  also has a  Deferred  Share  Unit  Plan  which is  accounted  for on a
mark-to-market basis, whereby a liability and compensation expense are recorded
for each period based upon the number of Deferred Share Units  outstanding  and
the current market price of Western's shares.

      Western,  as an owner of the AOSP, shares in the related costs associated
with the AOSP's stock-based  compensation plans. The AOSP's plans involve Stock
Appreciation  Rights  which may  require  settlement  with cash  payments.  The
expense recognized as part of operating expense in the Consolidated  Statements
of Operations  and as part of Accounts  Payable and Accrued  Liabilities in the
Consolidated  Balance Sheets is determined at the balance sheet date based upon
the Black-Scholes option pricing model.


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.


Employee Future Benefits

Western,  as an owner of the  AOSP,  has a  defined  benefit  pension  plan for
employees of the AOSP.  Costs  associated to this plan are determined using the
projected  benefit method prorated on length of service and reflects the AOSP's
best  estimate of expected  plan  investment  performance,  salary  escalation,
retirement ages of employees,  withdrawal rates and mortality  rates.  Expected
return  on plan  assets  is  based on the fair  value of those  assets  and the
obligation is discounted  using a market  interest rate at the beginning of the
year based on high quality corporate debt instruments. Pension expense includes
the cost of pension  benefits earned during the current year, the interest cost

<PAGE>

on the pension  obligations,  the expected  return on pension plan assets,  the
amortization of adjustments arising from pension plan amendments and the excess
of the net  actuarial  gain or loss over 10 per cent of the greater of benefits
obligation and the fair value of plan assets.


Arrangements Containing a Lease

Western,  through its 20 per cent  ownership  interest  in AOSP,  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
("EIC-150"),  we are 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,  we are 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
its Consolidated Balance Sheet.



CHANGES IN ACCOUNTING POLICY

Stock-based  Compensation  for Employees  Eligible to Retire Before the Vesting
Date

For the year ending December 31, 2006, Western  retroactively  adopted Emerging
Issues Committee Abstract 162 ("EIC-162").  EIC-162 requires the Corporation to
recognize  stock-based  compensation  expense for awards  granted to  employees
eligible  for  retirement  under  stock-based  compensation  plans that contain
provisions that allow an employee to continue vesting in an award in accordance
with the stated vesting terms after the employee has retired.  During 2006, the
Corporation  amended the stock option and performance share unit plans allow an
employee to continue  vesting in an award in accordance with the stated vesting
terms after the employee has retired and, accordingly, stock-based compensation
expense  of $3.6  million  has been  included  in  general  and  administrative
expense,  representing  the  additional  compensation  expense  recognized  for
employees eligible for retirement during the vesting period. There is no impact
to the  Consolidated  Financial  Statements  as at December 31, 2005 as no such
retirement provisions existed during this period.


Non-monetary Transactions

On January 1, 2006, Western  prospectively  adopted CICA Handbook Section 3831,
"Non-Monetary   Transactions"   which  replaces  Section  3830,   "Non-Monetary
Transactions".  Section 3831  establishes  standards  for the  measurement  and
disclosure of non-monetary transactions. Section 3830 prescribes that exchanges
of non-monetary  transactions should be measured based on the fair value of the
assets  exchanged,  while providing an exception for non-monetary  exchanges in
transactions  which do not result in the  culmination of the earnings  process.
Section 3831 eliminates this exception provided in Section 3830 and replaces it
with an  exception  for  exchanges  of  non-monetary  assets  that do not  have
commercial substance.  A transaction has commercial substance when the entity's
future  cash  flows are  expected  to change  significantly  as a result of the

<PAGE>

transaction.  There is no impact on the  Consolidated  Financial  Statements as
Western did not have exchanges of  non-monetary  transactions  after January 1,
2006 within the scope of Section 3831.


Implicit Variable Interests under AcG-15

On January 1, 2006,  Western  adopted  Emerging Issues  Committee  Abstract 157
("EIC-157").  EIC-157 requires that a reporting  enterprise consider whether it
holds an implicit  variable interest in the Variable Interest Entity ("VIE") or
potential  VIE.  The  determination  of whether an implicit  variable  interest
exists  should also be based on whether  the  reporting  enterprise  may absorb
variability  on the VIE or  potential  VIE.  The  Corporation  has entered into
operating  leases,  as  described in note 19(a) to the  Consolidated  Financial
Statements,  with a VIE. These  operating  leases as structured do not meet the
criteria for  consolidation  by the Corporation and therefore,  the adoption of
this  accounting  policy  had no impact  on  Western's  Consolidated  Financial
Statements.


Conditional Asset Retirement Obligations

On January 1, 2006,  Western  retroactively  adopted  Emerging Issues Committee
Abstract 159 ("EIC-159").  EIC-159 clarifies that the term  "conditional  asset
retirement  obligation" as used in CICA 3110,  "Asset  Retirement  Obligations"
refers to a legal obligation to perform an asset  retirement  activity in which
the timing and (or) method of settlement are conditional on a future event that
may or may  not be  within  the  control  of the  entity.  EIC-159  requires  a
liability to be recognized for the fair value of a conditional asset retirement
obligation if the fair value of the liability can be reasonably  estimated;  an
entity to apply expected  present value technique if certain  conditions  exist
indicating  sufficient  information to reasonably  estimate  conditional  asset
retirement  obligation;  and that a liability should be recognized initially in
the period in which  sufficient  information  becomes  available  to estimate a
conditional asset retirement  obligations fair value. There is no impact on the
Consolidated Financial Statements from the retroactive adoption of EIC-159.



FUTURE CHANGES IN ACCOUNTING POLICY

Financial Instruments

The  CICA  issued  Section  3855,  "Financial  Instruments  -  Recognition  and
Measurement",  which prescribes when a financial instrument is to be recognized
on the balance  sheet and at what amount -  sometimes  using fair value,  other
times using  cost-based  measures.  This Section also  specifies  how financial
instrument gains and losses are to be presented.  A financial instrument is any
contract  that gives  rise to a  financial  asset of one party and a  financial
liability or equity  instrument of another  party.  These may include loans and
notes  receivable and payable,  investments  in debt and equity  securities and
derivative  contracts such as forwards,  swaps and options.  Other  significant
accounting implications arising on adoption of Section 3855 include the initial
recognition of certain financial  guarantees at fair value on the balance sheet
and the requirement to expense or use of the effective  interest rate method of
amortization for any transaction costs or fees, premiums or discounts earned or
incurred for financial  instruments  measured at amortized  cost.  This Section
applies to interim and annual  financial  statements  relating to fiscal  years
beginning  on or after  October 31,  2006.  Western  will adopt this Section on

<PAGE>

January  1, 2007 and does not  expect  there to be any  material  impact to the
Consolidated  Financial  Statements upon adoption of the standard on January 1,
2007.


Hedges

The CICA issued Section 3865, "Hedges", which replaces the guidance formerly in
Section 1650,  "Foreign  Currency  Translation"  and  Accounting  Guideline 13,
"Hedging  Relationships" by specifying how hedge accounting is applied and what
disclosures  are necessary when it is applied.  This Section applies to interim
and annual financial  statements relating to fiscal years beginning on or after
October 31, 2006.  Western  plans to adopt this  Section on January1,  2007 and
does not expect there to be any material impact on the  Consolidated  Financial
Statements upon adoption of the standard on January 1, 2007.


Financial Instruments - Disclosures and Presentations

The CICA issued  Section 3862,  "Financial  Instruments -  Disclosures",  which
modifies the disclosure  requirements of Section 3861, "Financial Instruments -
Disclosures  and  Presentation"  and Section  3863,  "Financial  Instruments  -
Presentations",  which carries forward unchanged the presentation  requirements
for financial  instruments of  Section3861.  Section 3862 requires  entities to
provide disclosures in their financial statements that enable users to evaluate
the significance of financial  instruments on the entity's  financial  position
and its  performance  and the nature and extent of risks arising from financial
instruments to which the entity is exposed during the period and at the balance
sheet date,  and how the entity manages those risks.  Section 3863  establishes
standards  for   presentation  of  financial   instruments  and   non-financial
derivatives.  It deals with the classification of financial  instruments,  from
the  perspective  of  the  issuer,   between  liabilities  and  equities,   the
classification   of  related  interest,   dividends,   losses  and  gains,  and
circumstances in which financial  assets and financial  liabilities are offset.
These Sections  apply to interim and annual  financial  statements  relating to
fiscal years beginning on or after October 1, 2007. Early adoption is permitted
at the same time an entity adopts other  standards  relating to the  accounting
for  financial  instruments.  Western plans to adopt this Section on January 1,
2007 and does not expect  there to be any material  impact on the  Consolidated
Financial Statements upon adoption of the standard on January 1, 2007.


Comprehensive Income

The CICA issued Section 1530,  "Comprehensive  Income",  which  established new
standards  for  reporting the display of  comprehensive  income.  Comprehensive
income is the change in equity (net assets) of an enterprise during a reporting
period from  transactions  and other events and  circumstances  from  non-owner
sources.  It includes  all  changes in equity  during the period  except  those
resulting from investments by owners and distributions to owners.  This Section
applies to interim and annual  financial  statements  relating to fiscal  years
beginning on or after October 31, 2006.  Earlier  adoption is permitted only as
at the beginning of a fiscal year ending on or after December 31, 2004. Western
plans to adopt this  Section on January 1, 2007 and does not expect there to be
any material impact on the Consolidated  Financial  Statements upon adoption of
the standard on January 1, 2007.


Equity

The CICA issued Section 3251, "Equity", which replaces Section 3250, "Surplus".
It establishes  standards for the  presentation of equity and changes in equity
during a reporting period. This Section applies to interim and annual financial

<PAGE>

statements  relating to fiscal years  beginning  on or after  October 31, 2006.
Western  plans to adopt  this  Section  on  January 1, 2007 and does not expect
there to be any material impact on the Consolidated  Financial  Statements upon
adoption of the standard on January 1, 2007.


Accounting Changes

The CICA issued  Section 1506,  "Accounting  Changes",  which  replaces  former
Section  1506.  The  Section  establishes   criteria  for  changing  accounting
policies,  together with the accounting  treatment and disclosure of changes in
accounting  policies and  estimates,  and  correction  of errors.  This Section
applies to interim and annual  financial  statements  relating to fiscal  years
beginning on or after  January 1, 2007.  Western plans to adopt this Section on
January  1, 2007 and does not  expect  there to be any  material  impact on the
Consolidated  Financial  Statements upon adoption of the standard on January 1,
2007.


Determining the Variability to be Considered in Applying AcG-15

The Emerging Issues Committee issued Abstract 163, "Determining the Variability
to be Considered in Applying AcG-15",  which addresses how an enterprise should
determine the variability to be considered in applying  AcG-15,  "Consolidation
of  Variable  Interest  Entities".   This  Abstract  applies  to  all  entities
(including  newly created  entities) with which that  enterprise  first becomes
involved,  and to all entities  previously required to be analyzed under AcG-15
when a  reconsideration  event has occurred pursuant to paragraph 11 of AcG-15,
beginning the first day of the interim or annual  reporting period beginning on
or after January 1, 2007. Retrospective  application to the date of the initial
application  of AcG-15,  is permitted but not required.  Western plans to adopt
this  Section on January 1, 2007 and does not expect  there to be any  material
impact on the Consolidated  Financial  Statements upon adoption of the standard
on January 1, 2007.


Capital Disclosures

The CICA issued Section 1535,  "Capital  Disclosures",  which  establishes  new
standards for disclosing  information  about an entity's  capital and how it is
managed.   It  requires  the  disclosure  of  information   about  an  entity's
objectives,  policies and processes for managing capital.  This Section applies
to interim and annual financial  statements  relating to fiscal years beginning
on or after October 1, 2007.  Western plans to adopt this Section on January 1,
2008 for the Consolidated Financial Statements.



CONTROLS AND PROCEDURES

Disclosure Controls

Disclosure controls and procedures are designed to provide reasonable assurance
that all relevant information is gathered, reported, processed,  summarized and
reported to  management,  including the President and Chief  Executive  Officer
("CEO") and the Chief  Financial  Officer  ("CFO"),  on a timely  basis so that
appropriate decisions are made regarding public disclosure.

      As of  December  31,  2006,  an  evaluation  was carried  out,  under the
supervision of and with the participation of management,  including the CEO and
CFO, of the effectiveness of our disclosure  controls and procedures as defined

<PAGE>

in Canada in Multilateral  Instrument  52-109,  Certification  of Disclosure in
Issuers'  Annual  and  Interim  Filings,  and in the  United  States  by  Rules
13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934. Based on
that evaluation, the CEO and CFO concluded that the design and operation of our
disclosure  controls and  procedures  were effective as at December 31, 2006 to
ensure that  information  required to be  disclosed  by us is  accumulated  and
communicated  to the  management  of  Western  to allow  for  timely  decisions
regarding required  disclosure as specified under Canadian and U.S.  securities
laws.


Internal Control over Financial Reporting

Our  management  is  responsible  for  establishing  and  maintaining  adequate
internal  control over  financial  reporting as defined in Rules  13a-15(f) and
15d-15(f)  under the Securities  Exchange Act of 1934, as amended and in Canada
as defined in Multilateral  Instrument  52-109 - Certification of Disclosure in
Issuers'  Annual and Interim  Filings.  Our  internal  control  over  financial
reporting is designed to provide reasonable assurance regarding the reliability
of our financial  reporting and  preparation  of our financial  statements  for
external purposes in accordance with accounting  principles  generally accepted
in Canada.  Our  internal  control  over  financial  reporting  includes  those
policies and  procedures  that:  pertain to the  maintenance of records that in
reasonable   detail   accurately  and  fairly  reflect  our   transactions  and
disposition of the assets;  provide reasonable  assurance that transactions are
recorded as necessary to permit  preparation  of our  financial  statements  in
accordance with generally accepted accounting  principles and that receipts and
expenditures   of  our  assets  are  being   made  only  in   accordance   with
authorizations  of  our  management  and  directors;   and  provide  reasonable
assurance regarding prevention or timely detection of unauthorized acquisition,
use or  disposition  of our assets  that  could  have a material  effect on our
financial  statements.  Because of its inherent  limitations,  internal control
over  financial  reporting  may not  prevent  or  detect  misstatements.  Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate  because of changes in conditions,
or  that  the  degree  of  compliance  with  the  policies  or  procedures  may
deteriorate.

      Our management, with the participation of our principal executive officer
and principal  financial  officer,  evaluated the effectiveness of our internal
control  over  financial  reporting  as of December  31,  2006.  In making this
evaluation,  management  used  the  criteria  set  forth  by the  Committee  of
Sponsoring  Organizations  of the  Treadway  Commission  ("COSO")  in  Internal
Control - Integrated Framework.

      There was one exclusion  from our  evaluation.  Our 20 per cent undivided
working  interest in the AOSP,  was excluded  from our  evaluation as we do not
have the  ability to dictate or modify  this  entity's  internal  control  over
financial  reporting,  and we do not have the ability,  in practice,  to assess
those controls.  However,  we have assessed our internal control over financial
reporting  with  respect  to the  inclusion  of our  share  of the AOSP and its
results of operations in our  consolidated  financial  statements.  For further
discussion of this  exclusion  from the scope of our  evaluation  see "Scope of
Management's Report on Internal Control over Financial Reporting" below.

      Based on our  evaluation,  our  management  concluded  that our  internal
control over financial reporting was effective as of December 31, 2006.

      Our management's  evaluation of the effectiveness of our internal control
over  financial  reporting  as of  December  31,  2006,  has  been  audited  by
PricewaterhouseCoopers  LLP, independent auditors, as stated in their report on
page 66 herein.

<PAGE>

Scope of Management's Evaluation of Internal Control over Financial
Reporting

Western  is the  holder  of a 20 per cent  undivided  interest  in the AOSP and
conducts  the  operation  of the AOSP through a Joint  Venture  Agreement  (the
"Agreement")  with Chevron,  the other 20 per cent interest holder,  and Shell,
the 60 per cent interest  holder.  The Agreement is structured such that Shell,
as the project  administrator and controller of the executive  committee of the
AOSP, is delegated all  managerial  responsibilities,  including the ability to
control  operations,  create accounts and keep internal controls over the AOSP.
Shell charges us our  proportionate  share of the  expenditures and provides us
with our  proportionate  share of  saleable  synthetic  crude  which we  market
directly to third parties.

      Pursuant  to  the  Agreement,   and  as  described  below,  we  have  the
contractual  right to audit  Shell's  determination  of our  share of costs and
outputs of the AOSP.  During our 2006 fiscal  year,  our 20 per cent  undivided
working interest in the AOSP comprised 96 per cent of our total Property, Plant
and  Equipment,  100 per cent of Operating  Expenses,  54 per cent of Purchased
Feedstocks  and  Transportation,  and 64 per  cent  of  Research  and  Business
Development Expense as at and for the year ended December 31, 2006. However, we
do not have the right or ability to dictate or modify the internal control over
financial  reporting of the AOSP, and we do not have the ability,  in practice,
to evaluate those controls.  Further,  we are not able to influence the control
environment or control  evaluations of the AOSP. As a result,  we have excluded
the AOSP from our  evaluation  of internal  control  over  financial  reporting
relating to the AOSP.

      Pursuant to the Agreement,  we have a control  structure  which includes,
among other things, the following:

      o      the  right  to  participate  in  the  committee  that  grants  the
authority under which all other  committees  operate  including the approval of
the annual budget;

      o      the right to participate in the committee that reviews  operations
and capital spending as well as the approval of certain spending and contracts;

      o      the  right  to  participate  in  quarterly  accounting  and  audit
committee meetings; and

      o      the right to  participate  in other  committees and work groups as
needed.

      In  addition,  we have and we exercise  our right to audit,  on a routine
basis, Shell's  determination of our share of costs as noted and outputs of the
AOSP.  Although  these  activities  do not provide the ability to evaluate  the
internal   control  over  financial   reporting  of  the  AOSP,  the  foregoing
constitutes a control  environment  for the purposes of evaluating our internal
control over  financial  reporting.  Accordingly,  despite the exclusion of the
AOSP from our  management's  review,  our management has evaluated our internal
control over financial  reporting with respect to the inclusion of our share of
the AOSP and its results in our consolidated financial statements.

      No changes were made in our internal  control  over  financial  reporting
during the year ended December31,  2006, that have materially affected,  or are
reasonably likely to affect, our internal control over financial reporting.