EXHIBIT 1
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                                [GRAPHIC OMITTED]
                           [LOGO - WESTERN OIL SANDS]




                             ANNUAL INFORMATION FORM











                                 March 28, 2006



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                                TABLE OF CONTENTS
                                                                           PAGE

INTRODUCTORY INFORMATION......................................................i
FORWARD LOOKING INFORMATION...................................................i
CORPORATE STRUCTURE...........................................................1
GENERAL DEVELOPMENT OF THE BUSINESS...........................................2
         Operating Activities.................................................2
         Financing Activities.................................................4
NARRATIVE DESCRIPTION OF THE BUSINESS.........................................4
         Project Overview.....................................................5
         Joint Venture Agreement..............................................6
                  General.....................................................6
                  Joint Venture and Related Agreements........................6
                  Executive Committee and Project Administrator...............6
                  Western Personnel...........................................7
         The Athabasca Oil Sands Project......................................7
                  Production History..........................................7
                  Production Estimates........................................7
                  Reserves, Resources and Land................................8
                  Reserves....................................................8
                  Costs Incurred.............................................13
                  Significant Factors or Uncertainties on Reserves Data......13
                  Land Tenure................................................13
                  Royalties..................................................13
                  Environmental Considerations...............................14
                  Abandonment and Reclamation Costs..........................14
                  Third Party Facilities.....................................15
                  Marketing and Sales........................................15
                  Insurance..................................................15
                  AOSP Expansions............................................16
                  Dispositions...............................................17
                  Proposed Expansions and Feasibility Study Agreement........17
                  Regulatory Approvals.......................................18
                  Resources..................................................18
                  Land Position..............................................19
                  Forward Contracts..........................................20
                  Tax Horizon................................................21
DIVIDEND POLICY..............................................................21
DESCRIPTION OF SHARE CAPITAL.................................................21
MARKET FOR SECURITIES........................................................23
CREDIT RATINGS...............................................................23
DIRECTORS AND OFFICERS.......................................................24
AUDIT COMMITTEE..............................................................27
         Composition and Qualifications......................................27
         Responsibilities and Terms of Reference.............................28
         Auditor Service Fees................................................28
RISKS AND UNCERTAINTIES......................................................29
TRANSFER AGENTS AND REGISTRAR................................................39

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                                TABLE OF CONTENTS
                                  (continued)
                                                                           PAGE

INTEREST OF EXPERTS..........................................................39
LEGAL PROCEEDINGS............................................................40
ADDITIONAL INFORMATION.......................................................40
GLOSSARY ....................................................................41

APPENDIX A - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR

APPENDIX B - REPORT OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION

APPENDIX C - AUDIT COMMITTEE CHARTER

<PAGE>

                            INTRODUCTORY INFORMATION

References  in  this  Annual  Information  Form  to  Western  Oil  Sands  Inc.
("Western"   or  the   "Corporation")   includes   Western  and  its  material
wholly-owned  subsidiaries,  852006  Alberta Ltd.,  Western Oil Sands L.P. and
Western Oil Development Inc. unless the context otherwise requires.  INITIALLY
CAPITALIZED  TERMS USED HEREIN AND NOT  OTHERWISE  DEFINED  HAVE THE  MEANINGS
ASCRIBED THERETO IN THE GLOSSARY.

Unless   otherwise   indicated,   all  financial   information   included  and
incorporated by reference in this Annual  Information Form is determined using
Canadian generally accepted  accounting  principles  ("Canadian GAAP"),  which
differs from  generally  accepted  accounting  principles in the United States
("U.S.  GAAP").  The  notes  to  Western's  audited   consolidated   financial
statements contain a discussion of the principal differences between Western's
financial results calculated under Canadian GAAP and under U.S. GAAP.

UNLESS  OTHERWISE  SPECIFIED,  ALL DOLLAR  AMOUNTS ARE  EXPRESSED  IN CANADIAN
DOLLARS,  ALL  REFERENCES TO "DOLLARS" OR "$" ARE TO CANADIAN  DOLLARS AND ALL
REFERENCES TO "US$" ARE TO UNITED STATES DOLLARS.

                           FORWARD LOOKING INFORMATION

This Annual  Information  Form  contains  certain  forward-looking  statements
relating  but not  limited  to  Western's  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 Corporation'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  associated  with  the  extraction,
treatment and upgrading of mineable oil sands deposits;  risks surrounding the
level and timing of capital  expenditures  required to fulfill  the  Project's
growth strategy;  risks of financing these growth  initiatives at commercially
attractive  levels;  risks of being unable to  participate  in  expansion  and
corresponding  loss of  voting  rights  in the  AOSP;  risks  relating  to the
execution  of  the  Project's  optimization  strategy;   risks  involving  the
uncertainty  of  estimates  involved in the reserve  and  resource  estimation
process,  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 commodity price and 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. Forward-looking statements are not based on historical
facts  but  rather  on  the  expectation  of  management  of  the  Corporation
("Management")  regarding  the  Corporation's  future  growth  or  results  of
operations,  production,  future capital and other expenditures (including the
amount, nature and sources of funding thereof),  competitive advantages, plans
for  and  results  of  drilling  activity,   environmental  matters,  business
prospects and opportunities.  These forward-looking  statements are made as of
the date of the  Annual  Information  Form,  and the  Corporation  assumes  no
obligation  to update or revise them to reflect  new events or  circumstances,
except as required by law. For additional information relating to risk factors
please refer to "Risks and Uncertainties".

<PAGE>

                            WESTERN OIL SANDS INC.

                            ANNUAL INFORMATION FORM

                              CORPORATE STRUCTURE

Western Oil Sands Inc. was  incorporated  under the BUSINESS  CORPORATIONS ACT
(Alberta) on June 18, 1999. The  Corporation  amended its articles on July 27,
1999, October 6, 1999, November 30, 1999, December 22, 1999, December 8, 2000,
March 14,  2001 and May 21, 2002 to change its name to Western Oil Sands Inc.,
to remove its  private  company  restrictions,  to amend its share  capital to
create a class of Non-voting  Convertible Equity Shares, to designate a series
of Class D Preferred  Shares and to fix the rights,  privileges,  restrictions
and conditions  attaching to such series and to increase the maximum number of
directors permitted.  On June 1, 2005, the Corporation amended its articles to
divide  the issued  and  outstanding  Class A Shares on a three for one basis,
such that each outstanding Class A Share resulted in three outstanding Class A
Shares (the "Share Split")

Western has the following material wholly-owned  subsidiaries;  852006 Alberta
Ltd.  (which  together  with  Western  holds a 20%  undivided  interest in the
Project) and Western Oil Development Inc., as shown below:

                               [GRAPHIC OMITTED]

                            _____________________
                           |                     |
           --------------- |       Western       | -----------------
           |               |       (Alberta)     |            100% |
           | 100%          |_____________________|                 |
 ____________________                    |               _____________________
|852006 Alberta Ltd. |           General |              |     Western Oil     |
|   (Alberta)        |           Partner |              |   Development Inc   |
|                    |\                  |              |      (Alberta)      |
|____________________| \      1% Limited |              |_____________________
                        \    Partnership |
                         \         Units |
             99% Limited  \              |
       Partnership Units   \             |
                            _________________________
                           |  Western Oil Sands L.P. |
                           |        (Alberta)        |
                           |_________________________|
                                         |
                                         | 20%
                                         |
                                       /  \
                                      /    \
                                     /      \
                                    /Project \
                                   /          \
                                  /____________\


Western's  head  office is located at 2400 Ernst & Young  Tower,  440 - Second
Avenue S.W., Calgary,  Alberta T2P 5E9 and its registered office is located at
Suite 3700, 400 Third Avenue S.W., Calgary, Alberta T2P 4H2.

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                                     -2-


                      GENERAL DEVELOPMENT OF THE BUSINESS

Western is a Canadian  corporation that holds a 20 percent undivided ownership
interest in the  multibillion  dollar  Joint  Venture that is  exploiting  the
recoverable bitumen reserves and resources found in certain oil sands deposits
located  in the  Athabasca  region  of  Alberta.  Shell and  Chevron  hold the
remaining 60 percent and 20 percent undivided  ownership interest in the Joint
Venture,  respectively. If a joint venture party acquires additional interests
in the Athabasca  region,  the other joint venture  parties have the option to
participate so that all parties are on an equal basis or on a basis  otherwise
agreed, in the acquired interest. These transactions are governed by the terms
set out in the Area of Mutual Interest Agreement ("AMI") and the Joint Venture
Agreement.  ("JVA"). The current operating Project,  which includes facilities
owned by the Joint Venture and third parties,  uses  established  processes to
mine oil sands deposits,  extract and upgrade the bitumen into synthetic crude
oil and vacuum gas oil, or VGO. Western is also actively pursuing research and
development efforts to add value to existing assets; downstream initiatives to
reduce  exposure to heavy oil  differentials;  and  identifying and evaluating
opportunities  in resource  development  of oil sands and other  ventures with
significant long-life hydrocarbon resource potential.

OPERATING ACTIVITIES

March 2006  represents  nearly three years of  commercial  operations  for the
Athabasca  Oil Sands Project  ("AOSP").  The Project has made great strides in
production  capacity,   recently   establishing  three  consecutive  quarterly
production  records in fiscal 2005 since its start-up and  commissioning.  The
maturation  of the  Project  has  proceeded  for the most part  without  major
incident but for the fire that  occurred at the Mine on January 6, 2003 during
the  start-up  and  commissioning.  This fire  occurred in the froth  cleaning
circuit  resulting  in  limited  damage,   primarily  to  electrical   cables,
instrumentation  and  insulation  in the  solvent  recovery  area of the froth
treatment plant. Repairs were completed expeditiously, however, severe weather
conditions  caused  broader  freeze  damage  and  impeded  progress.  Start-up
recommenced  on  April 4,  2003  and the  Project  achieved  fully  integrated
operations  between the Mine and the Scotford Upgrader on April 19, 2003. This
unfortunate  event resulted in the submission of insurance  claims pursuant to
various  policies  both by the Project and Western  itself.  All Joint Venture
claims have now been  settled,  however,  Western  continues to pursue its own
claims.

On June 1, 2003,  Western  reported the start of commercial  operations as all
aspects of the facilities became fully operational and the Project achieved 50
percent of the stated design  capacity of 155,000  barrels per day.  Since the
commencement of commercial  production,  ramp-up  continued  uninterrupted for
2003, with production increases each quarter. Production ramped-up at the Mine
to approach  design levels by the end of 2003,  averaging  138,000 barrels per
day in December.  Production in 2003 averaged  118,000 barrels per day. By the
end of 2003, nine months after  start-up,  the Project was operating at 89 per
cent of design  capacity.  In fiscal 2004,  the operation set several  records
including record monthly production and daily production to that point.

Despite the records set to that point, during the course of 2004 two unplanned
operational events occurred.  At the Mine site, the froth settlers for Train 2
failed in July 2004 and  repairs  and  modifications  were  required.  Similar
repairs were  conducted on the froth  settlers for Train 1. The froth settlers
form part of the froth treatment process which combines the rich bitumen froth
from storage tanks with a solvent to separate out the remaining solids,  water
and  heavy  asphaltenes.  The end  result  of this  process  is clean  diluted
bitumen.  Operations  were  brought  to full  capacity  at both  the  Mine and
Upgrader upon  completion of these repairs,  however,  additional  operational
issues surfaced at the Upgrader.  The extent of this unforeseen event, and the
associated  events that followed,  resulted in lower production for the fourth
quarter of 2004 which  lagged  into the first  quarter  of 2005  resulting  in
yearly production levels far

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                                     -3-


below the  Corporation's  expectations.  Measured  steps were taken to avoid a
recurrence  of these  events in the future and key  learnings  were  obtained,
setting the stage for the record  production levels achieved in the last three
quarters of 2005. Full  production at both the Mine and Upgrader  re-commenced
on January 30, 2005.

The key  lessons  garnered  from these  repairs  set the stage for the ensuing
consecutive  quarterly  production records  established from the second to the
fourth  quarter of 2005.  Average  production  for 2005 reached  nearly160,000
barrels per day which is above the original  stated  calendar day design rate,
an increase of 18 per cent from approximately 135,500 barrels per day recorded
in 2004. The Project achieved this production record with particular focus and
attention to reliability and increased  availability of the facilities at both
the Mine and the  Upgrader.  Within  the space of less than three  years,  the
Project has progressed  from start-up and  commissioning  to exceeding  stated
design rates. This rapid timeline has exceeded performance expectations for an
operation  of this size and  complexity  and is due to the  dedication  of the
Project's  personnel,  together  with  personnel at Albian which is the AOSP's
operating entity for the Mine.

Operating  costs for 2005 were $22.06 per processed  barrel,  up slightly from
$21.17 per processed barrel in 2004 in large part due to inflationary  impacts
to labour,  materials and higher natural gas costs  associated with the robust
commodity market.

Fiscal 2005 represented the second full year of commercial  operations for the
Project. A few noteworthy milestones included:

         o    production  of 100  million  barrels of bitumen in just over two
              years of operation;

         o    record consecutive quarterly production in the second, third and
              fourth  quarters  of  approximately  164,000  barrels  per  day,
              165,000   barrels   per  day  and   178,000   barrels  per  day,
              respectively;

         o    record annual  production of  approximately  160,000 barrels per
              day of bitumen in 2005;

         o    Albian  became  the first  company in Canada to become ISO 14001
              certified under the new standards; and

         o    Albian  achieved one year  without a lost time  incident on July
              1st and July 5th marked four million person hours without a lost
              time incident.

These  milestones   demonstrate  the  Project's  ability  to  safely  extract,
transport and process significant volumes of bitumen.  However, the Project is
complex and can, from time to time, experience  unforeseen  operational issues
requiring  immediate  attention and repair as has been evidenced over the last
several years. When these events occur, the Joint Venture  systematically  and
methodically  addresses  the outages to return to full  production  as soon as
practicable and applies the lessons learned to prevent future outages.

Subsequent to the year-ended  December 31, 2005, the conveyor belt used at the
Mine to  transport  bitumen  ore from the primary  crushers to the  extraction
plant developed a vertical tear. As a result,  overall operations were reduced
to approximately one-third of stated design rates for three weeks. Repairs and
replacement  of the  conveyor  belt  were  completed  ahead of  schedule  with
production brought back to stated design rates on March 20, 2006.

The Project  continues to make  progress on production  optimization  programs
which once completed,  are expected to increase  production volumes to between
180,000  and  200,000  barrels  per  day by 2008 -  2009.

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                                     -4-


These  optimization  programs,  as well as other  initiatives,  do not require
significant amounts of capital to complete.  Therefore,  Western believes that
substantial   additional  volumes  may  be  achieved  with  a  modest  capital
investment  over  the  course  of the next  two to  three  years to meet  this
objective. See "Forward-looking Information" and "Risks and Uncertainties"

FINANCING ACTIVITIES

Western has used a combination of debt and equity capital to fund its share of
Project capital costs associated with  construction and its share of operating
costs.  Western's  credit  position has improved  significantly  over the last
several years as excess free cash flow has been aggressively applied to reduce
its revolving bank facilities. The following outlines key financing activities
up to and  including  fiscal 2005  undertaken by the  Corporation  in the last
three years:

         o    A public  offering of Common Shares at $8.17 per share (adjusted
              to  reflect  the Share  Split)  for gross  proceeds  of  $50.225
              million completed on February 7, 2003;

         o    On October 16, 2003, the Corporation entered into a $240 million
              credit  facility  (the  "Revolving   Credit  Facility")  with  a
              syndicate of Canadian  chartered banks. This facility replaced a
              $110 million credit facility  entered into by the Corporation in
              November  2002 and  subsequently  amended in 2003 (the  "Working
              Capital  Facility").  The  proceeds  were used to repay  amounts
              outstanding  under a bridge  facility  entered  into in  October
              2001,  the Working  Capital  Facility and to provide for working
              capital during operations.

         o    A  $68  million   bought-deal  equity  offering   consisting  of
              6,000,000 Common Shares at a price of $11.33 per share (adjusted
              to reflect the Share Split) completed on April 8, 2004;

         o    During  March 2005,  Western  successfully  refinanced  its $100
              million  Senior Credit  Facility by the  assumption of this full
              amount  into  Western's   Revolving  Credit  Facility,   thereby
              increasing the Revolving  Credit  Facility to $340 million.  The
              additional  $100  million  is  subject  to the  same  terms  and
              conditions as those contained in the Revolving Credit Facility;

         o    During  October  2005,  Western  successfully  amended  its $340
              million  Revolving  Credit  Facility  with respect to pricing or
              spreads  on  both  drawn  and  undrawn  allocations  to  reflect
              Western's  improved  credit  position.  Western also amended the
              structure  of the  Revolving  Credit  Facility  from  a  364-day
              revolver  with a two year term-out  provision for  non-revolving
              allocations  to  a  three-year   revolving  facility  extendible
              annually at the lenders' discretion; and

         o    Repayment of $175 million in debt credit  facilities  during the
              course of fiscal 2005.

                     NARRATIVE DESCRIPTION OF THE BUSINESS

Western is a Canadian  corporation that holds a 20 percent undivided ownership
interest in a  multibillion  dollar Joint  Venture to exploit the  recoverable
bitumen resources found in certain oil sands deposits at the Muskeg River Mine
located on the western  portion of Lease 13. This is Western's  only  material
asset and it is our primary  focus.  Shell and Chevron  hold the  remaining 60
percent and 20 percent  undivided  ownership  interest  in the Joint  Venture,
respectively.  Detailed  expansion  plans  are  underway  to  exploit  bitumen
resources on other  mineable oil sands leases in the  Athabasca  area in which
Western has a right to  participate.  Lease 13 is located in northern  Alberta
approximately  70 km north of Fort McMurray,  Alberta,  abutting the Athabasca
River; and the integrated  Scotford Upgrader is situated near Shell's existing
refinery  near  Fort  Saskatchewan,   Alberta.  The  Project,  which  includes
facilities  owned by the Joint  Venture and third  parties,  uses  established
processes  to mine oil sands  deposits,  extract and upgrade the bitumen  into
synthetic  crude oil and vacuum  gas oil,  or VGO.  Western  is also  actively
pursuing

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                                     -5-


research and development  efforts to add value to existing assets;  downstream
initiatives to reduce exposure to heavy oil differentials; and identifying and
evaluating  opportunities  in  resource  development  of oil  sands  and other
ventures with significant long-life hydrocarbon resource potential.

Construction  of the Mine and Upgrader was  completed in December  2002,  at a
total  capital cost of $5.7  billion  ($1.14  billion to  Western's  account).
Bitumen production  commenced at the Mine in January 2003, reaching commercial
levels in June 2003.  Ramp up of production at the Project  continued  through
2004 with average  production  of  approximately  135,500  barrels per day (87
percent of design capacity).  Considerable focus and attention was directed to
increased  reliability  and  availability  of our  extraction  facilities  and
upgrader during 2005,  resulting in production  records for three  consecutive
quarters,  aggregating to a yearly production record of nearly 160,000 barrels
per day. This production level is above the stated calendar day design rate of
155,000  barrels  per  day  as the  Project  continues  to  look  for  product
optimization programs to enhance reliability further.

As at December 31, 2005, Western had 41 employees.

PROJECT OVERVIEW

The Project is  designed to produce  high  quality  bitumen by surface  mining
certain  Athabasca oil sands deposits and upgrading the extracted bitumen into
custom blended petroleum products for sale to conventional refineries where it
is used to produce petroleum products. Approximately 275,000 tonnes per day of
ore, in addition to  approximately  155,000 tonnes per day of overburden,  low
grade  (waste)  oil sand and  extraction  plant  rejects can be mined from the
Mine.  At design  rates  approximately  155,000  barrels per day of bitumen is
extracted  from  this ore in the  Extraction  Plant and with the  addition  of
non-bitumen  feedstocks  approximately  190,000  barrels  per day of  refinery
feedstocks and synthetic crude oil blends can be produced by the Upgrader.

The Project is an integrated oil sands development in which:

         o    Oil sands  deposits are mined using open pit  techniques  at the
              Mine  located on the  western  portion  of Lease 13,  which is a
              truck and shovel mine operation;

         o    Raw bitumen is extracted  from the oil sands  through  processes
              powered by electrical and thermal energy at the Extraction Plant
              that  is  located  on the  western  portion  of  Lease  13.  The
              extraction  process  consists  of primary  extraction  and froth
              treatment stages;

         o    Once extracted,  the raw bitumen  feedstock is transported  from
              the Mine through a dual pipeline system to the Scotford Upgrader
              located  near Fort  Saskatchewan,  Alberta  where it is upgraded
              into refinery feedstocks;

         o    Upgrading  is the final  stage of the  production  process.  The
              bitumen   feedstock  is  distilled  to  recover  diluent,   then
              undergoes   a    hydro-conversion    process   with   integrated
              hydro-treating to generate suitable product streams; and

         o    After the  bitumen  has been  upgraded,  it is sold as  refinery
              feedstock  to  North  American  refineries  and to the  Scotford
              Refinery,  which  is  adjacent  to the  Scotford  Upgrader,  for
              further processing. A dual pipeline system connects the Scotford
              Upgrader to certain third party pipelines in Edmonton, Alberta.

<PAGE>
                                     -6-


JOINT VENTURE AGREEMENT

The  following  section  describes  the  general  terms of the  Joint  Venture
Agreement and certain other relevant agreements.

GENERAL

The  Joint  Venture,  which  commenced  December  6,  1999,  consists  of  the
following:  (i) the mining of oil sands from the western  portion of Lease 13;
(ii) extraction of bitumen from such oil sands at the Extraction Plant;  (iii)
the upgrading of such diluted bitumen in the Upgrader into refinery feedstocks
and synthetic  crude oil blends;  (iv) certain rights of the  Corporation  and
Chevron to participate  in mining  operations on the east area of Lease 13 and
in  Shell's  Other  Athabasca  Leases;  (v) an area  of  mutual  interest  for
expansion of  operations of the Joint  Venture;  (vi) the  disposition  of the
Upgrader  products;  and (vii) the  construction  operations  relating  to the
foregoing.

The Joint  Venture has been  established  pursuant  to a number of  agreements
among the Owners and is the subject of other agreements between the Owners and
third parties.

JOINT VENTURE AND RELATED AGREEMENTS

The principal  agreement,  which established the Joint Venture and governs the
relationship  of the Owners,  is the Joint Venture  Agreement.  This agreement
also sets out the manner in which certain of the other Project agreements will
be managed.

The agreement  provides for the formation of the Joint Venture,  the manner in
which the Joint Venture is administered,  the creation and manner in which the
Executive  Committee,  which is the  decision  making  body in respect of most
matters,   functions,  the  responsibilities  of  the  project  administrator,
secondments  of  Owners'  personnel,   budgets,   costs,  technology  matters,
dispositions,  defaults,  environmental  matters,  expansions,  Owner's rights
vis-a-vis each other, as well as financial, accounting, banking matters, basic
design parameters of the Project and other matters.

The  Joint  Venture  continues  until  all  abandonment  and   decommissioning
obligations  of the Owners have been fulfilled in accordance  with  applicable
laws and all required regulatory approvals have been received, all third party
Project  agreements  have been terminated and all accounts among the Owners in
respect of the Project have been settled.

EXECUTIVE COMMITTEE AND PROJECT ADMINISTRATOR

The  Joint  Venture  Agreement  establishes  an  Executive  Committee  that is
responsible for most decisions relative to the Joint Venture, other than those
which are requirements of the Owners. One of Shell's  representatives has been
appointed   as  the  first   Chairman  and  each  Owner  has   appointed   two
representatives to the Executive Committee.  Voting at the Executive Committee
level is based upon Owners' ownership interests.

The Executive  Committee  also oversees the  operations of Albian and Shell as
operators  of the Mine and  Extraction  Plant  and the  Upgrader  and  related
facilities  and ensures that each Owner has an ongoing  opportunity to provide
qualified secondees to the Project.

The project  administrator,  which initially is Shell,  has an  administrative
function and deals with day to day matters that include making  payments under
third-party  Project  agreements  and  dealing  with  administrative   matters
relating to non-performing  Owners.  The project  administrator is responsible
for

<PAGE>
                                     -7-


carrying out the  directions  of the  Executive  Committee  and  appointing an
individual to act as project integration manager.

WESTERN PERSONNEL

Albian  operates the Mine and the  Extraction  Plant  pursuant to an operating
agreement. The mining and extraction services agreement dated December 6, 1999
between  Western and Albian (the "Mining and Extraction  Services  Agreement")
sets out that  Western will provide  certain  mine and  extraction  management
services including the full and part-time services of certain of its employees
and consultants to Albian. Further, Western will identify additional personnel
to be employed by Albian  beyond the Western  personnel  who are necessary for
the operation of the Mine and the Extraction Plant. Western has five employees
working directly for the Joint Venture, two of which are operational personnel
at the Mine while the  remaining  three are based in Calgary and their primary
role is to  assist  with  our  Joint  Venture  partners  in the  planning  and
feasibility studies associated with expansion initiatives.  All costs incurred
by Western and approved by the Executive Committee in respect of the provision
of  services  by  Western  pursuant  to the  Mining  and  Extraction  Services
Agreement are reimbursed by Albian.

THE ATHABASCA OIL SANDS PROJECT

PRODUCTION HISTORY

The following  table sets forth certain  information in respect of production,
product prices received, royalties,  production costs and netbacks received by
Western for its synthetic  crude oil  production  for each quarter of its most
recently completed financial year:

<TABLE>
<CAPTION>
                                                            THREE MONTHS ENDED
                                  --------------------------------------------------------------------
                                  MARCH 31, 2005  JUNE 30, 2005  SEPTEMBER 30, 2005  DECEMBER 31, 2005
                                  --------------  -------------  ------------------  -----------------
<S>                                  <C>            <C>               <C>                <C>
Average Daily Production - dry
bitumen basis (bbl/day)              26,503         32,757            33,034             35,572

Average Net Prices Received
($Cdn/bbl)                            50.44           66.74            77.38               68.28

Royalties ($Cdn/bbl)                   0.28           0.30              0.46               0.32

Operating Expenses ($Cdn/bbl)         24.79           18.57            21.33               21.72

Feedstocks ($Cdn/bbl)                 11.56           17.14            16.29               17.58

Netback Received
($Cdn/bbl)((2))                       13.81           30.73            39.30               28.66
</TABLE>

NOTES:
(1)      All per barrel amounts are stated on a dry production bitumen basis.
(2)      Netback is calculated as oil sands revenue less royalties, operating
         expenses and feedstocks on a per barrel of production basis.

PRODUCTION ESTIMATES

Western  estimates that its synthetic  crude oil production from the AOSP will
be between  145,000 to 150,000  barrels per day (29,000 to 30,000  barrels per
day,  net to  Western)  for 2006.  Production  for 2006 will be impacted by an
estimated  eight week  turnaround  of the entire  operation  during the second
quarter of 2006 together with the unscheduled repairs in March to the conveyor
belt at the Mine.  Production from the Project  accounts for 100% of Western's
estimated production in 2006.

<PAGE>
                                     -8-


RESERVES, RESOURCES AND LAND

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

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

RESERVES

Lease 13  encompasses  49,872 acres  hectares and lies within the mineable oil
sands area of the Athabasca deposits. Bitumen has been extracted from the west
side of Lease 13 for nearly  three  years.  The  operating  Mine  covers a 121
square kilometre portion of the western portion of Lease 13.

GLJ Petroleum  Consultants  Ltd.  ("GLJ") prepared a report dated February 13,
2006 which  evaluated the reserves  attributable to Western as of December 31,
2005.  This west  portion  of Lease 13 has been  estimated  by GLJ to  contain
approximately  1.6  billion  barrels  of oil.  Of the 1.6  billion  barrels of
reserves,  approximately  1.0 billion  barrels are proved  reserves  while 0.6
billion  barrels are  considered  probable  reserves.  Based on the  Project's
design capacity,  the Mine has a reserve life index (both proved and probable)
of 27 years at a non-declining  undiluted  bitumen  production rate of 155,000
barrels per day.

The following  table below  outlines the Joint  Venture's  proved and probable
reserves on the western portion of Lease 13 as estimated by GLJ.

-------------------------------------------------------------------------------
                                                                      WESTERN'S
                                                            TOTAL       SHARE
                                                           (MMBBLS)    (MMBBLS)
-------------------------------------------------------------------------------

JOINT VENTURE (RESERVES)
  Western portion of Lease 13                               1,551          310

-------------------------------------------------------------------------------

Reserves  represent  those  quantities  of  oil  and  gas  anticipated  to  be
economically recoverable from Discovered Resources.  Quantities of oil and gas
must not be classified  as reserves  unless there is an  expectation  that the
accumulation  will be developed and placed on  production  within a reasonable
timeframe.  Reserves are a subset of recoverable  resources  which itself is a
subset of discovered resources. See "Resources".

The tables  below  summarize  the upgraded  bitumen  reserves and the value of
future net revenue attributable to Western's ownership as evaluated in the GLJ
Report.  The  information  set forth  below  relating  to  Western's  reserves
constitutes  forward-looking information which is subject to certain risks and
uncertainties.    See    "Forward-Looking    Information"   and   "Risks   and
Uncertainties".

All evaluations of future revenue are after the deduction of future income tax
expenses, unless otherwise noted in the tables,  royalties,  development costs
and  production  costs,  but before  consideration  of indirect  costs such as
administrative,  overhead  and other  miscellaneous  expenses.  THE  ESTIMATED
FUTURE NET  REVENUES  CONTAINED  IN THE  FOLLOWING  TABLES DO NOT  NECESSARILY
REPRESENT  THE FAIR MARKET VALUE OF THE  CORPORATION'S  RESERVES.  THERE IS NO
ASSURANCE  THAT THE FORECAST PRICE AND COST  ASSUMPTIONS

<PAGE>
                                     -9-


CONTAINED IN THE GLJ REPORT WILL BE ATTAINED AND VARIANCES  COULD BE MATERIAL.
Other assumptions and  qualifications  relating to costs and other matters are
included in the GLJ Report. The recovery and reserves  estimates  attributable
to Western's  ownership in the Project are estimates only. Actual reserves may
be greater or less than those calculated.

It is noted that the accuracy of any reserve  estimate,  especially when based
on volumetric analysis,  is a function of the quality of available data and of
engineering  interpretation  and judgment.  While reserve estimates  presented
herein are considered  reasonable,  performance  subsequent to the date of the
estimate may justify their revision, either upward or downward. The GLJ Report
presents net revenue projections prepared for the reserves attributable to the
ownership interest of Western along with a discussion of the evaluation.

<TABLE>
<CAPTION>
                                    SUMMARY OF RESERVES AS AT DECEMBER 31, 2005

                                                    CONSTANT PRICES AND COSTS           FORECAST PRICES AND COSTS
                                                ----------------------------------- ----------------------------------
                                                         UPGRADED BITUMEN                   UPGRADED BITUMEN
                                                ----------------------------------- ----------------------------------
                                                     GROSS              NET              GROSS              NET
                                                    (MMBBL)           (MMBBL)           (MMBBL)           (MMBBL)
                                                ---------------    -------------    --------------    -------------
<S>                                                   <C>               <C>               <C>               <C>
Proved Developed Producing                            190               182               190               175
Proved Developed Non-Producing                         5                 4                 5                 4
                                                ---------------    -------------    --------------    -------------
Total Proved                                          195               186               195               179
Total Probable                                        115               109               115               104
                                                ---------------    -------------    --------------    -------------
Total Proved Plus Probable                            310               295               310               283
                                                ===============    =============    ==============    =============
</TABLE>

<TABLE>
<CAPTION>
                                     NET PRESENT VALUES OF FUTURE NET REVENUE
                                        BASED ON CONSTANT PRICES AND COSTS

                                         BEFORE DEDUCTING INCOMES TAXES            AFTER DEDUCTING INCOME TAXES
                                     ----------------------------------------  -------------------------------------
                                                                                                      DISCOUNTED AT
                                       UNDISCOUNTED       DISCOUNTED AT 10%       UNDISCOUNTED            10%
                                           (MM$)                (MM$)                (MM$)                (MM$)
                                     ------------------  --------------------  -------------------  -----------------
<S>                                        <C>                  <C>                  <C>                 <C>
Proved Developed Producing                 6,109                3,099                4,498               2,423
Proved Developed Non-Producing              232                  240                  148                 152
                                     ------------------  --------------------  -------------------  -----------------
Total Proved                               6,341                3,339                4,645               2,575
Total Probable                             4,015                 960                 2,672                639
                                     ------------------  --------------------  -------------------  -----------------
Total Proved Plus Probable                10,356               4,299                7,317               3,214
                                     ------------------  --------------------  -------------------  -----------------
</TABLE>

The following tables present the estimated future net revenue  attributable to
Western, as set forth in the GLJ Report:

<TABLE>
<CAPTION>
                                      TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
                                        BASED ON CONSTANT PRICES AND COSTS

                                                                                  FUTURE               FUTURE
                                                                                    NET                  NET
                                                                  ABANDONMENT    REVENUE              REVENUE
                                                                      AND         BEFORE               AFTER
                                      OPERATING    DEVELOPMENT     RECLAMATION     INCOME    INCOME     INCOME
                 REVENUE  ROYALTIES     COSTS         COSTS          COSTS         TAXES     TAXES      TAXES
                  (MM$)     (MM$)       (MM$)         (MM$)          (MM$)         (MM$)     (MM$)      (MM$)
                --------- ----------  ----------  -------------  --------------  ---------- --------  --------
<S>              <C>         <C>        <C>            <C>             <C>        <C>        <C>        <C>
Total Proved     11,377      519        4,087          429             -           6,341     1,696      4,645
                --------- ----------  ----------  -------------  --------------  ---------- --------  --------
Total Proved
Plus Probable    18,111      910        6,243          602             -          10,356     3,039      7,317
                --------- ----------  ----------  -------------  --------------  ---------- --------  --------
</TABLE>

<PAGE>
                                     -10-

                    FUTURE NET REVENUE BY PRODUCTION GROUP
                      BASED ON CONSTANT PRICES AND COSTS

The future net revenue  before income taxes and  discounted at 10% per year in
respect of the total proved and total proved plus  probable  upgraded  bitumen
reserves  attributable  to Western's  ownership  interest in the Project as at
December 31, 2005 are $3,339 million and $4,299 million, in each case based on
constant prices and costs.

<TABLE>
<CAPTION>
                                     NET PRESENT VALUES OF FUTURE NET REVENUE
                                        BASED ON FORECAST PRICES AND COSTS

                                     BEFORE DEDUCTING INCOME TAXES              AFTER DEDUCTING INCOME TAXES
                                             DISCOUNTED AT                              DISCOUNTED AT
                               ------------------------------------------ ----------------------------------------
                                 0%       5%      10%     15%      20%      0%       5%      10%     15%      20%
                               (MM$)    (MM$)    (MM$)   (MM$)    (MM$)   (MM$)    (MM$)    (MM$)   (MM$)    (MM$)
<S>                            <C>      <C>      <C>     <C>      <C>     <C>      <C>      <C>     <C>      <C>
Proved Developed Producing     3,494    2,473    1,875   1,502    1,254   2,755    2,029    1,595   1,316    1,127
Proved Developed
Non-producing                    156      163      139     109       83      96      100       84      64       47
                               -----    -----    -----   -----    -----   -----    -----    -----   -----    -----
Total Proved                   3,650    2,636    2,014   1,611    1,337   2,851    2,130    1,679   1,381    1,174
Total Probable                 2,799    1,301     671     386      248    1,862     866      448     260      168
                               -----    -----    -----   -----    -----   -----    -----    -----   -----    -----
Total Proved Plus Probable     6,449    3,937    2,685   1,997    1,585   4,713    2,996    2,127   1,641    1,342
                               =====    =====    =====   =====    =====   =====    =====    =====   =====    =====
</TABLE>

<TABLE>
<CAPTION>
                                      TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
                                        BASED ON FORECAST PRICES AND COSTS

                                                                                  FUTURE               FUTURE
                                                                                    NET                  NET
                                                                  ABANDONMENT    REVENUE              REVENUE
                                                                      AND         BEFORE               AFTER
                                      OPERATING    DEVELOPMENT     RECLAMATION     INCOME    INCOME     INCOME
                 REVENUE  ROYALTIES     COSTS         COSTS          COSTS         TAXES     TAXES      TAXES
                  (MM$)     (MM$)       (MM$)         (MM$)          (MM$)         (MM$)     (MM$)      (MM$)
                --------- ----------  ----------  -------------  --------------  ---------- --------  --------
<S>              <C>         <C>        <C>           <C>             <C>        <C>         <C>        <C>
Total Proved      9,203        723      4,316         514             -          3,650         799      2,851
Total Proved
Plus Probable    15,526      1,341      6,964         772             -          6,449       1,736      4,713
</TABLE>

                    FUTURE NET REVENUE BY PRODUCTION GROUP
                      BASED ON FORECAST PRICES AND COSTS

The future net revenue  before income taxes and  discounted at 10% per year in
respect of the total proved and total proved plus  probable  upgraded  bitumen
reserves  attributable  to Western's  ownership  interest in the Project as at
December 31, 2005 are $2,014 million and $2,685 million, in each case based on
forecast prices and costs.

           RECONCILIATION OF NET RESERVES BY PRINCIPAL PRODUCT TYPE
                      BASED ON CONSTANT PRICES AND COSTS

Both fiscal 2005 and 2004 represent  full years of  production.  The following
table sets forth a reconciliation of the changes in Western's bitumen reserves
as at December 31, 2005 against such reserves as at December 31, 2004 based on
the constant price and cost assumptions set forth in Note 8 below:

<PAGE>
                                     -11-

<TABLE>
<CAPTION>
                                                           UPGRADED BITUMEN
                                           ---------------------------------------------
                                                                         NET PROVED PLUS
                                           NET PROVED     NET PROBABLE      PROBABLE
                                             (MMBBL)         (MMBBL)         (MMBBL)
                                           ----------     ------------      --------
<S>                                            <C>               <C>          <C>
At December 31, 2004                           202               112          314
                                           ----------     ------------      --------
     Extensions                                 -                 -             -
     Improved Recovery                          -                 -             -
     Technical Revisions                        3                 2             5
     Discoveries                                -                 -             -
     Acquisitions                               -                 -             -
     Dispositions                               -                 -             -
     Economic Factors                          (7)               (5)          (12)
     Production                               (12)                -           (12)
                                           ----------     ------------      --------
At December 31, 2005                           186               109           295
</TABLE>

     RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE NET REVENUE
             DISCOUNTED AT 10% BASED ON CONSTANT PRICES AND COSTS

The following  table sets forth changes  between future net revenue  estimates
attributable  to net proved  reserves as at December  31,  2005  against  such
reserves as at December 31, 2004:

<TABLE>
<CAPTION>
                                                                                         (MM$)
                                                                                         -----
<S>                                                                                      <C>
Estimated Future Net Revenue at December 31, 2004                                        1,832
                                                                                         -----

  Sales and Transfers of Oil and  Gas Produced, Net of Production Costs and Royalties     (237)
  Net Change in Prices, Production Costs and Royalties Related to Future Production      1,378
  Changes in Previously Estimated Development Costs Incurred During the Period              28
  Changes in Estimated Future Development Costs                                           (196)
  Extensions and Improved Recovery                                                           -
  Discoveries                                                                                -
  Acquisitions of Reserves                                                                   -
  Dispositions of Reserves                                                                   -
  Net Change Resulting from Revisions in Quantity Estimates                                 24
  Accretion of Discount Pre Tax                                                            183
  Net Change in Income Taxes                                                              (437)
  Other changes, including Hedging                                                           -
                                                                                         -----
Estimated Future Net Revenue at December 31, 2005                                        2,575
                                                                                         =====
</TABLE>
NOTES:
(1) Reserve definitions consistent with National Instrument 51-101 - Standards
    of Disclosure for Oil and Gas  Activities  ("NI 51-101") have been used in
    the GLJ Report,  where:  "Proved"  reserves are those reserves that can be
    estimated with a high degree of certainty to be recoverable.  The targeted
    level of certainty under a specific set of economic conditions is at least
    a 90 percent probability that the quantities actually recovered will equal
    or exceed the  estimated  proved  reserves  "Probable"  reserves are those
    reserves that are less certain to be recovered than proved reserves. It is
    equally  likely that the actual  remaining  quantities  recovered  will be
    greater  or  less  than  the sum of the  estimated  proved  plus  probable
    reserves.   "Proved  Plus  Probable"  reserves  include  those  additional
    reserves that are less certain to be recovered than proved  reserves.  The
    targeted level of certainty under a specific set of economic conditions is
    at least a 50 percent  probability that the quantities  actually recovered
    will  equal  or  exceed  the sum of the  estimated  proved  plus  probable
    reserves.

(2) All of the Project  reserves are  classified  as  "developed".  The proved
    non-producing reserves relate to recovery factor and capacity improvements
    associated with de-bottlenecking capital investments. Although the capital
    is significant  relative to the cost of drilling a well,  classifying  the
    non-producing  reserves as undeveloped is not considered  appropriate  for
    this mining project.

(3) Reserves  have not been  attributed  to Western for the  bitumen  deposits
    present in the eastern  portion of Lease 13.  Western  does not  currently
    hold  a  working  interest  position  in  these  expansion  opportunities.
    Although preliminary resource base assessments have been conducted on some
    of the leases  held  through  the Joint  Venture,  no  reserves  have been
    attributed  to Leases 88, 89, 90, 9, 15, 17, 309,  310, 351, 352, 631, and
    632.

(4) Upgraded  bitumen is equivalent to a synthetic oil product type. This term
    is used rather  than  synthetic  oil since  production  from the  Upgrader
    includes volumes attributable to off-lease feedstock purchases that cannot
    be booked as Project reserves.  Upgrading swells the bitumen such that the
    upgraded bitumen corresponds to 1.03 barrels of undiluted bitumen.

(5) The oil price forecasts reflect total revenues  associated with the output
    from the  Upgrader  less the purchase  costs  associated  with  feedstock.
    Changes to the product mix and associated feedstock composition will occur
    relative to what they have been. In the constant price case, GLJ estimates
    the oil pricing to be the December 31, 2005  Edmonton Par less  $10.00/bbl
    in 2006,  reflecting the average  December 2005 offset to Edmonton Par for
    each  feedstock  product and  marketable  product  stream,  and  Western's
    budgeted

<PAGE>
                                     -12-


    compositions  of  feedstock  and sales.  In the forecast  price case,  GLJ
    estimates  the oil pricing to be Edmonton Par less  $10.00/bbl  based upon
    the average for 2005..

(6) Bitumen  production has been forecast by GLJ to be 145,000 barrels per day
    in 2005 in the proved category  growing to 180,000 barrels per day by 2009
    in the total proved category. In the proved plus probable case, production
    is forecast  to grow from a rate of 150,000  barrels per day in 2005 to an
    average rate of 195,000 barrels per day by 2008. The incremental  probable
    reserves  reflect  the current  mine plan as well as  improved  extraction
    recovery relative to the proved category.

(7) Royalties are paid at the Mine boundary using a deemed bitumen revenue. In
    the constant price case, GLJ has used a bitumen price of $27.74/bbl  based
    upon the December 2005 offset and a posted December 31, 2005 price for LLB
    Crude Oil at  Hardisty.  In the  forecast  price  case,  GLJ has  deducted
    $0.50/bbl  to GLJ's  price for 12 degree  heavy oil at Hardisty to reflect
    historic royalty calculations. The capital expense base for the Project at
    December 31, 2005 is estimated at $1,650 million.

(8) The  constant  price  reflects  December  31,  2005  prices of  $68.27/bbl
    Edmonton Par oil,  $39.20/bbl LLB Crude Oil at Hardisty,  $9.46/MMBTU  gas
    and zero inflation.  In the forecast price assumptions,  the following GLJ
    price forecast was used:

<TABLE>
<CAPTION>
                   EXCHANGE     WTI CRUDE OIL AT    LIGHT, SWEET CRUDE OIL AT     HEAVY CRUDE OIL     ALBERTA PLANT
YEAR    INFLATION    RATE       CUSHING OKLAHOMA    EDMONTON (40 API, 0.3% S)   (12 API) AT HARDISTY    SPOT GAS

          (%)      ($US/$CDN)      ($US/BBL)                ($CDN/BBL)               ($CDN/BBL)         ($/MMBTU)
---------------------------------------------------------------------------------------------------------------------
<C>       <C>            <C>         <C>                      <C>                      <C>                <C>
2006      2.0            0.85        57.00                    66.25                    33.25              10.35
2007      2.0            0.85        55.00                    64.00                    32.75              9.00
2008      2.0            0.85        51.00                    59.25                    32.50              7.75
2009      2.0            0.85        48.00                    55.75                    32.00              7.25
2010      2.0            0.85        46.50                    54.00                    32.00              6.95
2011      2.0            0.85        45.00                    52.25                    33.50              6.65
2012      2.0            0.85        45.00                    52.25                    33.50              6.65
2013      2.0            0.85        46.00                    53.25                    34.00              6.80
2014      2.0            0.85        46.75                    54.25                    34.75              6.95
2015      2.0            0.85        47.75                    55.50                    35.25              7.15
2016      2.0            0.85        48.75                    56.50                    36.00              7.30
2017+     2.0            0.85       +2.0%/yr                 +2.0%/yr                 +2.0%/yr          +2.0%/yr
</TABLE>

    In  consideration  of oil sands  mining  cost  pressures,  rather than the
    projected  inflation  of 2.0  percent  above,  GLJ  assumed a 5.0  percent
    inflation factor for the Muskeg River Mine component of the project during
    the period 2006  through  2008,  4.0 percent in 2009,  3.0 percent in 2010
    followed by 2.0 percent thereafter.

(9) Western's weighted average  historical  realized price for 2005 was $49.91
    per synthetic barrel sold,  $57.02 per synthetic barrel sold excluding the
    effects of hedging activities.

(10) GLJ is an independent  qualified reserves evaluator  appointed pursuant to
     NI 51-101.

                           FUTURE DEVELOPMENT COSTS

The following table sets forth the future development costs associated with the
development of Western's reserves as set forth in the GLJ Report.

<TABLE>
<CAPTION>
                                                      TOTAL PROVED          TOTAL PROVED      TOTAL PROVED PLUS
                                                    ESTIMATED USING       ESTIMATED USING     PROBABLE ESTIMATED
                                                  CONSTANT PRICES AND   FORECAST PRICES AND     USING FORECAST
                                                         COSTS                 COSTS           PRICES AND COSTS
                                                         (MM$)                 (MM$)                (MM$)
                                                  -------------------   -------------------     --------------
<C>                                                       <C>                   <C>                  <C>
2006                                                      65.0                  67.5                 72.8
2007                                                      80.0                  86.0                 96.7
2008                                                      50.0                  55.5                 60.1
2009                                                      20.0                  23.2                 24.4
2010                                                      20.0                  23.8                 25.1
                                                  -------------------   -------------------     --------------
Total for all years undiscounted                         429.1                 513.8                772.3
                                                  -------------------   -------------------     --------------
Total for all years discounted at 10%/year               276.6                 317.6                383.0
                                                  ===================   ===================     ==============
</TABLE>

Western  intends to finance these  development  costs through a combination of
free cash-flow from operations together with existing banking  facilities.  To
the extent that bank facilities increase, costs associated with this borrowing
would  likely be  similar to the rates  that have been  incurred  in the prior
years.  This  anticipated  financing  strategy  would not affect  the  reserve
balances nor the estimated  future net revenue  associated with these reserves
listed above.

<PAGE>
                                     -13-


COSTS INCURRED

The  following  table sets forth  costs  incurred by Western in respect of the
Project for the year ended December 31, 2005:

       PROPERTY ACQUISITION COSTS          EXPLORATION COSTS   DEVELOPMENT COSTS
                 (MM$)                           (MM$)               (MM$)
---------------------------------------    -----------------   -----------------
PROVED PROPERTIES   UNPROVED PROPERTIES
-----------------   -------------------
       Nil                  Nil                 $31.7(1)              $27.7

(1) Includes $27.7 million incurred to fund Western's  commitments pursuant to
    the first phase of the expansion


SIGNIFICANT FACTORS OR UNCERTAINTIES ON RESERVES DATA

Western's  reserves  to date  relate  only to the west side of Lease  13.  All
infrastructure  components are in place to extract the independently evaluated
reserves.  Since significant  capital costs have already been incurred for the
Project, the exposure to rising capital costs is limited to expansion projects
required to extract the undeveloped  resources.  Certain  maintenance  capital
costs will be  expended  over the life of the  reserves  to repair and replace
certain components,  particularly at the Mine and extraction  facilities given
the abrasive  nature of the ore being  processed.  However,  risk remains with
respect to ore quality,  existence of  deleterious  materials such as water or
clay  fines and ore body  geometry  such as strip  ratio.  Important  economic
factors in the  determination  of the future net revenues  associated with the
reserves are  forecasted  prices of crude oil and natural gas.  Should  future
prices  vary  significantly  from  prices  used  by GLJ in  their  independent
assessment, the corresponding future net revenues associated with the reserves
may be materially different. See section titled "Risks and Uncertainties".

LAND TENURE

Oil produced from oil sands is produced  under Crown Oil Sands Leases  granted
by the  Province of Alberta.  Such Crown Oil Sands Leases have an initial term
of 15 years,  and may be  continued  thereafter  under  the OIL  SANDS  TENURE
REGULATION  (Alberta)  to the extent that the lessee has attained the required
minimum  level of  evaluation of the oil sands in the leases or the leases are
producing.  Lease  13 has  been  continued  under  such  regulation.  The real
property  related  to  the  pipelines,   the  Upgrader  and  the  cogeneration
facilities  fall  into two  basic  categories  of  ownership:  (i) a number of
locations,  including  some  pumping/compressor  stations,  are  owned  in fee
simple;  and (ii) the majority of locations are covered by leases,  easements,
rights-of-way, permits or licenses from landowners or governmental authorities
permitting the land to be used in such a manner.

ROYALTIES

An initial royalty of 1% of the gross revenue on the bitumen  produced is paid
until the Owners have recovered 100% of the capital costs  associated with the
Mine and Extraction Plant, including a return on capital. Such return is based
on the monthly Canadian federal long-term bond rate.  Subsequent thereto,  the
royalty will be the greater of 1% of the gross revenue on the bitumen produced
and 25% of net bitumen revenue.  Gross revenue is calculated based on the fair
market value of the bitumen prior to  upgrading.  Net revenue is determined by
deducting from gross revenue the aggregate of all allowable  operating  costs,
interest expense and amortization of capital costs and any loss carryforwards.
Based on forecasted production levels and proposed capital expansions, Western
does not foresee the higher  royalty  rates to take effect in the  immediately
foreseeable future.

<PAGE>
                                     -14-


ENVIRONMENTAL CONSIDERATIONS

The key  environmental  issues and  stakeholder  concerns to be managed by the
Owners in the  development  of the Mine are similar to those  currently  being
managed by existing oil sands  operators  and  communities  and  encompass the
health  of  local  and  regional  residents  and  Project  employees,  surface
disturbance on the terrestrial ecosystem,  effects on traditional land use and
historical resources, local and regional air quality, water quality, health of
the  aquatic  ecosystem  in the  Athabasca  and Muskeg  rivers and  cumulative
effects on  wildlife  populations  and  aquatic  resources.  The  Owners  have
committed to both  site-specific  and regional  monitoring  programs that will
track the  effects of the  Project  and the  cumulative  effects  of  regional
development on environmental components and ecosystems.

The Owners  will  operate the Project to achieve  compliance  with  applicable
statutes,   regulations,   codes,   permit   conditions  and,  to  the  extent
practicable, government guidelines. Where the applicable laws are not clear or
do not address all environmental  concerns,  management will apply appropriate
internal  standards and  guidelines to address such  concerns.  In addition to
complying with  legislation and regulations and exercising due diligence,  the
Owners  will  strive  to  continuously   improve  the  overall   environmental
performance  of the operation and products  while  aspiring for short term and
long term  commercial  success for the Project.  Air quality is of  particular
importance  to the  Project,  and has taken on greater  significance  with the
federal  government's  ratification  of the  Kyoto  agreement.  As  part  of a
Voluntary  Climate  Change Action Plan,  the Joint  Venture has  substantially
reduced emission  targets for the Project.  As it stands today, the Project is
operating  with emissions  that are  approximately  27 per cent lower than the
original  case that was approved by the Alberta  Energy and  Utilities  Board.
This has been achieved through the addition of cogeneration  units, the use of
waste  hydrogen  from  a  neighbouring  facility  and  a  variety  of  process
improvements.  Western's goal is to further reduce emissions by another 40 per
cent by 2010 through a combination of energy efficiency  projects.  To achieve
this goal, the Owners are pursuing a multi-faceted plan, which includes energy
efficiency  projects,  investigation  of cleaner  technology,  the purchase of
domestic and international offsets and tree-planting offset programs.

ABANDONMENT AND RECLAMATION COSTS

Western has  abandonment  and  reclamation  liabilities  relating to the Mine,
Upgrader and related facilities.  Western estimates the abandonment liability,
net of salvage, for these assets with consideration given to the expected cost
to abandon and reclaim the lands and facilities.  These estimates are based on
prevailing industry conditions,  regulatory  requirements and past experience.
The value is determined by Western first estimating the anticipated timing and
amount of net cash outflows  using third party costs for future  dismantlement
and site  restoration.  These future  payments are then present valued using a
credit adjusted risk free rate appropriate for Western.

The  liability is estimated in the period in which the  liability is incurred.
These  estimates are prepared  annually and adjustments are made quarterly for
material  changes in the amount of the liability or the timing of abandonment.
Where material  differences are identified,  adjustments to the liabilities or
accretion expense are made on a prospective basis.

Western's share of the present value of abandonment and reclamation costs that
require  recognition in its financial  statements at December 31, 2005 is $9.1
million ($199.0 million  undiscounted).  These liabilities relate to Western's
20% working  interest in the  Project's  future  dismantlement  costs and site
restoration costs for the Mine, Upgrader and related  facilities.  GLJ has not
included any abandonment and reclamation costs in the GLJ Report. Western does
not  anticipate  any  material   expenditures   relating  to  abandonment  and
reclamation  during the next three years as the current mine plan contemplates
development over 30 years.

<PAGE>
                                     -15-


THIRD PARTY FACILITIES

The Owners have entered into various  contracts  with certain third parties to
construct,  own and  operate  certain  additional  facilities  required by the
Project.  Terasen Pipelines (Corridor) Inc.  ("Terasen")  constructed the dual
pipeline  system  that  connects  the Mine to the  Scotford  Upgrader  and the
Scotford  Upgrader to certain  third  party  pipelines.  Terasen was  acquired
during the course of 2005 by Kinder  Morgan,  Inc.  ("Kinder  Morgan")  Kinder
Morgan now operates this system directly. The Owners are severally responsible
for the costs of transportation on the pipeline systems, which is on a take or
pay basis.

ATCO built,  owns and operates the  cogeneration  facility located on Lease 13
which provides power and steam for the Mine and  Extraction  Plant.  ATCO also
owns and operates the cogeneration  facility constructed to provide electrical
power to the Upgrader.  The Owners are  obligated to purchase  power from ATCO
under  long-term  contracts.  ATCO has the  ability to sell any  excess  power
generated by the cogeneration facilities to the commercial power market.

MARKETING AND SALES

Shell Canada Products Limited takes delivery of vacuum gas oil at the Scotford
Refinery,   representing   approximately   one-third  of  the  total  Upgrader
production,   pursuant  to  a  long-term  sales  arrangement.   Western  sells
approximately  12,000  barrels  per  day of  vacuum  gas oil to  Shell  Canada
Products  Limited under this  arrangement  representing  its 20% share of such
total sales.  The remaining  production  from the Upgrader and any third party
feedstocks currently form the basis of two streams of synthetic crude oil (one
heavy and one light) totalling  approximately  150,000 barrels per day (30,000
barrels per day to Western).  This production is taken in kind and marketed by
each Owner to numerous  refineries  throughout  North  America.  The  Scotford
Upgrader is located at the hub of the western Canadian  refining industry near
Edmonton,  Alberta,  providing  the Owners with access to a number of pipeline
systems,  to which the Corridor  pipeline system is connected.  Provisions for
pipeline  deliveries  have  been  established  through  most  major  crude oil
trunkline systems. As a result,  Western is able to sell all of its production
volumes into the traditional North American markets.

Market acceptance of Western's two streams of synthetic crude oil continues to
be high,  with  these  products  consistently  meeting or  exceeding  customer
expectations.  While  Western's  upgrading  provides  synthetic crude oil with
superior qualities for processing,  Western's products also lend themselves to
blending  and  customizing  and  this  flexibility  may  lead  to  significant
improvements in refinery  efficiencies  for Western's  customers.  A dedicated
pipeline to the  Edmonton  terminals  has ensured the  integrity  of Western's
product and in order to maintain this quality,  Western's products are shipped
in segregated streams.

INSURANCE

The Owners obtained  insurance to protect against certain risks of loss during
the construction of the Mine, Extraction Plant and the Upgrader. The insurance
is typical for a project of the nature of the Project.

In addition,  Western obtained,  for its own account, a $200 million insurance
policy which,  throughout  the period March 2000 through  April 2004,  covered
certain  costs,  expenses  and  losses  of  revenue  including:  (i) costs and
expenses or loss of revenues  arising from a delay in achieving the guaranteed
production levels as set out in the feasibility study; (ii) costs and expenses
incurred  in  connection  with the  modification,  repair  or  replacement  of
equipment or material,  which are directly related to achieving the guaranteed
production  levels;  (iii)  escalation  in Project  costs  beyond the budgeted
Project  costs,  which  are

<PAGE>
                                     -16-


directly related to achieving the guaranteed  production levels; and (iv) debt
service costs related to  obligations  incurred to finance any of (i), (ii) or
(iii).

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

In addition,  insurers  involved in the dispute  with  Western  have  withheld
insurance  proceeds payable to Western for damages related to the January 2003
fire and related freezing damage.  With the exception of the amounts withheld,
these  claims have now been  resolved.  To date,  Western has  received  $16.1
million  from  insurers  in respect of claims  relating to the fire and freeze
damage. See "General Development of the Business - Operating Activities".

During 2005, the Joint Venture  announced it had reached a settlement with the
insurers on its loss of profits claim.  The final  settlement  amount totalled
$220 million ($44 million net to Western),  of which  Western  received  $19.4
million.  Amounts withheld are by those common insurers on Western's  start-up
and delay  insurance  policy  which,  as  discussed  above,  is  currently  in
arbitration  proceedings.   The  principal  amount  of  Western's  outstanding
insurance claims is $244 million.  There can be no assurance that Western will
receive any or all of these  outstanding  amounts.  The  potential  benefit of
collection  of insurance  proceeds is not factored  into  Western's  financing
strategy.  Should these proceeds, or part thereof, be received,  Western would
conduct appropriate analysis to determine where to best deploy the funds.

Western's  current  insurance  is designed to protect its  ownership  interest
against  losses  or  damage to the Mine,  Extraction  Plant and  Upgrader,  to
preserve its operating income and to protect against its risk of loss to third
parties. Western also renewed its property and business interruption insurance
but  increased  the limit to reflect the  significant  increase  in  commodity
prices.  Western also maintains other  insurance  coverages  addressing  other
parts of our operations to sufficiently  guard against  unforeseen  events and
risks.

AOSP EXPANSIONS

Under the  terms of the  Joint  Venture  Agreement,  should  an Owner  wish to
undertake an expansion  of a key  component of the Project,  the mining of the
remaining area of Lease 13 or the  construction of a new mine or upgrader,  it
must first  advise the other  Owners and  provide a period of time for them to
advise as to whether or not they will participate in the feasibility study for
the  proposed  expansion.  If an Owner does not  originally  participate  in a
feasibility study it may, upon completion of the feasibility  study,  purchase
the right to participate in the feasibility  study and the expansion by paying
twice the cost of its proportionate share of the feasibility study.

If an expansion is to take place,  an Owner must  satisfy  certain  conditions
relating  to  financial   capability  to  undertake  the  proposed  expansion.
Expansion  on the  eastern  portion of Lease 13 or in respect of the  Upgrader
prior to five years after  Project  Start-up may only be  undertaken  with the
written  approval of Shell  (provided  Shell or an affiliate  has an ownership
interest in the Upgrader and is an Owner and operator of the Scotford Refinery
at the time in respect of expansion to the Upgrader).  In order to

<PAGE>
                                     -17-


participate  in an  expansion  in respect  of the east area of Lease 13,  each
Owner would be  required  to pay to Shell an amount  based on the share of the
recoverable  bitumen reserves to be acquired by such Owner.  Owners' interests
will be  adjusted  to reflect  expansions.  Expansions  may only take place by
Owners with total ownership  interest of a minimum of 40% in the key component
of the  Project  being  expanded.  If an  Owner  other  than  Shell  does  not
participate  in an  expansion  on the east  portion  of Lease 13 or in Shell's
other Athabasca Leases it shall have no further expansion rights.

DISPOSITIONS

Owners may not assign or transfer  ownership  interests  in the Project  until
three years after Project Start-up unless such  dispositions  are: (i) a grant
of security  and the  secured  party  acknowledges  it is subject to the Joint
Venture  Agreement and is  subordinate to all liens granted  thereunder;  (ii)
dispositions  to  affiliates;  (iii) to a  person  meeting  certain  specified
financial  requirements;  and (iv) certain limited public or private placement
offerings of  securities.  Partial  assignments  are only  permissible  if all
resulting ownership interests are 10% or greater. The Owners have also granted
each other a right of first refusal in respect of proposed dispositions.

PROPOSED EXPANSIONS AND FEASIBILITY STUDY AGREEMENT

During 2005, the Project adopted an expansion strategy of developing identical
incremental  trains of production.  It is anticipated that three  back-to-back
100,000  barrel per day trains will be added to the Mine with a  corresponding
increase in capacity  at the  Upgrader.  This  "building-block"  strategy  has
several  competitive  advantages  including  economies of scale in engineering
design,  procurement  of components  and materials and labour  retention.  The
timing of the current expansion plans contemplates  100,000 barrels per day of
incremental  production being added every two years starting in 2009, 2011 and
2013.  With the leases known to have resources at the present time, this would
imply an  eight  to ten year  construction  period.  With  significantly  more
people,  time and effort  dedicated to the planning  process of the  expansion
compared  to  the  first   construction   initiative,   it  is  believed  that
cost-overruns  will be largely  mitigated.  Further  expansion  efforts may be
conducted as additional leases are included in the AMI. As currently designed,
expansion plans would result in the AOSP's production  increasing from 180,000
to 200,000 barrels per day following  production  optimization  initiatives to
500,000 to 600,000  barrels  per day by 2015.  Initial  capital  costs for the
first  expansion  phase have been  estimated at up to $200 per annual  flowing
barrel.  Based on the continuous  construction  strategy,  the first expansion
phase will  include  items which will be utilized  by  subsequent  phases and,
therefore,  the  capital  intensity  of  subsequent  phases is  expected to be
reduced.  Capital will be deployed  once for permanent  personnel  facilities,
permanent construction equipment, utilities infrastructure,  etc rather than a
strategy of  multiple  stand-alone  expansion  efforts.  See  "Forward-Looking
Information" and "Risks and Uncertainties".

Beyond the first phase of the expansion, the Project's longer term optimization
plan includes:

         o    development of additional  resources located on Leases 88 and 89
              with a capacity  of  approximately  100,000  barrels  per day of
              bitumen  production.  Regulatory  approval  would be received as
              part of the omnibus filing;

         o    development  of  additional  resources  on  Lease  9  which  was
              acquired by Shell in 2004.  It is  estimated  that Lease 9 could
              result in an  additional  200  million  barrels  net to Western.
              Shell also acquired Lease 17 in 2004 but this parcel has not yet
              been evaluated;

         o    evaluation of additional  mineable leases  acquired  recently by
              Shell in the Athabasca region. An extensive  drilling program on
              these  leases,  together  with  Lease  17,  is  planned  for the
              2006/2007 drilling season. The results will be reviewed over the
              balance of 2006 and a mine plan  developed  accordingly,  should
              economic resources exist; and

<PAGE>
                                     -18-


         o    analyses of  processes  and/or  equipment  that will result in a
              reduction of unit operating costs in the extraction  process and
              the dependency on natural gas.

The timing  and  details of any  expansion  will be subject to the  outcome of
future  evaluations of economics,  market needs,  regulatory  requirements and
sustainable development considerations.

The  pre-feasibility   phase  has  been  completed  and  the  Owners  are  now
progressing through the feasibility study which is expected to be completed in
the third  quarter of 2006.  The scope of the  feasibility  study is much more
involved and includes such analysis as the location and size of the mine,  the
nature,  location and extent of the mine facilities,  the upgrader  facilities
and  the  third  party  facilities,  a plan  for  the  construction  of  these
additional   facilities  in  addition  to  numerous  other   activities.   The
feasibility  study will also more narrowly define the capital costs associated
with the expansion initiatives to an estimate within +/- 10%. The interests of
the parties to this agreement are the same as in the Joint Venture  Agreement;
however,  the  terms  of  the  Joint  Venture  Agreement  do not  govern  this
undertaking. This feasibility study agreement does not add to nor detract from
any of  Western's  rights  under  the Joint  Venture  Agreement.  The  overall
management has been delegated to the Executive Committee of the Joint Venture,
which  delegates  certain  matters to the project  administrator.  Western may
withdraw from the feasibility  study agreement at any time;  however,  Western
may be  reinstated  by paying  twice the costs it would  have  otherwise  been
required to pay to preserve its rights to participate  in a feasibility  study
and expansion  pursuant to the Joint Venture Agreement.  See  "Forward-Looking
Information" and "Risks and Uncertainties".

REGULATORY APPROVALS

On April 23, 2004, Western announced that the AOSP received approval from both
the  provincial  and  federal  government  cabinet  for the first phase of the
Jackpine  Mine in the Athabasca  oil sands region of northern  Alberta.  Since
these  approvals have been  received,  the Owners have advanced the continuous
construction  scenario  and  filed a  regulatory  permit in April  2005  which
included  a  revision  to  the  existing  Mine  permit  to   accommodate   the
de-bottlenecking  volumes as well as the first  phase of the  expansion.  With
permits in place and those  recently  filed,  the goal is to  produce  300,000
barrels  per day by the end of 2009.  The first  expansion  phase  intends  to
extract  resources from the east side of Lease 13 in addition to those located
on Lease 90 and includes a mining and extraction  facility.  It is anticipated
that Western will seek board  approval  for the first  expansion  phase in the
latter half of 2006.  Approval will be preceded by the substantial  completion
of design and appropriate  multi-company,  multi-disciplinary reviews aimed at
improving the certainty of project  execution and reducing the  variability on
capital costs to an acceptable level Certain long lead items have already been
ordered with a corresponding capital outlay to ensure these critical items are
delivered on site at the appropriate time.  Approval of the first phase of the
expansion this year,  combined with Western compliance with certain provisions
under the JVA, will allow the  Corporation  to recognize its pro rata share of
the reserves associated with this expansion.

In  addition,  an  omnibus  regulatory  permit is being  prepared  that,  once
submitted and approved,  would enable the Project to produce  500,000  barrels
per day. It is envisioned that this permit will be submitted  during 2006 with
the expectation that approval will be received in mid-2008.

The timing and receipt of regulatory approvals is subject to certain risks and
uncertainties.    See    "Forward-Looking    Information"   and   "Risks   and
Uncertainties".

RESOURCES

Western  is a party  to the  AOSP  Participation  and AMI  Agreement.  The AMI
stipulates  that the current Joint Venture  parties have rights to participate
in any  additional  leases that are  acquired by any one of the parties in the
Athabasca region.  Western is entitled to participate in all future expansions
on Lease 13 and in the

<PAGE>
                                     -19-


other oil sands  opportunities  with  Shell and  Chevron in respect of Shell's
Other Athabasca leases, and within a defined area of mutual interest.

The following table outlines the independently  evaluated  resources available
for future expansion  opportunities on the remainder of Lease 13 together with
Leases 88, 89, 90, 9 and 17 as verified by Norwest Corporation, an independent
mining and geological consultant. Except in the case of Lease 17, the resource
estimates  set  forth in the  Norwest  Report  are based on  certain  limiting
criteria  including a minimum bitumen  content of 7% to total weight,  minimum
mining  thickness  of 3 metres and  maximum  total  volume to bitumen in place
("TV:BIP") of 12:1.

The  volumetric  amounts  are  expressed  on  a  Discovered  Resources  basis.
Definitions and guidelines which govern the evaluation of reserve and resource
quantities  are  contained in the Canadian  Oil and Gas  Evaluation  Handbook.
There is  considerable  difference  between the evaluation of reserves  versus
resources. Discovered Resources are comprised of recoverable and unrecoverable
resources.   Recoverable  resources  are  those  quantities  of  oil  and  gas
anticipated  to be  economically  recoverable,  which  may be  categorized  as
reserves once other conditions such as obtaining regulatory approvals, capital
commitment  and ownership of the leases have been  satisfied.  Western has not
yet satisfied the requirements on these leases.  Only the recoverable  portion
of  the  resources  listed  below  will  ultimately  be  booked  as  reserves.
Evaluations will be conducted in the future to determine these amounts.


                                                         TOTAL PROJECT
                                                            (MMBBLS)
                                               -------------------------------
FUTURE OPPORTUNITIES (DISCOVERED RESOURCES)         High       Best       Low
                                                 Estimate   Estimate   Estimate
                                                    (P10)      (P50)     (P90)
------------------------------------------------------------------------------
  Remainder of Lease 13                             5,251      5,028     3,194
                                                    2,382
  Leases 88 and 89                                             2,038       856
  Lease 90                                            269        253       162
  Lease 9 and 17(2)                                 2,110        899       431
------------------------------------------------------------------------------
Total                                              10,012      8,218     4,643
------------------------------------------------------------------------------
(1) Table above  represents  total  Project  interest in the leases  which are
    currently  held  by  Shell.  Under  the  AMI,  Western  has the  right  to
    participate in these leases to a 20 percent level.

(2) Norwest  attributed  only  inferred  resources to Lease 17 (high  estimate
    only)  reflecting a  probability  of only 10% that the resource  equals or
    exceeds the estimated amount given the limited amount of data available on
    this  lease.  Major  assumptions  used in the  classification  of inferred
    resources  for Lease 17 were average  in-place  bitumen  content of 10% to
    total weight and ore thickness of  approximately  15 metres over less than
    half the lease  area.  Due to the level of  uncertainty  on this  lease it
    should not be assumed that all or any part of an inferred resource will be
    upgraded as a result of continued exploration.

LAND POSITION

During 2005,  Shell  purchased  Leases 15, 351,  352, 631, 632, 309 and 310 at
public land auctions of the Alberta  Government which have not been evaluated.
Pursuant to the AMI,  Western has the right to  participate to its 20 per cent
interest in the  development  of these leases.  Extensive  core-hole  drilling
programs  are  planned  over the  next two  years  to  evaluate  the  resource
potential of these additional leases.

Western  also has the right to  participate  in the five heavy oil sand leases
that Chevron  recently  acquired.  These  in-situ  leases cover  approximately
30,300  hectares and possess an estimated 7.5 billion  barrels of oil in place
(according  to Chevron's  internal  estimates).  They have the  potential  for
bitumen extraction through in-situ recovery methods.  Pursuant to the terms of
the AMI,  Western has the right to participate  to a 20 percent  interest upon
Chevron  serving  notice to the other  Joint  Venture  parties  of its  recent
purchase followed by certain payments to Chevron.

<PAGE>
                                     -20-


Our  undeveloped  land position  also  includes an in-situ  lease  acquired by
Western during 2005 covering 3,329 gross hectares. Both Shell and Chevron have
elected to participate to their 20 percent interest pursuant to the AMI.

Western has significantly increased its internal  organizational  capabilities
in 2005 with the addition of senior  technical staff focused on developing its
in-situ  strategy.  This  strategy  includes  the  ability  to  make  critical
assessments  in both the Shell and  Chevron  property  rights in  addition  to
pursuing  the  purchase  of  undeveloped   properties  directly  and  offering
reciprocal option rights to Shell and Chevron. The exploration and development
of this  significant  land and resource base if  warranted,  both mineable and
in-situ,  could involve a substantial and material  capital  commitment on the
part of Western to develop the underlying resource.

The following table  summarizes the gross and net area associated with each of
these Leases together with existing leases.


                                                                     NET AREA TO
                                    GROSS AREA    WESTERN INTEREST     WESTERN
                                      (ACRES)            (%)            (ACRES)
                                   -------------- ----------------- ------------
AOSP/EXPANSIONS
     Lease 13                         49,872             20             9,974
     Lease 88                         28,108             20             5,622
     Lease 89                         14,765             20             2,953
     Lease 90                          2,881             20               576
     Lease 9                          14,896             20             2,979
     Lease 17                         21,508             20             4,302
---------------------------------- -------------- ----------------- ------------
                                     132,030              -            26,406
---------------------------------- -------------- ----------------- ------------
ADDITIONAL MINEABLE LEASES
     Lease 15                          3,796             20               759
     Lease 351                        22,773             20             4,555
     Lease 352                        16,447             20             3,289
     Lease 631/632                     6,642             20             1,328
     Lease 309                        11,387             20             2,277
     Lease 310                         7,591             20             1,518
---------------------------------- -------------- ----------------- ------------
                                      68,636              -             13,726
---------------------------------- -------------- ----------------- ------------
IN-SITU LEASES
     Chevron Leases                   75,000             20             15,000
     Lease 353 (Western)               8,225             60             4,935
---------------------------------- -------------- ----------------- ------------
                                      83,225              -            19,935
---------------------------------- -------------- ----------------- ------------
TOTAL                                283,891              -            60,067
                                   -------------- ----------------- ------------


FORWARD CONTRACTS

Western has entered  into various  commodity  pricing  agreements  designed to
mitigate the exposure to the  volatility  of crude oil prices in U.S.  dollars
with the objective of solidifying the Corporation's balance sheet in the years
where significant  capital  expenditures are planned.  Western no longer holds
fixed priced swap  contracts but utilizes a combination of a series of put and
call options in order to provide a floor West Texas Intermediate ("WTI") price
yet maintain upside potential on a portion of the  Corporation's  base volumes
should commodity prices continue to rise. As at January 1, 2006, the following
positions are in place:

<PAGE>
                                     -21-


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

Put options purchased (bbls/d)         20,000       20,000        20,000
Avg. put strike price (US$/bbl)         52.50        54.25         50.50

Call options sold (bbls/d)             10,000       15,000        15,000
Avg. call strike price (US$/bbl)        92.50        94.25         90.50

GLJ has not included any effects of ing activities in the GLJ Report.

TAX HORIZON

Western is currently not required to pay cash income taxes.  Western estimates
that cash  income  taxes  will  become  payable  within  five to seven  years,
depending  on commodity  prices,  foreign  exchange  rates,  operating  costs,
interest rates, future annual taxable income levels, expansions of the Project
and other business activities. Changes in these factors from estimates used by
Western  could result in Western  paying  income  taxes  earlier or later than
expected.

                                DIVIDEND POLICY

No  dividends  have been paid on any shares of  Western  since the date of its
incorporation.  The  Corporation  currently  intends to retain its earnings to
finance the growth and  development  of its business  and  therefore it is not
expected that  dividends will be paid on the Common Shares in the immediate or
foreseeable  future.  In  addition,  the note  indenture  governing  the Notes
contains  restrictions  on  the  Corporation's  ability  to pay  dividends  or
distributions of any kind. See "Credit Ratings".

                         DESCRIPTION OF SHARE CAPITAL

The authorized  share capital of the Corporation  includes an unlimited number
of Common Shares, an unlimited number of Non-voting Convertible Class B Equity
Shares ("Non-voting  Convertible Equity Shares"), an unlimited number of Class
C  Preferred  Shares  ("Class C Shares")  and an  unlimited  number of Class D
Preferred Shares, issuable in series ("Class D Shares").

The following is a brief  description of the  attributes of the  Corporation's
Common Shares,  Non-voting Convertible Equity Shares, Class C Shares and Class
D Shares.

COMMON SHARES

The holders of Common Shares are entitled, subject to specified preferences in
favour of holders of Class C Shares and Class D Shares,  to  dividends  if, as
and when  declared by the  directors  and to one vote per share at meetings of
the  holders of Common  Shares and,  upon  liquidation,  subject to  specified
preferences  in favour of  holders  of Class C Shares  and Class D Shares,  to
share equally share for share with the Non-voting Convertible Equity Shares in
the remaining assets of the Corporation.

<PAGE>
                                     -22-


NON-VOTING CONVERTIBLE EQUITY SHARES

The holders of Non-voting  Convertible Equity Shares are entitled to dividends
in parity with the Common  Shares if, as and when  declared  by the  directors
and, upon liquidation,  subject to specified  preferences in favour of holders
of Class C Shares and Class D Shares,  to share  equally  share for share with
the  Common  Shares in the  remaining  assets of the  Corporation.  Holders of
Non-voting Convertible Shares are not entitled to receive notice of, attend or
vote at any meetings of shareholders  unless  otherwise  entitled  pursuant to
applicable laws.

Each Non-voting  Convertible  Equity Share shall entitle the holder to acquire
(subject to adjustment),  at no additional cost, one Common Share at 4:30 p.m.
(Calgary time) (the "Acquisition Expiry Time") on the earlier of: (i) five (5)
business days  following  the date upon which a receipt for a prospectus  (the
"Qualifying   Prospectus")  to  be  filed  by  Western  with  respect  to  the
distribution   of  the  Common  Shares  upon   conversion  of  the  Non-voting
Convertible  Equity  Shares  has been  issued  by the  last of the  securities
commissions or similar  regulatory  authorities in the Province of Alberta and
such other provinces of Canada in which the Corporation  files such Qualifying
Prospectus  (based upon the residences of Canadian  subscribers);  and (ii) 12
months from the date of issuance of the Non-voting  Convertible Equity Shares.
Non-voting  Convertible  Equity Shares  outstanding at the Acquisition  Expiry
Time shall be deemed to be converted by the holder, without any further action
on the part of the holder,  at the  Acquisition  Expiry  Time.  As at the date
hereof, there are no outstanding securities of this class.

CLASS C SHARES

The  Corporation  is  authorized  to make one issuance of Class C Shares.  The
holders of Class C Shares shall not be entitled to receive  notice of,  attend
or  vote  at any  meetings  of the  shareholders  of  the  Corporation  unless
otherwise  entitled  pursuant  to  applicable  laws but shall be  entitled  to
receive in respect of each  calendar  year,  if, as and when  declared  by the
directors,  a  non-cumulative  preferential  dividend  in the  amount (if any)
declared by the directors.  No dividends shall be declared or paid in any year
on the Common Shares,  Non-voting Convertible Equity Shares, Class D Shares or
any other shares of the Corporation  ranking junior to the Class C Shares from
time to time with respect to the payment of  dividends,  unless all  dividends
which shall have been  declared and which remain  unpaid on the Class C Shares
then issued and  outstanding  shall have been paid or provided for at the date
of such declaration or payment.  Upon  liquidation,  holders of Class C Shares
shall be entitled to payment of an amount (subject to adjustment) equal to the
amount or value of the  consideration  paid for such shares  (the  "Redemption
Amount") in priority to the Common Shares,  the Non-voting  Convertible Equity
Shares,  the Class D Shares and any other shares ranking junior to the Class C
Shares from time to time. The Class C Shares are redeemable by the Corporation
or the holders of Class C for the  Redemption  Amount.  As at the date hereof,
there are no outstanding securities of this class.

CLASS D SHARES

The Class D Shares are entitled to receive  notice of,  attend and vote at any
meetings of  shareholders  and are  convertible  into Common Shares,  prior to
redemption,  on a one-for-one  basis. The Class D Shares are redeemable by the
Corporation  at a price equal to their issue price plus a cumulative  dividend
of 12% per annum  compounded  semi-annually  until January 1, 2007, from which
date the  dividend  increases by 3% per quarter to a maximum of 24% per annum.
As at the date hereof, there are no outstanding Class D Shares.

<PAGE>
                                     -23-


                             MARKET FOR SECURITIES

The Common  Shares of the  Corporation  are listed for  trading on the Toronto
Stock Exchange  ("TSX") under the symbol "WTO".  The following  table sets for
the high,  low and  closing  trading  prices and the  volume of Common  Shares
traded on the TSX for each monthly of the most  recently  completed  financial
year. The following data has been adjusted to reflect the 3 for 1 Share Split.

     MONTH           HIGH            LOW          CLOSING         VOLUME
---------------- ------------- -------------- --------------- -------------
January              15.19          13.17          14.52         9,053,994
February             21.33          14.51          19.72        14,785,455
March                21.43          17.45          18.67        17,556,693
April                20.00          17.50          18.59        11,899,557
May                  24.74          18.50          19.33        11,439,684
June                 24.74          18.68          23.79        12,978,115
July                 28.99          24.41          28.50         9,443,560
August               33.19          27.00          29.35        19,784,844
September            32.40          27.35          27.55        13,299,253
October              28.30          23.60          25.40        13,604,174
November             29.40          25.20          27.02        16,646,233
December             29.00          25.18          27.81         9,551,977


                                CREDIT RATINGS

On April 23, 2002,  Western completed a private  placement  offering of US$450
million  senior  secured  Notes.  The Notes bear interest at 8.375% per annum,
payable on May 1 and  November 1 of each year,  beginning  on November 1, 2002
and mature on May 1, 2012. Western's Notes are currently rated by two separate
agencies, Standard and Poors ("S&P") and Moody's Investor Service. ("Moody's")
Please  refer to the table below for the  respective  ratings  assigned to the
Notes.

-----------------------------------------------------------------------------
           TYPE OF SECURITY                  S&P              MOODY'S
-----------------------------------------------------------------------------
US$450 Million Senior Secured Notes      BB+/Positive           Ba2
-----------------------------------------------------------------------------

S&P  Rating   Definition  -  Obligations  rated  BB  are  regarded  as  having
significant  speculative  characteristics.  An  obligation  rated  BB is  less
vulnerable to non-payment than other  speculative  issues.  However,  it faces
major ongoing  uncertainties or exposure to adverse  business,  financial,  or
economic  conditions which could lead to the obligor's  inadequate capacity to
meet its financial  commitment on the obligation.  BB+ is one level below that
which is considered  "Investment  Grade" under the S&P rating system.  The (+)
sign is added to show relative  standing  within the major rating  categories.
The ratings  outlook for Western by S&P is "Positive"  which  indicates that a
rating may be raised.

Moody's - Moody's  long-term  obligation  ratings are opinions of the relative
credit risk of fixed-income  obligations with an original maturity of one year
or more. They address the possibility that a financial  obligation will not be
honoured as promised.  Such ratings reflect both the likelihood of default and
any financial loss suffered in the event of default.  Obligations rated Ba are
judged to have  speculative  elements  and are subject to  substantial  credit
risk.  Moody's appends numerical  modifiers 1, 2, and 3 to

<PAGE>
                                     -24-


each  generic  rating  classification  from Aa  through  Caa.  The  modifier 1
indicates  that the  obligation  ranks in the higher end of its generic rating
category;  the  modifier 2 indicates a mid-range  ranking;  and the modifier 3
indicates  a  ranking  in the  lower  end of  that  generic  rating  category.
Investment grade under the Moody's rating system would be Baa3 and higher.

A security rating is not a recommendation  to buy, sell or hold securities and
may  be  subject  to  revision  or  withdrawal  at  any  time  by  the  rating
organization.

                            DIRECTORS AND OFFICERS

The following  table lists the names of the directors and officers of Western,
their  municipalities  of  residence,  positions  and offices with Western and
principal occupations during the preceding five years:

<TABLE>
<CAPTION>
    NAME AND MUNICIPALITY OF     PRESENT POSITION    PRINCIPAL OCCUPATION DURING THE LAST        DIRECTOR SINCE
           RESIDENCE                AND OFFICE                    FIVE YEARS
-----------------------------    ----------------  ------------------------------------------   ----------------
<S>                              <C>               <C>                                          <C>
DIRECTORS

David J. Boone(4)(5)             Director          President  of  Escavar   Energy  Inc.,  a        May 2005
Calgary, Alberta; Canada                           private  oil and gas  corporation,  since
                                                   2003.    Prior   to    2003,    Executive
                                                   Vice-President of EnCana  Corporation and
                                                   President  of  the  EnCana  Corporation's
                                                   Offshore and International Operations and
                                                   Executive    Vice-President   and   Chief
                                                   Operating Officer of PanCanadian  Energy.
                                                   Prior to 2001,  various  executive  roles
                                                   with Imperial Oil Limited,  an integrated
                                                   oil and gas company.


Tullio Cedraschi(2)(4)           Director          President and Chief  Executive Officer of      October 2000
Montreal, Quebec: Canada                           CN Investment    Division,    the  entity
                                                   responsible for  investing  the assets of
                                                   the  Canadian  National Railways  Pension
                                                   Trust Funds.

Geoffrey A. Cumming(3)(5)((7))   Lead Director     Managing    Director  of   Zeus   Capital      October 1999
Auckland, New Zealand                              Limited, a private New Zealand investment
                                                   corporation,    since     March     2003.
                                                   Vice-Chairman of Gardiner  Group  Capital
                                                   Limited,  a  private Canadian  investment
                                                   corporation,  to June 2003  and  prior to
                                                   July  2002,  Chief  Executive  Officer of
                                                   Gardiner Group Capital Limited.

James C. Houck                   President, Chief  President and Chief Executive  Officer of        May 2005
Calgary, Alberta; Canada         Executive         the   Corporation   since   April   2005.
                                 Officer and       Previously   principal   of   FrontStreet
                                 Director          Partners,   a   private   United   States
                                                   investment  firm,  since 2003.  President
                                                   of  ChevronTexaco's  Worldwide  Power and
                                                   Gasification  Inc.  from  1998  to  2003.
                                                   President    of    Texaco     Development
                                                   Corporation from 1996 to 2001.
</TABLE>

<PAGE>
                                            -25-

<TABLE>
<CAPTION>
    NAME AND MUNICIPALITY OF     PRESENT POSITION    PRINCIPAL OCCUPATION DURING THE LAST        DIRECTOR SINCE
           RESIDENCE                AND OFFICE                    FIVE YEARS
-----------------------------    ----------------  ------------------------------------------   ----------------
<S>                              <C>               <C>                                          <C>
Oyvind Hushovd(2)(3)             Director          Chairman  and Chief  Executive Officer of      December 2003
Kristiansand, Norway                               Gabriel    Resources    Ltd.,   a  mining
                                                   corporation,   from   March  2003 to  May
                                                   2005.   President   and  Chief  Executive
                                                   Officer  of  Falconbridge  Ltd., a mining
                                                   corporation, from 1996 to February 2002.

John W. Lill(2)(4)               Director          Executive   Vice   President   and  Chief      December 2003
Toronto, Ontario; Canada                           Operating Officer of Dynatec Corporation,
                                                   a  mining  corporation,   since  November
                                                   2003.   President  and  Chief   Operating
                                                   Officer  (Base Metals) with BHP Billiton,
                                                   a mining  corporation,  from 2001 to 2003
                                                   and Chief Operating Officer (Copper) with
                                                   BHP Billiton from 2000 to 2001. From 1998
                                                   to  2001,   Vice   President   of  Mining
                                                   Operations  for Rio Algom Ltd.,  a mining
                                                   corporation.

Randall Oliphant(1)(5)           Director          Chairman  and Chief  Executive Officer of      February 2005
Toronto, Ontario; Canada                           Rockcliff   Group   Limited,   a  private
                                                   company  investing  mainly in the  mining
                                                   sector, since 2003. Prior thereto, served
                                                   in  various  senior  financial  roles  in
                                                   Barrick Gold  Corporation  culminating in
                                                   appointment as Chief Executive Officer in
                                                   1999 until 2003.

Robert G. Puchniak(1)            Director          Executive   Vice   President   and  Chief      October 1999
Winnipeg, Manitoba; Canada                         Financial  Officer of James Richardson  &
                                                   Sons,  Limited ("James Richardson") since
                                                   March      2001.      Prior      thereto,
                                                   Vice-President,  Finance and  Investment,
                                                   James Richardson since 1996.

Guy J. Turcotte((7))(9)          Chairman and                                                       July 1999
Calgary, Alberta; Canada         Director          Chairman  of  the  Board  of   Directors.
                                                   Prior to April 2005,  President and Chief
                                                   Executive  Officer of  Western  from July
                                                   1999.  Also,  Chairman  of  Fort  Chicago
                                                   Energy  Partners,  L.P.  since  September
                                                   1997 and Chief  Executive  Officer  until
                                                   December 2002.


Mac H. Van Wielingen(1)(3)((6))  Director          Co-Chairman      of    ARC      Financial      December 1999
Calgary, Alberta; Canada                           Corporation ("ARC"), a private investment
                                                   management  company focused on the energy
                                                   sector, and Chairman of ARC Energy Trust.
                                                   Previously,  Chief  Executive  Officer of
                                                   ARC from 1989 until June 2000.

OFFICERS

Steve Reynish ((8))              Executive         Executive    Vice-President    and  Chief           --
Calgary, Alberta; Canada         Vice-President    Operating   Officer   of   Western  since
                                 and Chief         January 1,  2006;  prior  thereto, Senior
                                 Operating Officer Vice    President    Mining    Operations
                                                   including   secondment  to  Albian  Sands
                                                   Energy as Chief  Operating  Officer since
                                                   2002
</TABLE>

<PAGE>
                                            -26-


<TABLE>
<CAPTION>
    NAME AND MUNICIPALITY OF     PRESENT POSITION    PRINCIPAL OCCUPATION DURING THE LAST        DIRECTOR SINCE
           RESIDENCE                AND OFFICE                    FIVE YEARS
-----------------------------    ----------------  ------------------------------------------   ----------------
<S>                              <C>               <C>                                          <C>
David A. Dyck                    Senior            Vice-President,    Finance    and   Chief           --
Calgary, Alberta; Canada         Vice-President,   Financial   Officer   of   Western  since
                                 Finance and       April 2000;  prior  thereto,  Senior Vice
                                 Chief Financial   President  Finance  &  Administration and
                                 Officer           Chief   Financial    Officer   of  Summit
                                                   Resources   Limited    ("Summit")   since
                                                   September  1998;  Vice President  Finance
                                                   and  Chief  Financial  Officer  of Summit
                                                   from October 1996 to September 1998.

Charles W. Berard                Corporate         Partner   with     Macleod     Dixon LLP,           --
Calgary, Alberta; Canada         Secretary         Barristers & Solicitors.
</TABLE>

NOTES:
(1) Member of the Audit Committee.

(2) Member of the Compensation Committee.

(3) Member of the Governance Committee.

(4) Member of the Health, Safety and Environment Committee.

(5) Member of the Reserves and Business Risk Committee

(6) Mr.  Van  Wielingen  was  a  director  of  Gauntlet   Energy   Corporation
    ("Gauntlet")  from  September  1999 to December 2003. On June 17, 2003, an
    order was granted  under the  COMPANIES  CREDITORS  ARRANGEMENT  ACT which
    provided   creditor   protection   to  Gauntlet  to  develop  a  financial
    restructuring plan that was approved by its creditors.

(7) Mr.  Guy  Turcotte  resigned  as  President  and Chief  Executive  Officer
    effective April 15, 2005 and assumed the position of Chairman of the Board
    and Director.  Mr. Geoff Cumming stepped down as Chairman  effective April
    15, 2005, continuing as the independent Lead Director.

(8) As announced on November 23,  2005,  Mr.  Frangos  decided to step down as
    Executive Vice President and Chief Operating  Officer effective January 1,
    2006 to be replaced by Mr. Steve Reynish, previously Senior Vice President
    Mining with Western and prior to that,  seconded  into Albian Sands Energy
    Inc. as its Chief  Operating  Officer since 2002. Mr. Frangos will stay on
    with the Company as Senior Advisor to management and to the Board.

(9) On  May  10  1998,  Mr.  Turcotte   resigned  as  a  director  of  Chauvco
    International  Ltd.  ("Chauvco").   On  January  26,  1999,  a  bankruptcy
    receiving  order was granted by the Alberta Court of Queen's Bench against
    Chauvco and it was susequently ceased traded for failing to file financial
    statements and other related documents.

Each director  holds office until the next annual meeting of  shareholders  of
the Corporation or until their successors are duly elected or appointed.

As at March 28, 2006, the directors and officers of the Corporation,  together
with their respective spouses, children or corporations controlled by them own
or control, directly or indirectly, an aggregate of 3,368,614 Common Shares or
approximately  2.1% of the issued and  outstanding  voting  securities  of the
Corporation. Not included in the amount above is 5,650,781 Common shares owned
by Turcotte  Family  Holdings Ltd.  ("Turcotte  Holdings").  Mr. Turcotte is a
discretionary  beneficiary  under a family trust that exercises voting control
over Turcotte Holdings. Mr. Turcotte does not own, directly or indirectly,  or
exercise control or direction over any voting shares of Turcotte Holdings.

Investors  should be aware  that some of the  directors  and  officers  of the
Corporation are directors and officers of other private and public  companies.
Some of these private and public companies may, from time to time, be involved
in business  transactions or banking relationships which may create situations
in which  conflicts  might  arise.  Any such  conflicts  shall be  resolved in
accordance with the procedures and requirements of the relevant  provisions of
the BUSINESS CORPORATIONS ACT (Alberta),  including the duty of such directors
and  officers  to act  honestly  and in good  faith  with a view  to the  best
interests of the Corporation.

<PAGE>
                                     -27-


                                AUDIT COMMITTEE

COMPOSITION AND QUALIFICATIONS

The Audit Committee consists of three outside independent directors: Robert G.
Puchniak (Chair),  Randall Oliphant and Mac H. Van Wielingen,  all of whom are
financially literate.

In considering criteria for the determination of financial literacy, the Board
of Directors  looks at the ability to read and understand a balance sheet,  an
income statement and a cash flow statement of a public company.

The following is a brief  description  of the education and experience of each
of the members of the Audit Committee:

ROBERT G. PUCHNIAK, CHAIRMAN AND INDEPENDENT DIRECTOR

Mr.  Puchniak  was  appointed  Executive  Vice-President  and Chief  Financial
Officer  of James  Richardson  & Sons,  Limited,  an  investment  and  holding
corporation,  in March 2001 and prior thereto was Vice-President,  Finance and
Investment  with James  Richardson & Sons,  Limited since  November  1996. Mr.
Puchniak was President and Chief Executive Officer of Tundra Oil and Gas Ltd.,
a private  oil and gas  corporation,  from  January  1989 to April  2003.  Mr.
Puchniak has also held positions  with Gendis Inc. and  Richardson  Securities
Limited.  Mr.  Puchniak  is a  director  of a number  of  public  and  private
corporations including James Richardson  International Limited, Tundra Oil and
Gas Ltd.,  Opti Canada Inc.,  Trident  Resources  Corp,  Petrobank  Energy and
Resources Ltd.,  Richardson  Partners  Financial  Holdings Limited and Lombard
Realty Limited.  Past  involvements  include Director,  Moffat  Communications
Limited,  Terraquest Energy  Corporation and Richland  Petroleum  Corporation;
Chairman,  Manitoba Teachers' Retirement Fund; Chairman, Council of Examiners,
Institute of Chartered Financial Analysts; and President,  Winnipeg Society of
Financial Analysts. Mr. Puchniak holds a Bachelor of Commerce (Honours) degree
from the University of Manitoba and was awarded the University  Gold Medal for
his achievements. He earned a Chartered Financial Analyst designation in 1975.

RANDALL OLIPHANT, INDEPENDENT DIRECTOR

Mr. Randall Oliphant is the Chairman and Chief Executive  Officer of Rockcliff
Group  Limited,  a private  corporation  actively  involved  in the  strategic
planning and corporate  development of its investee companies,  principally in
the mining  sector.  He is on the  Advisory  Board of  Metalmark  Capital  LLC
(formerly  Morgan  Stanley  Capital  Partners)  and  serves on the Boards of a
number of public,  private companies and not-for-profit  organizations.  Until
2003,  he was the  President  and Chief  Executive  Officer  of  Barrick  Gold
Corporation,  and  served in senior  financial  positions  since  joining  the
company in 1987 prior to being appointed Chief Executive  Officer in 1999. Mr.
Oliphant  holds a B.Comm.  from the  University  of Toronto and is a Chartered
Accountant.

MAC H. VAN WIELINGEN, INDEPENDENT DIRECTOR

Mr. Van  Wielingen is a founder and  currently  Co-Chairman  of ARC  Financial
Corporation, an investment management corporation focused on the energy sector
in Canada.  Mr. Van Wielingen is also a founder and currently  Chairman of ARC
Energy  Trust.  He is a past and a current  director of  numerous  private and
public  energy  companies  in  Canada  and has 25 years of  experience  in the
investment business relating to the energy sector in Canada. Mr. Van Wielingen
holds an Honours  Business  Degree  from the  University  of  Western  Ontario
Business School and has studied post-graduate Economics at Harvard University.

<PAGE>
                                     -28-


RESPONSIBILITIES AND TERMS OF REFERENCE

The following is a summary of the key roles and  responsibilities of the Audit
Committee.  Full particulars are set out in the Audit Committee  Charter which
is attached as Appendix C hereto.

The  Audit  Committee  approves   Western's  interim  unaudited   consolidated
financial   statements,   press   releases  and  reviews  the  annual  audited
consolidated  financial  statements and certain corporate disclosure documents
including the annual information form,  management's  discussion and analysis,
offering  documents  including all prospectuses  and other offering  memoranda
before  they are  approved  by the Board.  The  Committee  reviews and makes a
recommendation  to the Board in respect  of the  appointment  of the  external
auditor and it monitors  accounting,  financial  reporting,  control and audit
functions.  The Audit Committee meets to discuss and review the audit plans of
the external  auditors and is directly  responsible for overseeing the work of
the external auditor with respect to the preparing or issuing of the auditor's
report or the performance of other audit,  review or attest services including
the resolution of  disagreements  between  management and the external auditor
regarding  financial  reporting.  The Committee questions the external auditor
independently  of management  and reviews a written  statement of the external
auditors'  independence based on the criteria found in the  recommendations of
the Canadian Institute of Chartered  Accountants.  The Committee considers and
makes a  recommendation  to the Board as to the  compensation  of the external
auditor  and  ensures  that fees paid to the  external  auditor  for audit and
non-audit  services are publicly  disclosed.  The Committee  must be satisfied
that  adequate  procedures  are in place for the  review of the  Corporation's
public  disclosure  of  financial  information  extracted  or derived from its
financial  statements  and it  periodically  assesses  the  adequacy  of those
procedures.  In  addition,  it reviews  the  internal  control  procedures  to
determine their  effectiveness  to ensure  compliance  with  applicable  legal
requirements,  regulatory  requirements  and  Western's  policies.  The  Audit
Committee reviews the controls in place with respect to officers' expenses and
perquisites,  reviews  insurance  coverage for significant  business risks and
uncertainties  and reviews  material  litigation  and its impact on  financial
reporting.   The  Committee  has  established   procedures  for  dealing  with
complaints,  submissions  or concerns on an anonymous and  confidential  basis
which come to its attention  with respect to accounting,  internal  accounting
controls or audit matters.

The Audit  Committee's  mandate was modified during 2005 to transfer its roles
and  responsibilities  concerning  the  review  of the  independent  qualified
reserves  evaluator's  report  on the  Corporation's  estimated  oil  and  gas
reserves to the  Reserves  and  Business  Risk  Committee.  The  Reserves  and
Business Risk Committee was  commissioned  during 2005 and is also a committee
of the Board.

AUDITOR SERVICE FEES

PricewaterhouseCoopers  LLP has served as the  auditors  of Western  since its
incorporation.   The  following  table  summarizes  the  total  fees  paid  to
PricewaterhouseCoopers  LLP for the years ended December 31, 2005 and December
31, 2004

                                                  2005(1)               2004
                                              -----------          ----------
         Audit fees                             $146,396            $131,980
         Tax fees                               $133,108              24,960
-----------------------------------------------------------------------------
         TOTAL                                  $279,504            $156,940

NOTE:

(1) Paid or estimated to be payable for 2005 services.


Audit fees were paid for  professional  services  rendered by the auditors for
the  audit  of the  Corporation's  annual  financial  statements  or  services
provided in connection  with statutory and regulatory  filings.

<PAGE>
                                     -29-


Audit-related fees were paid for review of quarterly  financial  statements of
Western,  attendance at quarterly audit meetings, and for services provided in
connection with  financings.  Tax fees were paid for tax advice and assistance
with tax audits, including GST and property tax reviews.

All permissible categories of non-audit services require pre-approval from the
Audit Committee.

                            RISKS AND UNCERTAINTIES

The Corporation is exposed to a number of risks and uncertainties  relating to
its operations.

THE MINE, EXTRACTION PLANT AND UPGRADER MAY NOT PERFORM AS PLANNED.

The Project may encounter  interruptions in production or additional costs due
to many factors,  including:

         o    breakdown or failure of equipment or processes;

         o    design errors;

         o    operator  errors;

         o    violation of permit  requirements;

         o    disruption in the supply of energy;  and

         o    catastrophic  events such as fire, earthquake, storms or
              explosions.

The Project  consists of multiple  facilities,  all of which must be run on an
integrated  and  co-ordinated  basis.  There  can be no  assurance  that  each
component  will  continuously  operate as  designed  or  expected  or that the
necessary  levels  of  integration  and  co-ordination  will  continuously  be
achieved.  Some of the mining and extraction processes employed in the Project
represent new applications of established processes, processes that are larger
in scale than other commercial operations, or new processes that are scaled-up
from the pilot plant  processes  used to test the  feasibility of the Mine and
Extraction Plant.  There can be no assurance that all components of the mining
and extraction facility will continue to perform as expected or that the costs
to operate this facility will not be significantly higher than expected.

There  can be no  assurance  that the  Upgrader  will  have the same  level of
success in upgrading  bitumen and purchased  feedstocks into products with the
desired  specifications.  Costs to operate the Upgrader  may be  significantly
higher than expected.

THIRD-PARTY FACILITIES MAY NOT OPERATE AS PLANNED.

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

         o    pipeline  transportation  to be provided  through  the  Corridor
              pipeline system;

         o    electricity  and  steam  to be  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 by the ATCO pipeline;

         o    hydrogen to be provided  to the  Upgrader  from the HMU and Dow;
              and

<PAGE>
                                     -30-


         o    electricity  and steam to be provided to the  Upgrader  from the
              Upgrader cogeneration facility.

For the Mine and Extraction  Plant,  electricity  and steam is provided by the
Muskeg River cogeneration  facility. If the Muskeg River cogeneration facility
fails  to  continuously  operate  in  the  manner  designed,  there  can be no
assurance  that the  Owners  will be able to  obtain  alternative  sources  of
electricity on a timely basis, at prices acceptable to Western,  or at all. If
the cogeneration facility does not continuously provide the required steam, it
is unlikely  that other  sources of steam could be acquired on a timely basis,
at prices acceptable to Western, or at all.

For the  Upgrader,  the  electricity  and steam is  provided  by the  Upgrader
cogeneration  facility.  There  can be no  assurance  that  in the  event  the
Upgrader  cogeneration  facility fails to  continuously  operate in the manner
designed, the Owners will be able to secure alternative sources of electricity
and steam on a timely basis, at prices acceptable to Western, or at all.

The HMU is designed to produce  approximately  75% of the Upgrader's  hydrogen
requirements,  with the  remainder  to be provided by Dow. If the HMU fails to
perform  continuously  as  designed  or Dow fails to deliver  pursuant  to its
contract,  respectively,  there can be no  assurance  that the Project will be
able to  obtain  its  hydrogen  requirements  on a  timely  basis,  at  prices
acceptable to Western, or at all.

The Project  relies on  transportation  of bitumen and upgrader  output from a
pipeline system owned and operated by Kinder Morgan.  If the Corridor pipeline
system is unavailable for any reason,  Western will have to find  alternatives
to the Corridor  pipeline system which may not be available on a timely basis,
at prices acceptable to Western, or at all.

Under the terms of certain third-party agreements, the Owners are committed to
pay for utilities and services on a long-term  "take-or-pay" basis, regardless
of the extent that such utilities and services are actually used. In addition,
under  the  terms of the  agreement  with  Kinder  Morgan,  Western  must make
scheduled payments to them even if the Corridor pipeline system has diminished
capacity or is unavailable. If, due to Project delays, suspensions, shut-downs
or other  reasons,  the Owners  fail to meet  their  commitments  under  these
long-term agreements,  the Owners may incur substantial costs and may, in some
circumstances,  be  obligated to purchase the  facilities  constructed  by the
third parties to provide the services and  utilities  for a purchase  price in
excess of the fair market value of the  facilities.  There can be no assurance
that Western will have sufficient funds to satisfy these obligations.

Most of the contracts with third-party operators do not contain provisions for
the payment of liquidated damages.  Accordingly, if certain of the third-party
facilities do not operate as planned, Western will not have a direct financial
claim against the third-party operators.

THE PRICE OF CRUDE OIL AND NATURAL GAS MAY  FLUCTUATE  AND  NEGATIVELY  IMPACT
FINANCIAL RESULTS.

Western's  financial  results are dependent upon the prevailing price of crude
oil and natural gas.  Oil and natural gas prices  fluctuate  significantly  in
response to supply and demand  factors  beyond  Western's  control.  Political
developments,  especially in the Middle East,  can affect world oil supply and
oil  prices.  As a result  of the  relatively  higher  operating  costs of the
Project  compared  to  some  conventional  crude  oil  production  operations,
Western's  operating  margin is more sensitive to oil prices than that of some
conventional crude oil producers.

Any  prolonged  period of low oil prices  could  result in a  decision  by the
Owners to suspend or reduce  production.  Any such  suspension or reduction of
production would result in a corresponding  substantial  decrease in Western's
revenues  and  earnings and could  expose  Western to  significant  additional
expense

<PAGE>
                                     -31-


as a result of certain  long-term  contracts.  If the Owners did not decide to
suspend or reduce  production,  the sale of product  at reduced  prices  would
lower revenues.

In addition,  because  natural gas comprises a  substantial  part of Western's
operating  costs,  any  prolonged  period  of high  natural  gas  prices  will
negatively impact Western's financial results.

WESTERN  MAY  EXPERIENCE  PRICING  PRESSURE  ON ITS  SHARE  OF  THE  PROJECT'S
SYNTHETIC CRUDE OIL PRODUCTION DUE TO OVERSUPPLY AND COMPETITION.

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. There exist other suppliers of synthetic crude oil and
there are several additional  projects being  contemplated.  If undertaken and
completed,  these projects will result in a significant increase in the supply
of synthetic crude oil to the market. In addition, not all refineries are able
to  process or refine  synthetic  crude oil.  There can be no  assurance  that
sufficient  market demand will exist at all times to absorb Western's share of
the Project's synthetic crude oil production.

WESTERN MAY NOT BE ABLE TO PRODUCE A HIGH VALUE SINGLE STREAM BLEND.

Western  expects that  concurrent  with expansion  initiatives it will be in a
position to market a single  stream blend of  synthetic  crude oil which has a
greater value than the heavy and light streams currently marketed.  There is a
risk that Western will be unable to create a single stream with a higher value
than the  heavy  and  light  streams.  There is also a risk that the price per
barrel from selling two  synthetic  crude oil streams and vacuum gas oil could
be  significantly  less  than the  price  per  barrel  from  selling  a single
synthetic crude oil stream and vacuum gas oil.

FLUCTUATIONS  IN THE US AND CANADIAN  DOLLAR EXCHANGE RATE MAY CAUSE WESTERN'S
OPERATING COSTS TO RISE.

Crude oil  prices  are  generally  based on a US dollar  market  price,  while
Western's  operating  costs are  primarily  denominated  in Canadian  dollars.
Adverse  fluctuations  in the US and Canadian  dollar  exchange rate may cause
Western's operating costs to rise in relation to Western's  revenues.  Western
undertakes minor hedging activities against currency  fluctuations.  There can
be no assurance that current  activities or more expansive hedging programs in
the future that Western may adopt are or would be successful.

WESTERN COMPETES WITH LARGER COMPANIES AND ALTERNATIVE FUELS WHEN IT SELLS ITS
SHARE OF THE PROJECT'S PRODUCTION.

The Canadian and international petroleum industry is highly competitive in all
aspects,  including  the  distribution  and  marketing of petroleum  products.
Western  competes with  established oil sands operators which have established
operating histories and greater financial and other resources than Western. In
addition,  Western competes with other producers of synthetic crude oil blends
and producers of conventional crude oil, including Shell and Chevron,  some of
whom have  lower  operating  costs and many of whom have  extensive  marketing
networks.  The crude oil industry  also  competes  with other  industries  and
alternative  energy sources in supplying energy,  fuel and related products to
consumers.

FEEDSTOCK SUPPLY FOR THE UPGRADER MAY NOT ALWAYS BE AVAILABLE.

The Upgrader will require certain additional feedstocks to produce its output.
Western  has entered  into  contracts  for  required  feedstocks  for terms of
between one and five years.  There can be no assurance that

<PAGE>
                                     -32-


feedstocks  of the desired  quality  will be available on a timely basis after
these  contracts  expire,  at  prices  acceptable  to  Western,   or  at  all.
Unavailability of required feedstocks could have an adverse effect on the rate
and quality of Upgrader output.

THE PROJECTIONS AND ASSUMPTIONS  ABOUT WESTERN'S FUTURE  PERFORMANCE MAY PROVE
TO BE INACCURATE.

Western  has  only a few  years  of  operating  results.  Western's  long-term
financing  plan is based upon certain  assumptions  and financial  projections
regarding  its share of revenues  and of  operating,  maintenance  and capital
costs of the  Project.  These  projections  and  assumptions  may  prove to be
inaccurate.

DEBT LEVELS  COULD LIMIT  FUTURE  FLEXIBILITY  IN  OBTAINING  ADDITIONAL  DEBT
FINANCING AND IN PURSUING BUSINESS OPPORTUNITIES.

As at December  31,  2005,  Western  had  approximately  $707  million of debt
(including  obligations  under the HMU lease and net option premiums  deferred
associated  with Western's  strategic  crude oil hedging  program  implemented
during  the  third  quarter  of  2005).  Western  may also  incur  significant
additional indebtedness for various purposes, including expansions.  Western's
debt level and  restrictive  covenants  will have an  important  effect on its
future operations.

In addition,  Western's ability to make scheduled payments or to refinance its
debt  obligations  will depend upon its financial  and operating  performance,
which in turn,  will  depend upon  prevailing  industry  and general  economic
conditions beyond Western's control.  There can be no assurance that Western's
operating  performance,  cash flow and capital resources will be sufficient to
repay its debt in the future.

FINANCING  ARRANGEMENTS  CONTAIN COVENANTS  LIMITING OUR DISCRETION TO OPERATE
OUR BUSINESS.

Western's financing arrangements contain provisions that limit its discretion to
operate its business. If Western fails to comply with the restrictions set forth
in its current or future financing agreements, Western will be in default and
the principal and accrued interest may become due and payable.
THE PROJECT MAY EXPERIENCE  EQUIPMENT FAILURES FOR WHICH WESTERN DOES NOT HAVE
SUFFICIENT INSURANCE.

The Upgrader  processes  large  volumes of  hydrocarbons  at high pressure and
temperatures  in equipment  with fine  tolerances.  Equipment  failures  could
result in damage to the  Extraction  Plant and the Upgrader  and  liability to
third  parties  against  which  Western may not be able to fully insure or may
elect not to insure for various  reasons,  including high premium costs.  Even
with adequate  insurance,  delays in realizing on claims and replacing damaged
equipment could adversely affect Western's operations and revenues.

HEDGING  ACTIVITIES  COULD  RESULT IN LOSSES OR LIMIT THE  BENEFIT  OF CERTAIN
COMMODITY PRICE INCREASES.

The nature of  Western's  operations  results in exposure to  fluctuations  in
commodity  prices.  Western has  initiated a hedging  program to use financial
instruments  and  physical  delivery  contracts to hedge its exposure to these
risks.  When  engaging in hedging  Western  will be exposed to  credit-related
losses in the event of  non-performance  by  counterparties  to the  financial
instruments.  From time to time  Western  may enter  into  additional  hedging
activities  in an effort to mitigate the  potential  impact of  declining  oil
prices. These activities may consist of, but may not be limited to:

         o    buying a price floor under which  Western will receive a minimum
              price for its oil production;

<PAGE>
                                     -33-


         o    buying a collar under which  Western will receive a price within
              a specified range for its oil production;

         o    entering into fixed contracts for oil production; and

         o    entering  into a contract  to fix the  differential  between the
              price  for   Western's   outputs   and  either  the  West  Texas
              Intermediate or the Edmonton Par crude oil pricing benchmarks.

If product prices increase above those levels  specified in any future hedging
agreements, Western could lose the cost of floors or ceilings or a fixed price
could  limit  Western  from  receiving  the full  benefit of  commodity  price
increases. In addition, by entering into these hedging activities, Western may
suffer financial loss if it is unable to produce sufficient  quantities of oil
to fulfil its obligations.

Western may hedge its exposure to the costs of various  inputs to the Project,
such as natural gas or  feedstocks.  If the prices of these inputs falls below
the levels specified in any future hedging agreements,  Western could lose the
cost of ceilings or a fixed price could limit Western from  receiving the full
benefit of commodity price decreases.

RESERVE AND RESOURCE ESTIMATES ARE UNCERTAIN.

There are numerous uncertainties inherent in estimating quantities of reserves
and  resources,  including many factors beyond  Western's  control.  Western's
reserve and resource data  represent  estimates  only.  The usefulness of such
estimates is highly  dependent  upon the accuracy of the  assumptions on which
they are based,  the quality of the  information  available and the ability to
compare such information against industry standards.

Fluctuations  of oil  prices  may  render  the  mining of oil  sands  reserves
uneconomical.  Other factors  relating to the oil sands reserves,  such as the
need  for  orderly  development  of ore  bodies  or the  processing  of new or
different grades of ore, may impair Western's profitability.

In general,  estimates of economically  recoverable  bitumen  reserves and the
related future net pretax cash flows of the Project are based upon a number of
variable factors and assumptions, such as:

         o    historical production from similar properties which are owned by
              other operators;

         o    limited production and operating history of the Project;

         o    the assumed effects of regulation by governmental agencies;

         o    estimated future operating costs; and

         o    the availability of enhanced recovery techniques,

all of which may vary considerably from actual results of the Project.

There is a limited history of production from Western's  properties.  All such
estimates are to some degree speculative,  and classifications of reserves are
only attempts to define the degree of speculation involved.  Western's reserve
figures  have been  determined  based upon  assumed  oil prices and  operating
costs. For those reasons,  estimates of the economically  recoverable  bitumen
reserves attributable to any particular group of properties, classification of
such  reserves  based on risk of recovery and estimates of future net revenues
expected from them,  prepared by different  engineers or by the same engineers
at different  times,

<PAGE>
                                     -34-


may vary  substantially.  Western's  actual  production,  revenues,  taxes and
development and operating expenditures with respect to Western's reserves will
vary  from such  estimates,  and such  variances  could be  material.  Reserve
estimates may require revision based on actual production experience.

INDEPENDENT REVIEWS MAY BE INACCURATE.

Although  independent  and  qualified  third  parties have  prepared  reviews,
reports and projections  relating to the viability and expected performance of
the  Project,  there can be no  assurance  that  these  reports,  reviews  and
projections and the assumptions on which they are based will, over time, prove
to be accurate.

SHELL AND CHEVRON MAY NOT AGREE WITH WESTERN ON MATTERS RELATED TO THE PROJECT.

The Project is a joint venture among Shell, Chevron and Western.  Future plans
of the Project,  including  decisions  related to levels of  production,  will
depend on agreement among the Owners and will depend on the financial strength
and views of Shell and Chevron. There can be no assurance that the Owners will
agree on all matters relating to the Project.

Under the Joint  Venture  Agreement,  ordinary  resolutions  of the  Executive
Committee  may  be  passed  without  Western's  consent  and  there  can be no
assurance that such resolutions may not adversely affect Western.

In addition,  if Western's voting interest in any functional units falls below
15%, Western's consent will not be required for an extraordinary resolution of
the Executive  Committee relating to that functional unit and such resolutions
may adversely affect Western.

SHELL AND CHEVRON MAY NOT MEET THEIR OBLIGATIONS TO THE PROJECT.

Western is subject to the risk of  non-payment  by Shell or Chevron in meeting
their  payment  obligations  to the Project.  To the extent any Owner does not
meet  its  obligations  to fund its  costs in  respect  of the  Joint  Venture
Agreement and related agreements,  Western, together with any other performing
Owners, would be required to fund those obligations.

IF WESTERN  DEFAULTS ON ITS  OBLIGATIONS  UNDER THE JOINT  VENTURE  AGREEMENT,
SHELL AND CHEVRON  WILL HAVE THE RIGHT TO PURCHASE  WESTERN'S  INTEREST IN THE
JOINT VENTURE AT A DISCOUNT.

If  Western  fails  to meet all or part of our  obligations  under  the  Joint
Venture Agreement,  including by failing to participate in any expansion of an
existing  mine which does not require an  expansion of the  Extraction  Plant,
Upgrader,  major shared facilities or third party facilities (which expansions
can be  carried  out  pursuant  to an  ordinary  resolution  of the  Executive
Committee),  the other Owners will have an option to purchase Western's entire
ownership interest in the Joint Venture and related assets at a discount.  The
amount at which they could  purchase  Western's  ownership  interest  would be
equal to 80% of the capital costs incurred..

SHELL MAY NOT FULFIL ITS  OBLIGATIONS  TO WESTERN  UNDER OUR  LONG-TERM  SALES
CONTRACT.

Western  sells its share of  vacuum  gas oil  produced  by the  Project  to an
affiliate of Shell on a long-term basis. Since a large portion of our revenues
will be received from an affiliate of Shell, Western will have a concentration
of credit risk. Furthermore, if the Shell affiliate does not have the capacity
at the Scotford  Refinery to physically  process Western's share of vacuum gas
oil produced by the Project after using its commercially reasonable efforts to
maintain such capacity, it will not be required to purchase Western's

<PAGE>
                                     -35-


share  of  vacuum  gas  oil  until  the  Refinery   regains   such   capacity.
Modifications  to the Scotford  Refinery were  undertaken to permit it to take
the expected vacuum gas oil output.  If the affiliate of Shell were to default
on, or not be  required  to  fulfil  its  obligations  to  Western,  or if the
Scotford  Refinery is not capable of processing  the vacuum gas oil, there can
be no assurance  that Western  could sell its share of vacuum gas oil to other
purchasers  at a price  equal to or  greater  than  that  provided  for in its
contract with the Shell affiliate, or at all.

Additionally, the price Western receives for products sold to the affiliate of
Shell may vary depending on the  characteristics  of the products sold. To the
extent  the   characteristics  of  the  products  fail  to  meet  agreed  upon
specifications,  the  purchase  price  for  such  products  will  be  adjusted
downward.  If the  characteristics  of the  products are  significantly  below
specifications  the  affiliate  of Shell is entitled to reject such  products.
Downward  adjustment of the purchase  price or rejection of the products could
have an adverse effect on Western's operations and revenues,  and there can be
no assurance that we could sell any rejected products elsewhere.

IF WESTERN  DOES NOT  PARTICIPATE  IN CERTAIN  EXPANSIONS,  WESTERN  WILL LOSE
VOTING OR SIGNIFICANT EXPANSION RIGHTS.

If Western does not  participate in expansions on the western portion of Lease
13, in certain  circumstances  Western's  voting  interest will be diluted and
Western's consent will no longer be required for extraordinary  resolutions of
the Executive  Committee.  In addition,  if Western does not participate in an
expansion on the remainder of Lease 13 or Shell's Other Athabasca  Leases,  or
if  Western  no longer  has an  ownership  interest  in each  functional  unit
comprising  the  Project,  Western will lose its right to  participate  in any
further  expansions,  lose any rights to share in the  resources  contained on
Leases 88 and 89 and  Shell's  Other  Athabasca  Leases and lose any rights to
participate  in an area of mutual  interest with the other  Owners.  Shell and
Chevron, have significantly greater capital resources than that of Western. If
the other Owners decide to undertake  expansions,  including expansions on the
eastern portion of Lease 13 and on Leases 88 and 89, there can be no assurance
that  Western  will be able to fund  its  share  of the  expansion.  Western's
participation  would be  subject to several  conditions,  including  Western's
satisfaction  with  feasibility  studies and Western's access to the necessary
capital resources.

IF  WESTERN  PARTICIPATES  IN CERTAIN  EXPANSIONS,  THOSE  EXPANSIONS  WILL BE
SUBJECT TO MANY OF THE SAME RISKS AS THE PROJECT.

Western may  participate in expansions on the western  portion of Lease 13, on
the remainder of Lease 13 or on Shell's Other Athabasca Leases. The Owners are
evaluating potential long-term development opportunities relating to resources
contained  within Lease 13 and on Shell's Other Athabasca  Leases.  If Western
were  to  participate  in  any  expansion,  Western  will  require  additional
financing in order to fund its share of costs  associated  with an  expansion.
Additionally, Western's participation in expansions will be subject to many of
the same risks as the Project.

EXPANSIONS MAY NOT PROCEED AS PLANNED

The expansion strategy and configuration  currently envisioned may not proceed
as planned  with  respect to scope,  timing and  execution.  This may directly
impact the volume, quality and timing of producing marketable materials.

WESTERN MAY NOT BE ABLE TO EFFECTIVELY MANAGE ITS GROWTH.

The  Joint  Venture  Agreement  permits  participation  in  certain  expansion
opportunities.    Participation   in   any   expansion   opportunities   would
significantly increase the demands on Western's management

<PAGE>
                                     -36-


resources. Western may not be able to effectively manage these expansions, and
any  failure  to do so could  have a  material  adverse  effect  on  Western's
business, financial condition or results of operations.

THE  PROJECT  MAY NOT BE ABLE TO HIRE AND  RETAIN  THE  SKILLED  EMPLOYEES  IT
REQUIRES.

The Project requires experienced employees with particular areas of expertise.
There are other oil sands and other  industrial  projects  and  expansions  in
Alberta  that  compete  with  the  Project  for  skilled  employees,  and such
competition may result in increases to the compensation paid to such employees
and shortages of skilled  tradespersons.  The Project has already  experienced
increased costs as a result of such competition and decreases in productivity.
There  can be no  assurances  that  all of the  required  employees  with  the
necessary expertise will be available.

VARIOUS  HAZARDS  INHERENT IN  WESTERN'S  OPERATIONS  COULD  RESULT IN LOSS OF
EQUIPMENT OR LIFE.

The  operation of the Project is subject to the  customary  hazards of mining,
extracting,  transporting and processing  hydrocarbons,  including the risk of
catastrophic events such as fire, earthquake, storms or explosions. A casualty
occurrence might result in the loss of equipment or life, as well as injury or
property damage. Western does not carry insurance with respect to all casualty
occurrences and  disruptions.  There is no assurance that Western's  insurance
will be  sufficient  to cover any such casualty  occurrences  or  disruptions,
including  with respect to the damage  caused by the fire at the Mine.  Losses
and liabilities  arising from uninsured or  under-insured  events could have a
material  adverse effect on the Project and on Western's  business,  financial
condition and results of operations.

THE ABANDONMENT  AND  RECLAMATION  COSTS RELATING TO THE PROJECT MAY BE HIGHER
THAN ANTICIPATED.

Western will be responsible for compliance with terms and conditions set forth
in the environmental and regulatory  approvals for the Project and all present
and future laws and regulations  regarding the decommissioning and abandonment
of the Project and the  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  by the  prescribed  time  period,  Western must
establish and fund a reclamation  trust fund.  Western currently does not hold
the  minimum  credit  rating.  Even if Western  does hold the  minimum  credit
rating, in the future Western may determine that it is prudent or that Western
is 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  Western  concludes  that  the
establishment  of such a fund is prudent  or  required,  Western  may lack the
financial  resources  to do  so.  Western  may  also  be  required  by  future
regulatory  requirements  to  establish  a fund or place  funds in trust  with
regulators  for the  decommissioning  and  abandonment  of the Project and the
reclamation of its lands.

THE PROJECT MAY FAIL TO COMPLY WITH VARIOUS ENVIRONMENTAL  APPROVALS WHICH MAY
EITHER CAUSE THE WITHDRAWAL OF THESE APPROVALS OR IMPOSE OTHER COSTS.

The  operation  and  decommissioning  of the  Project and  reclamation  of the
Project's  lands are  conditional  upon various  environmental  and regulatory
approvals  issued by  governmental  authorities.  Further,  the  operation and
decommissioning  of the Project and reclamation of the Project's lands will be
subject to approvals and present and future laws and  regulations  relating to
environmental  protection and operational  safety.  Risks of substantial costs
and  liabilities  are  inherent in oil sands  operations,  and there can be no
assurance that substantial  costs and liabilities will not be incurred or that
the Project will be permitted by regulators to carry on its operations.  Other
developments,  such as  increasingly  strict  environmental  and safety  laws,
regulations and  enforcement  policies  thereunder,  and claims for damages

<PAGE>
                                     -37-


to property or persons  resulting  from the Project's  operations,  could also
result in substantial  costs and liabilities to Western,  delays in operations
or abandonment of the Project.

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  nation-wide  emissions of carbon dioxide,
methane,  nitrous oxide and other so-called  "greenhouse  gases".  The Project
will 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.

CHANGES IN THE  WESTERN'S  OIL SANDS CROWN  ROYALTIES  POSITION  AND OIL SANDS
TAXATION MAY NEGATIVELY IMPACT FINANCIAL RESULTS.

Western, through its 20 per cent undivided interest in the Project,  currently
benefits from both a favourable  royalty and income tax regime in terms of the
determination  royalty  payments  until the  Project has  recovered  the costs
associated with Mine and in terms of certain accelerated deductions for income
tax purposes.  However,  there can be no assurance that this royalty or income
tax regime will not change in a manner that would  adversely  affect  Western,
either through  changes in law or through further  interpretation  of law. The
classification  of  future  expansions  for  both  royalty   calculations  and
accelerated  deductions,  and  the  availability  of  these  expenditures  for
allowable costs for royalty  purposes or as accelerated  deductions for income
tax purposes,  can have a significant  impact on Western's  royalty and income
tax expenses and payments.

CHANGES IN GOVERNMENT REGULATION OF WESTERN'S OPERATIONS MAY HARM WESTERN.

Western's  mining,  extraction and upgrading  operations and the operations of
third-party contractors are subject to extensive Canadian federal,  provincial
and  local   laws  and   regulations   governing   exploration,   development,
transportation,  production,  exports, labour standards,  occupational health,
waste disposal,  protection and remediation of the  environment,  mine safety,
hazardous materials, toxic substances and other matters. Amendments to current
laws  and  regulations  and  the  introduction  of new  laws  and  regulations
governing  operations and activities of mining corporations and more stringent
application of such laws and regulations are actively  considered from time to
time and could affect the viability of the Project.

There can be no assurance that the various  government  licenses and approvals
or amendments  thereto that from time to time may be sought will be granted to
the Project at all or with conditions  satisfactory to Western or, if granted,
will not be  cancelled  or will be renewed upon expiry or that income tax laws
and government incentive programs relating to the Project, and the mining, oil
sands and oil and gas  industries  generally,  will not be changed in a manner
which may adversely affect Western.

Currently,  Western benefits from a favourable royalty regime;  however, there
can be no assurance  that this royalty regime will not change in a manner that
would adversely affect Western.

<PAGE>
                                     -38-


Lease 13 is subject to the OIL SANDS  TENURE  REGULATION  (Alberta)  which was
introduced in 2000.  This  legislation  deems Lease 13 to continue  beyond its
primary term to the extent that the lessee has  attained the minimum  level of
evaluation of the oil sands in Lease 13 or Lease 13 is producing. There can be
no assurance that the Owners will be able to comply with the  requirements  of
the OIL SANDS TENURE  REGULATION  (Alberta).  In addition,  the  Minister,  in
certain circumstances,  may change the designation of any lease subject to the
legislation and provide notice requiring the Owners to commence  production or
recovery  of, or to  increase  existing  production  or recovery of bitumen or
other oil sands products  within the time specified in such notice.  There can
be no  assurance  that if such a notice is given,  the Owners  will be able to
comply with its terms to maintain Lease 13. Additionally, the OIL SANDS TENURE
REGULATION  (Alberta)  expires on December 1, 2008 and, if such legislation is
not renewed in its present or similarly  favourable  form, the status of Lease
13 may be in question.

CANADA  REVENUE  AGENCY  ("CRA") MAY RULE  NEGATIVELY  ON EXTENT OF QUALIFYING
EXPENDITURE AS IT RELATES TO RENUNCIATION ON 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,
individuals  shareholders  can reduce their income subject to personal  income
taxes.  During the fourth quarter of 2005,  discussions  were held between the
AOSP and CRA regarding  the proper  characterization  of certain  expenditures
included  in  the  Canadian  exploration  expenses  in  those  years.  If  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 these  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).

ABORIGINAL  PEOPLES MAY MAKE CLAIMS AGAINST  WESTERN OR THE PROJECT  REGARDING
THE LANDS ON WHICH THE PROJECT IS LOCATED.

Aboriginal  peoples have claimed  aboriginal title and rights to a substantial
portion of  western  Canada.  Certain  aboriginal  peoples  have filed a claim
against the Government of Canada,  certain governmental  entities and the City
of Fort McMurray,  Alberta claiming,  among other things,  that the plaintiffs
have  aboriginal  title to large  areas of lands  surrounding  Fort  McMurray,
including  the  lands on which  the  Project  and most of the  other oil sands
operations in Alberta are located.  Such claims, if successful,  could have an
adverse effect on the Project.

RISKS ASSOCIATED WITH EXPLORATION AND DEVELOPMENT OF HYDROCARBON RESOURCES MAY
NEGATIVELY IMPACT WESTERN

The energy  industry  is highly  competitive  in all  aspects,  including  the
exploration  for and the  development of new sources of hydrocarbon  resource.
Western will compete for the exploration and the development of new sources of
hydrocarbon  resource with major integrated oil and gas companies,  as well as
various  independent oil and gas companies.  Western will do so through its 20
per cent ownership  interest in the AOSP and also through  direct  investments
made by Western into oil sands and other ventures with  significant  long-life
hydrocarbon resource potential.

Western's 20 per cent ownership interest in the AOSP gives Western the option,
upon satisfying certain  provisions of the Joint Venture Agreement,  to earn a
working interest in additional  leases in the Athabasca region of Alberta that
Shell  or  Chevron  may  purchase.  Western  may  also  make  certain  of  its

<PAGE>
                                     -39-


investments  involved in the  exploration  and  development  of new sources of
hydrocarbon resource in domestic or international  jurisdictions.  Investments
in international  jurisdictions have various inherent risks, including but not
limited to  political,  economical,  legal,  regulatory  and foreign  exchange
risks. The exploration and development of new sources of hydrocarbon  resource
can have various  inherent  risks,  including but not limited to  encountering
unexpected   formations   or   pressures,   blow-outs,   equipment   failures,
uncontrollable   flows  of  oil,  natural  gas  or  well  fluid,  and  various
environmental  risks.  Western will assess and mitigate to the extent possible
these inherent risks of international  jurisdictions and the inherent risks of
exploration and development as these investments are evaluated and pursued.

Western will also compete in the highly  competitive  energy  industry for any
downstream initiatives it pursues,  including the acquisition of upgrading and
refining  capacity for heavy crude oil. There can be no assurance that Western
will be able to secure such  opportunities  and,  if secured,  will be able to
finance the complete such opportunities.

INVESTMENTS  IN BUSINESS  DEVELOPMENT  ACTIVITIES  UNRELATED  TO THE OIL SANDS
INDUSTRY

Western has previously  announced its business strategy of  investigating,  at
any one time,  several  separate  projects which could  significantly  enhance
shareholder  value.  These  projects may be domiciled  outside  Canada.  These
potential investments may involve such risks as uncertain political, economic,
legal,  regulatory and tax  environments.  They may also include,  among other
things, currency restrictions and exchange rate fluctuations,  risk of loss of
revenue,  property and equipment as a result of hazards such as expropriation,
nationalization,  war,  insurrection  and  other  political  risks,  risks  of
increases in taxes and governmental royalties, renegotiation of contracts with
governmental  entities and  quasi-governmental  agencies,  changes in laws and
policies   governing   operations   of   foreign-based   companies  and  other
uncertainties arising out of foreign government sovereignty over an investment
that Western may make abroad.

                         TRANSFER AGENTS AND REGISTRAR

Valiant  Trust  Company at its  principal  office in  Calgary,  Alberta is the
transfer agent and registrar of the Common Shares of the  Corporation  and BNY
Trust  Company of Canada at its  principal  office in Toronto,  Ontario is the
co-agent and registrar of the Common Shares of the Corporation.

                              INTEREST OF EXPERTS

Norwest  Corporation,  independent  mining  consultants  to  the  Corporation,
prepared the Norwest Report and GLJ Petroleum  Consultants  Ltd.,  independent
petroleum  consultants  to the  Corporation,  prepared  the GLJ  Report,  both
referenced herein. As at the date of the respective reports, the principals of
each of Norwest and GLJ, as respective groups, owned beneficially, directly or
indirectly, less than 1% of the outstanding Common Shares. Neither Norwest nor
GLJ  received  or will  receive  any  interest,  direct  or  indirect,  in any
securities or other property of Western or its  affiliates in connection  with
the preparation of its report.

<PAGE>
                                     -40-


                               LEGAL PROCEEDINGS

There are no legal  proceedings  which  Western  is a party to that  involve a
claim for damages  that exceed ten per cent of the current  assets of Western.
Western is however involved in arbitration  proceedings arising from insurance
claims. See "Narrative Description of the Business - Insurance".

                            ADDITIONAL INFORMATION

Additional  information  relating to the  Corporation may be found on SEDAR at
www.sedar.com.
-------------

Additional information including directors' and officers' remuneration and
indebtedness, principal holders of the Corporation's securities and securities
authorized for issuance under equity compensation plans, if applicable, is
contained in the Corporation's information circular for its most recent annual
meeting of shareholders that involved the election of directors, and additional
financial information is provided in the Corporation's comparative financial
statements and MD&A for its most recently completed financial year.



<PAGE>
                                     -41-


                                   GLOSSARY

IN THIS ANNUAL  INFORMATION  FORM, THE FOLLOWING TERMS SHALL HAVE THE MEANINGS
SET FORTH BELOW, UNLESS OTHERWISE INDICATED:

"ALBIAN"  Albian  Sands  Energy  Inc.,  a  corporation  owned by the Owners in
proportion  to  their  ownership  interest,  which  was  incorporated  for the
purposes of acting as the operator of the Mine and the Extraction Plant;

"AOSP"  or the  "PROJECT"  The  design  and  construction  of  facilities  and
implementation  of operations of the Mine, the Extraction  Plant, the Upgrader
and all other  facilities  necessary to mine,  extract,  transport and upgrade
crude bitumen from the oil sands deposits on the western portion of Lease 13;

"ATCO"  ATCO Power Canada Limited;

"BBLS"  Barrels.  One barrel equals 0.15891 cubic metres at 15(0) Celsius;

"CHEVRON"  Chevron Canada Limited;

"COMMON SHARES"  The Class A shares of Western;

"DISCOVERED  RESOURCES"  Are those  quantities  of oil and gas  estimated on a
given date to be remaining in, plus those  quantities  already  produced from,
known  accumulations.  Discovered  resources  are divided  into  economic  and
uneconomic   categories,   with  the  estimated  future  recoverable   portion
classified  as  reserves  and  contingent  resources,  respectively.  (Source:
Canadian Oil and Gas Evaluation Handbook, Volume 1, Section 5.2.2)

"DOW" Dow Chemicals Canada Inc.;

"EXECUTIVE  COMMITTEE"  The  executive  committee  appointed  under  the Joint
Venture  Agreement which has the  responsibility  for managing the Project and
which is comprised of two representatives of each of the Owners;

"EXTRACTION  PLANT" The  extraction  facilities  are  located  on the  western
portion of Lease 13 which are designed to separate  crude bitumen from the oil
sands and process such crude bitumen so that it may be transported by pipeline
to the Scotford Upgrader;

"EXTRACTION  PLANT START-UP" That time when the Extraction  Plant has operated
at not less than 85% of its  design  capacity  for a period of 30  consecutive
days and any construction  deficiencies and defects have been rectified to the
satisfaction of the Owners;

"GLJ" GLJ Petroleum Consultants Ltd., independent petroleum consultants;

"GLJ REPORT" The report prepared by GLJ dated February 13, 2006 evaluating the
reserves attributable to Western as of December 31, 2005;

"HMU" The hydrogen manufacturing unit which supplies hydrogen to the Upgrader;

"JACKPINE MINE" The first planned  expansion area to be developed by the Joint
Venture physically located on the east side of the Muskeg River;

<PAGE>
                                     -42-


"JOINT  VENTURE"  The  unincorporated  joint  venture  created  by the  Owners
pursuant to the Joint Venture Agreement to undertake the Project;

"JOINT VENTURE  AGREEMENT" or "JVA" The Joint Venture Agreement dated December
6, 1999, among the Owners, as amended;

"LEASE 13" Bituminous Sands Lease No. 7277080T13 and all renewals, extensions,
replacements  and  amendments  thereto,  granted to Shell by the Government of
Alberta,  and  transferred to Albian Sands Energy Inc., the western portion of
which is the site for the mining and extraction operations of the Project;

"MD&A"  Management Discussion & Analysis;

"MM$"  Millions of dollars and "M$" thousands of dollars;

"MMBBLS"  Millions of barrels;

"MINE" The open pit mine  located on the  western  portion of Lease 13 and all
equipment, machinery, vehicles and facilities used in connection therewith;

"NON-VOTING  CONVERTIBLE  EQUITY  SHARES" The non-voting  convertible  Class B
equity  shares of Western  each  convertible  into one Common Share in certain
circumstances subject to adjustment, at no additional cost;

"NORWEST"  Norwest Corporation, independent mining consultants;

"NORWEST  REPORT"  The  report  prepared  by  Norwest  dated  March 15,  2006,
effective as of December 31, 2005, that considered  available drilling data on
Leases 13(east), 88, 89, 90, 9 and 17;

"NOTES"  Western's  senior  secured notes having a principal  amount of US$450
Million bearing  interest at a rate of 8.375% per annum and maturing on May 1,
2012;

"OWNERS" The owners of  undivided  ownership  interests  in the Project  which
include Shell, as to a 60% undivided ownership interest,  Chevron, as to a 20%
undivided  ownership  interest,  and Western,  as to a 20% undivided ownership
interest;

"PROJECT START-UP" That time when the main Project facilities have operated at
not less than 85% of their design capacity for a period of 30 consecutive days
and any  construction  deficiencies  and defects  have been  rectified  to the
satisfaction of the Owners;

"SCOTFORD  REFINERY" The oil refinery owned by Shell  Products  Canada Limited
which is located near Fort Saskatchewan,  Alberta and which is adjacent to the
location of the Scotford Upgrader;

"SCOTFORD  UPGRADER"  or  "UPGRADER"  The oil  sands  bitumen  upgrader  which
processes  diluted  bitumen  product  from the  Extraction  Plant  to  produce
refinery feed stocks for sale to Shell Products Canada Limited at the Scotford
Refinery  and  synthetic  crude  oil for  shipment  to  other  North  American
refineries;

"SENIOR  CREDIT  FACILITY" The credit  facility  between the  Corporation  and
certain lending institutions which, prior to repayment,  provided a portion of
the capital costs of the Project and which facility also included debt service
and cost overrun facilities;

"SHELL"  Shell Canada Limited; and

<PAGE>
                                     -43-


"SHELL'S  OTHER   ATHABASCA   LEASES"  Alberta  Crown  Oil  Sands  Lease  Nos.
7288080T88,   7288080T89,   7288080T90,  7280050T26,  7281010T93,  7281030T53,
7281030T45,   7280080T28,   7400120009,  7401100017,  7405080351,  7405080352,
74058090631,  7405090632, 7405120015, 7405120309, 7405120310 and all renewals,
extensions,  replacements and amendments in respect of same,  granted to Shell
by the Government of Alberta.



<PAGE>


                                  APPENDIX A

                            REPORT ON RESERVES DATA
                                      BY
                        INDEPENDENT QUALIFIED RESERVES
                             EVALUATOR OR AUDITOR


To the board of directors of Western Oil Sands Inc. (the "Corporation"):

1.   We have prepared an evaluation of the  Corporation's  reserves data as at
     December 31, 2005. The reserves data consist of the following:

     (a)   (i)     proved and proved plus probable oil and gas
                   reserves estimated as at December 31, 2005, using
                   forecast prices and costs; and

           (ii)    the related estimated future net revenue; and

     (b)   (i)     proved oil and gas reserves estimated as at
                   December 31, 2005, using constant prices and costs;
                   and

           (ii)    the related estimated future net revenue.

2.   The reserves data are the responsibility of the Corporation's management.
     Our responsibility is to express an opinion on the reserves data based on
     our evaluation.

     We carried out our evaluation in accordance with standards set out in the
     Canadian Oil and Gas Evaluation  Handbook (the "COGE Handbook")  prepared
     jointly  by  the  Society  of  Petroleum  Evaluation  Engineers  (Calgary
     Chapter)  and the Canadian  Institute  of Mining,  Metallurgy & Petroleum
     (Petroleum Society).

3.   Those standards  require that we plan and perform an evaluation to obtain
     reasonable assurance as to whether the reserves data are free of material
     misstatement.  An evaluation also includes assessing whether the reserves
     data  are in  accordance  with  principles  and  definitions  in the COGE
     Handbook.

4.   The following  table sets forth the estimated  future net revenue (before
     deduction of income taxes)  attributed to proved plus probable  reserves,
     estimated using forecast prices and costs and calculated using a discount
     rate of 10 percent,  included  in the  reserves  data of the  Corporation
     evaluated by us for the year ended  December 31, 2005, and identifies the
     respective portions thereof that we have audited,  evaluated and reviewed
     and reported on to the Corporation's board of directors:



<PAGE>


<TABLE>
<CAPTION>
                        LOCATION OF
                         RESERVES
    DESCRIPTION AND     (COUNTRY OR       NET PRESENT VALUE OF FUTURE NET REVENUE
  PREPARATION DATE OF     FOREIGN        (BEFORE  INCOME TAXES, 10% DISCOUNT RATE)
       EVALUATION       GEOGRAPHIC   -------------------------------------------------
         REPORT            AREA)     AUDITED       EVALUATED    REVIEWED       TOTAL
         ------            -----     -------       ---------    --------       -----
     <S>                  <C>        <C>           <C>          <C>         <C>
     Feb 13, 2006         Canada        0          2,685 MM$       0        2,685 MM$
</TABLE>

5.   In our opinion,  the reserves data respectively  evaluated by us have, in
     all material  respects,  been  determined and are in accordance  with the
     COGE Handbook.

<PAGE>
                                     -2-


6.   We have  no  responsibility  to  update  the  evaluation  referred  to in
     paragraph 4 for events and circumstances  occurring after the preparation
     dates.

7.   Because  the  reserves  data are  based on  judgements  regarding  future
     events, actual results will vary and the variations may be material.

<TABLE>
<CAPTION>
Executed as to our report referred to above:

<S>                                                            <C>
GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada       Dated: February 13, 2006
</TABLE>


ORIGINALLY SIGNED BY
--------------------

James H. Willmon, P. Eng.
Vice-President


<PAGE>


                                  APPENDIX B

   REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Western Oil Sands Inc. (the  "Corporation")  are responsible for
the   preparation   and  disclosure  of   information   with  respect  to  the
Corporation's oil and gas activities in accordance with securities  regulatory
requirements.  This information  includes  reserves data, which consist of the
following:

     (a)   (i)     proved  and  proved  plus  probable  oil and  gas  reserves
                   estimated as at December 31, 2005 using forecast prices and
                   costs; and

           (ii)    the related estimated future net revenue; and

     (b)   (i)     proved oil and gas  reserves  estimated  as at December 31,
                   2005 using constant prices and costs; and

           (ii)    the related estimated future net revenue.

An independent  qualified  reserves  evaluator has evaluated the Corporation's
reserves data. The report of the independent  qualified  reserves evaluator is
presented in Appendix A to this Annual Information Form.

The  Reserves  and  Business  Risk  Committee of the Board of Directors of the
Corporation has:

     (a)   reviewed the Corporation's procedures for providing
           information to the independent qualified reserves evaluator;

     (b)   met with the independent qualified reserves evaluator to
           determine whether any restrictions affected the ability of the
           independent qualified reserves evaluator to report without
           reservation; and

     (c)   reviewed the reserves data with management and the independent
           qualified reserves evaluator.

The  Reserves  and  Business  Risk  Committee  of the Board of  Directors  has
reviewed the  Corporation's  procedures  for  assembling  and reporting  other
information  associated  with oil and gas  activities  and has  reviewed  that
information with management. The Board of Directors has, on the recommendation
of the Reserves and Business Risk Committee, approved:

     (a)   the content and filing with securities regulatory authorities
           of the reserves data and other oil and gas information;

     (b)   the filing of the report of the independent qualified reserves
           evaluator on the reserves data; and

     (c)   the content and filing of this report.

<PAGE>
                                     -2-


Because the reserves data are based on  judgements  regarding  future  events,
actual results will vary and the variations may be material.

(signed) James C. Houck, President and Chief Executive Officer

(signed) Steve Reynish, Executive Vice President and Chief Operating Officer

(signed) Randall Oliphant, Director

(signed) David J. Boone, Director

(signed) Geoff Cumming, Lead Director

March 28, 2006





<PAGE>
                                     -3-


                                  APPENDIX C

                            AUDIT COMMITTEE CHARTER


PURPOSE

The  purpose  of the Audit  Committee  of the Board is to assist  the Board in
fulfilling  its  oversight  responsibilities  in  relation  to the  review and
approval  of  the  financial   statements  and  financial   reporting  of  the
Corporation and the assessment of internal control and management  information
of the Corporation. The Audit Committee shall also be directly responsible for
overseeing all audit processes and the  relationship of the external  auditors
with the Corporation and the external  auditors shall report directly,  and be
accountable, to the Audit Committee.

The  role  of the  Audit  Committee  is one of  supervision,  stewardship  and
oversight.  Management is responsible  for preparing the financial  statements
and  financial  reporting  of the  Corporation  and for  maintaining  internal
control and management information.  The external auditors are responsible for
the audit or review  of the  financial  statements  and  other  services  they
provide.

MANDATE


1.   FINANCIAL STATEMENTS AND FINANCIAL REPORTING.

     The Audit Committee shall:

     (a)   review with management and the external auditors,  and recommend to
           the Board for  approval,  the annual  financial  statements  of the
           Corporation,  the  reports of the  external  auditors  thereon  and
           related financial reporting,  including Management's Discussion and
           Analysis and earnings press releases prior to the public disclosure
           of such information;

     (b)   review with management and the external auditors,  and recommend to
           the Board for  approval,  the interim  financial  statements of the
           Corporation and related financial reporting, including Management's
           Discussion  and Analysis and earnings  press  releases prior to the
           public disclosure of such information;

     (c)   review with management and recommend to the Board for approval, the
           Corporation's Annual Information Form;

     (d)   review with management and recommend to the Board for approval, any
           financial  statements of the Corporation  which have not previously
           been  approved  by the  Board and  which  are to be  included  in a
           prospectus of the Corporation;

     (e)   consider and be satisfied that adequate procedures are in place for
           the review of the  Corporation's  public  disclosure  of  financial
           information  extracted or derived from the Corporation's  financial
           statements  (other than  disclosure  referred to in clauses (a) and
           (b)  above),   and   periodically   assess  the  adequacy  of  such
           procedures;

     (f)   review with  management,  the external  auditors and, if necessary,
           legal counsel, any litigation, claim or contingency,  including tax
           assessments,  that could have a material  effect upon the financial
           position of the Corporation,  and the manner in which these matters
           may be, or have been, disclosed in the financial statements;

<PAGE>
                                     -4-


     (g)   review the appropriateness of the accounting practices and policies
           of the Corporation and review any proposed changes thereto;

     (h)   review and discuss any new or pending  developments  in  accounting
           and reporting standards that may affect the Corporation; and

     (i)   review  accounting,  tax and financial aspects of the operations of
           the Corporation as the Audit Committee considers appropriate.

2.   RELATIONSHIP WITH EXTERNAL AUDITORS.

     The Audit Committee shall:

     (a)   consider  and  make  a  recommendation  to  the  Board  as  to  the
           appointment or  re-appointment of the external  auditors,  ensuring
           that such auditors are  participants  in good standing  pursuant to
           applicable securities laws;

     (b)   consider  and  make  a  recommendation  to  the  Board  as  to  the
           compensation of the external auditors;

     (c)   review and approve the annual audit plan of the  external  auditors
           (including without limitation,  engagement letters,  objectives and
           scope of the external audit word,  procedures for quarterly  review
           of financial  statements,  materiality limits, areas of audit risk,
           staffing, timetables and proposed fees);

     (d)   oversee the work of the external auditors in performing their audit
           or review services and oversee the resolution of any  disagreements
           between management and the external auditors;

     (e)   review and  discuss  with the  external  auditors  all  significant
           relationships  that the external auditors and their affiliates have
           with the  Corporation  and its affiliates in order to determine the
           external auditors' independence, including, without limitation, (A)
           requesting,  receiving and reviewing, on a periodic basis, a formal
           written  statement  from  the  external  auditors  delineating  all
           relationships  that  may  reasonably  be  thought  to  bear  on the
           independence   of  the  external   auditors  with  respect  to  the
           Corporation,   (B)  discussing  with  the  external   auditors  any
           disclosed  relationships  or services  that the  external  auditors
           believe may affect the objectivity and independence of the external
           auditors,  and (C)  recommending  that the Board  take  appropriate
           action in  response  to the  external  auditors'  report to satisfy
           itself of the external auditors' independence;

     (f)   as may  be  required  by  applicable  securities  laws,  rules  and
           guidelines, either:

           (i)     pre-approve  all  non-audit  services to be provided by the
                   external  auditors to the Corporation (or its subsidiaries,
                   if any), or, in the case of DE MINIMUS non-audit  services,
                   approve such non-audit  services prior to the completion of
                   the audit; or

           (ii)    adopt  specific  policies and procedures for the engagement
                   of the external  auditors for the purpose of the  provision
                   of non-audit services;

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                                     -5-


     (g)   be satisfied that the fees paid by the  Corporation to the external
           auditors for audit and non-audit  services are publicly  disclosed;
           and

     (h)   review and approve the hiring policies of the Corporation regarding
           partners,  former  partners,  employees and former employees of the
           present and former external auditors of the Corporation.

3.   INTERNAL CONTROLS.

     The Audit Committee shall:

     (a)   review with management and the external auditors,  the adequacy and
           effectiveness  of the internal  control and management  information
           systems  and  procedures  of  the  Corporation   (with   particular
           attention given to accounting,  financial  statements and financial
           reporting  matters  and to being  satisfied  that such  systems are
           reliable and that they  operate  effectively  to produce  accurate,
           appropriate and timely  management and financial  information)  and
           determine  whether the Corporation is in compliance with applicable
           legal  and  regulatory  requirements  and  with  the  Corporation's
           policies;

     (b)   provide  the Board  with an  independent  mechanism  for  reviewing
           reserves;

     (c)   review  the  external  auditors'   recommendations   regarding  any
           matters,  including  internal  control and  management  information
           systems and procedures, and management's responses thereto;

     (d)   establish  procedures  for the receipt,  retention and treatment of
           complaints, submissions and concerns regarding accounting, internal
           accounting  controls  or  auditing  matters  on  an  anonymous  and
           confidential basis;

     (e)   review   policies  and  practices   concerning   the  expenses  and
           perquisites of the Chairman, including the use of the assets of the
           Corporation;

     (f)   review with external  auditors any corporate  transactions in which
           directors or officers of the Corporation have a personal interest;

     (g)   review  insurance  coverage  of  significant   business  risks  and
           uncertainties;

     (h)   review material  litigation and its impact on financial  reporting;
           and

     (i)   review  policies  and  procedures  for the review and  approval  of
           officers' expenses and perquisites.

     COMPOSITION AND PROCEDURES

1.   COMPOSITION OF COMMITTEE.

     The Audit Committee shall consist of not less than three directors,  none
     of whom shall be an officer or employee of the  Corporation or any of its
     subsidiaries or any affiliate thereof.  Each Audit Committee member shall
     satisfy  the   independence  and  financial   literacy   requirements  of
     applicable  securities  laws,  rules or guidelines,  any applicable stock
     exchange  requirements or guidelines and any other applicable  regulatory
     rules. In addition, the Chair shall have "accounting

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                                     -6-


     or  related  financial  expertise".  The  Board  has  defined  "financial
     literacy" as the ability to understand a balance sheet,  income statement
     and a cash flow statement in accordance  with Canadian GAAP and the Board
     has defined "accounting or financial expertise" as the ability to analyze
     and  understand a full set of financial  statements,  including the notes
     attached  thereto in accordance  with Canadian  GAAP.  Each member of the
     Audit  Committee shall have no direct or indirect  material  relationship
     with the Corporation or any affiliate  thereof which could  reasonably be
     expected  to  interfere  with the  exercise of the  member's  independent
     judgment,  other  than  interests  and  relationships  arising  from  the
     holdings  of shares of the  Corporation.  Determinations  as to whether a
     particular  director  satisfies the  requirements  for  membership on the
     Audit Committee shall be made by the full Board.

2.   APPOINTMENT OF COMMITTEE MEMBERS

     Members of the Audit  Committee  shall be appointed from time to time and
     shall hold office at the pleasure of the Board. Where a vacancy occurs at
     any time in the  membership of the Audit  Committee,  it may be filled by
     the Board.  The Board  shall fill any  vacancy if the  membership  of the
     Audit Committee is less than three directors.

3.   ABSENCE OF COMMITTEE CHAIR

     If the Chair of the Audit  Committee is not present at any meeting of the
     Audit  Committee,  one of the other members of the Audit Committee who is
     present at the meeting shall be chosen by the Audit  Committee to preside
     at the meeting.

4.   AUTHORITY TO ENGAGE EXPERTS

     The Audit Committee has the authority to engage  independent  counsel and
     other advisors as it determines  necessary to carry out its duties and to
     set the compensation  for any such counsel and advisors,  such engagement
     to be at the Corporation's expense.

5.   MEETINGS

     The Audit  Committee  shall  meet at least  four times per year and shall
     meet at such other  times  during each year as it deems  appropriate.  In
     addition,  the Chair of the Audit Committee may call a special meeting of
     the Audit  Committee at any time. The Audit Committee shall meet with the
     external auditors on a regular basis in the absence of management and, if
     so requested  by a member of the Audit  Committee,  the external  auditor
     shall attend every meeting of the Audit Committee held during the term of
     office of the external  auditor.  The Chair of the Audit  Committee,  the
     Chairman  of the Board,  any two  members of the Audit  Committee  or the
     external auditors may call a meeting of the Audit Committee. The external
     auditors  shall be  provided  with  notice of every  meeting of the Audit
     Committee  and, at the expense of the  Corporation,  shall be entitled to
     attend and be heard thereat.  The Chair of the Audit Committee shall hold
     IN CAMERA meetings of the Audit Committee, without management present, at
     every Audit Committee meeting.

6.   QUORUM

     A majority  of the  members of the Audit  Committee  shall  constitute  a
     quorum.

7.   PROCEDURE, RECORDS AND REPORTING


<PAGE>
                                     -7-


     Subject to any statute or the  articles  and by-laws of the  Corporation,
     the  Audit  Committee  shall fix its own  procedures  at  meetings,  keep
     records  of its  proceedings  and  report  to the  Board  when the  Audit
     Committee  may deem  appropriate  (but not later than the next meeting of
     the Board).

8.   DELEGATION

     The Audit  Committee  may  delegate  from  time to time to any  person or
     committee of persons any of the Audit Committee's  responsibilities  that
     lawfully may be delegated.

9.   REVIEW OF TERMS OF REFERENCE

     The Audit  Committee  shall review and reassess the adequacy of its Terms
     of Reference at least  annually,  and otherwise as it deems  appropriate,
     and  recommend  changes to the  Board.  Such  review  shall  include  the
     evaluation of the  performance of the Audit  Committee  against  criteria
     defined in the Audit Committee mandate as well as the Directors' Charter.