EXHIBIT 1
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                          [LOGO - WESTERN OIL SANDS]






                            ANNUAL INFORMATION FORM

                      FOR THE YEAR ENDED DECEMBER 31, 2006





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                               TABLE OF CONTENTS

                                                                           PAGE


INTRODUCTORY INFORMATION......................................................1
FORWARD LOOKING INFORMATION...................................................1
CORPORATE STRUCTURE...........................................................3
GENERAL DEVELOPMENT OF THE BUSINESS...........................................4
NARRATIVE DESCRIPTION OF THE BUSINESS.........................................5
      THE ATHABASCA OIL SANDS PROJECT.........................................5
               MINING - BASE OPERATIONS.......................................5
                        OPERATING ACTIVITIES..................................6
                        FINANCING ACTIVITIES..................................8
                        PRODUCTION HISTORY....................................9
                        PRODUCTION ESTIMATES..................................9
               EXPANSION 1....................................................9
               EXPANSIONS 2 AND 3............................................10
               EXPANSIONS 4 AND 5............................................10
               REGULATORY APPROVALS..........................................11
               RESERVES, RESOURCES AND LAND POSITION.........................12
                        RESERVES.............................................12
                        UNDEVELOPED RESERVES.................................17
                        COSTS INCURRED.......................................17
                        ABANDONMENT AND RECLAMATION COSTS....................18
                        SIGNIFICANT FACTORS OR UNCERTAINTIES ON
                        RESERVES DATA........................................18
                        LAND TENURE..........................................18
                        RESOURCES............................................19
                        LAND POSITION........................................20
      IN-SITU PROJECTS.......................................................22
               WESTERN IN-SITU PROJECT.......................................22
               ELLS RIVER PROJECT............................................22
      DOWNSTREAM.............................................................22
               THIRD PARTY FACILITIES........................................22
               MARKETING AND SALES...........................................23
      KURDISTAN EXPLORATION PROJECT..........................................23
GENERAL CORPORATE INFORMATION................................................23
               ROYALTIES.....................................................23
               ENVIRONMENTAL CONSIDERATIONS..................................23
               INSURANCE.....................................................24
               RISK MANAGEMENT ACTIVITY......................................25
               TAX HORIZON...................................................25
               EMPLOYEES.....................................................25
DIVIDEND POLICY..............................................................26
DESCRIPTION OF SHARE CAPITAL.................................................26
               COMMON SHARES.................................................26
               NON-VOTING CONVERTIBLE EQUITY SHARES..........................26
               CLASS C SHARES................................................27
               CLASS D SHARES................................................27
MARKET FOR SECURITIES........................................................28
CREDIT RATINGS...............................................................28
DIRECTORS AND EXECUTIVE OFFICERS.............................................29
AUDIT COMMITTEE..............................................................32
      COMPOSITION AND QUALIFICATIONS.........................................32
      RESPONSIBILITIES AND TERMS OF REFERENCE................................33
      AUDITOR SERVICE FEES...................................................34
RISKS AND UNCERTAINTIES......................................................35
TRANSFER AGENTS AND REGISTRAR................................................49
INTEREST OF EXPERTS..........................................................49
LEGAL PROCEEDINGS............................................................49
ADDITIONAL INFORMATION.......................................................49
GLOSSARY ....................................................................50

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",  the  "Company"  or the  "Corporation")  includes  Western  and its
material  wholly-owned  subsidiaries,  852006  Alberta Ltd.,  Western Oil Sands
L.P., Western Oil Development Inc., Western Oil International  Holdings Limited
and  WesternZagros  Limited 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,   proposed   expansions  and   strategies.
Forward-looking  information  typically contains  statements with words such as
"anticipate",  "could",  "estimate",  "expect",  "intend" "plan",  "potential",
"project" or similar words suggesting  future outcomes.  We caution readers and
prospective  investors  of the  Corporation's  securities  not to  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 are
described more fully under "Risks and Uncertainties"  and include,  but are not
limited to,  risks of  commodity  prices in the  marketplace  for crude oil and
natural gas; risks  associated with the extraction,  treatment and upgrading of
mineable  oil  sands  deposits;  risks  associated  with the  size,  scope  and
execution  of  expansions;  risks  surrounding  the level and timing of capital
expenditures required to fulfill Western's growth strategy;  risks of financing
these growth  initiatives at  commercially  attractive  levels;  risks of being
unable to participate in expansions and corresponding  loss of voting rights in
the  AOSP;  risks  relating  to the  execution  of the  Project's  optimization
strategy;  risks involving the uncertainty of estimates involved in the reserve
and   resource   estimation   process  and  ore  body   configuration/geometry,
uncertainty in the assessment of asset retirement  obligations,  uncertainty in
the estimation of future income taxes,  and uncertainty in treatment of capital
for royalty  purposes;  risks  associated with  identifying and  implementing a
downstream  solution for upgrading  future bitumen volumes,  risks  surrounding
health,  safety  and  environmental  matters;  risk of  foreign  exchange  rate
fluctuations;  risks and  uncertainties  associated with securing the necessary
regulatory  approvals  for  expansion  initiatives;   risks  surrounding  major
interruptions in operational performance together with any associated insurance
proceedings  thereto;  and risks associated with  identifying,  negotiating and
completing our other business development activities, both those that relate to
oil sands  activities  and those that do not,  either  domestically  or abroad.
Risks  associated  with  our  international  initiatives  include,  but are not
limited to,  political  and economic  conditions  in the  countries in which we
operate or intend to  operate,  risks  associated  with acts of  insurgency  or
terrorism, changes in market conditions,  political risks, including changes in
law or government  policy,  the risks  associated with negotiating with foreign
governments (including ratification of the EPSA) and risks generally associated
with  international  activity.  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

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                                      -2-


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".



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                                      -3-


                             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, respectively. 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 owns Western Oil Sands LP which holds a 20%
undivided  interest in the Project),  Western Oil Development Inc., Western Oil
International Holdings Limited and WesternZagros Limited, as shown below:

                            [GRAPHIC OMITTED]

                         ________________________
                        |                        |
           -------------| Western Oils Sands Inc.|--------------
           |            |       (Alberta)        |               |
   100%    |            |________________________|               |        100%
 ____________________          /                   ____________________________
| 852006 Alberta Ltd.|        /    General         |        Western Oil        |
|     (Alberta)      |       /     Partner         |     Development Inc.      |
|____________________       /                      |         (Alberta)         |
           |               /                       |___________________________
   99% Limited            /                                    |
   Partnership           /                                     |
         Units          /    1% Limited                        |        100%
  _______________________   Partnership            ____________________________
 | Western Oil Sands L.P.|        Units            | Western Oil International |
 |       (Alberta)       |                         |      Holdings Limited     |
 |_______________________|                         |         (Cyprus)          |
           |                                       |___________________________
           |                                                   |
           |                                                   |
     20%   |                                                   |        100%
         /  \                                      ____________________________
        /    \                                     |   WesternZagros Limited   |
       /      \                                    |         (Cyprus)          |
      /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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                                      -4-


                      GENERAL DEVELOPMENT OF THE BUSINESS

Western is a Canadian corporation formed under the laws of Alberta whose vision
is to create shareholder value through the opportunity  capture and development
of large, world class hydrocarbon resources.  Western's primary asset is its 20
percent  undivided  interest  in the  Project.  Shell and Chevron are the other
Joint  Venture  Owners,   holding  a  60  percent  and  20  percent   interest,
respectively.  The Owners entered into the Joint Venture  Agreement in December
of  1999,  which  together  with  other  ancillary   agreements,   governs  the
relationships between the Owners. The base Project, located on the west side of
Lease 13, began  operations  in June 2003 and current  production  at the Joint
Venture level exceeds design rate capacity of 155,000 barrels per day.

In October  2006,  Western  announced its  participation  in Expansion 1 of the
AOSP.  Expansion 1 is a 100,000  barrel per day (20,000  barrels per day net to
Western) fully integrated expansion of the existing AOSP facilities,  with both
new oil sands  mining  operations  on Lease BT 31 and the east side of Lease 13
and associated  additional bitumen upgrading at the Scotford Upgrader.  It also
includes the construction of common upstream  infrastructure that will be sized
to support future mining  expansions.  The AOSP Joint Venture has also recently
announced its intention to file  applications  with the  applicable  government
authorities  that would  increase  permitted  upstream  productive  capacity to
770,000  barrels  (154,000  barrels net to  Western).  At this level,  multiple
mining expansions of the AOSP would be possible.

Western  continues to pursue downstream  integration  opportunities to maximize
value from its growing oil sands  resources and undeveloped  acreage  position.
Related  to  these   initiatives,   Western   intends  to  explore  and  pursue
alternatives  that will realize the full value of our assets and future  growth
potential. This may result in an acquisition or sale of assets, merger or other
corporate  transaction.   Western's  advisors,  Goldman,  Sachs  &  Co  and  TD
Securities  Inc.,  will be  assisting  in these  activities  which will involve
contacting third parties.  The Board of Directors has sanctioned a committee of
independent  directors to provide  oversight to  management  and the  Company's
financial advisors for these activities. There can be no assurances that any of
these activities will result in the consummation of an agreement or transaction
or result in any change to Western's current ongoing business strategy.

Western  is  also  pursuing  initiatives  related  to  in-situ  and  technology
development. This includes Western's participation in the Chevron-operated Ells
River  Project  in the  Athabasca  region in which  Western  holds a 20 percent
interest. Chevron is planning an evaluation program for the winter of 2007, the
results of which will influence the future  development  strategy and timeline.
In 2005 and 2006,  Western  acquired  three leases with  potential  for in-situ
development.  Early stage  planning  for these  in-situ  leases is underway and
includes an evaluation  drilling  program of  approximately 19 wells during the
2006/2007 winter drilling season.

In  addition  to these three focus  areas,  Western,  through its  wholly-owned
subsidiary,  WesternZagros  Limited  ("WesternZagros"),  negotiated the initial
form of an EPSA with the  Kurdistan  Regional  Government  ("KRG"),  subject to
finalization  of key terms and  ratification by the KRG to comply with expected
federal  petroleum  legislation.  The  EPSA  provided  for the  exploration  of
conventional  oil and gas in the Federal  Region of Kurdistan in northern Iraq.
WesternZagros  continues to work towards  ratification  of an EPSA with the KRG
which is expected to include the  finalization  of terms including its contract
area and the corresponding work program commitments.


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                                      -5-


                     NARRATIVE DESCRIPTION OF THE BUSINESS

Western is a Canadian corporation formed under the laws of Alberta that holds a
20 percent  undivided  ownership  interest in the Joint  Venture to exploit the
recoverable  bitumen  resources found in certain oil sands deposits  located in
the Athabasca  region including at the Muskeg River Mine. The Muskeg River Mine
is  Western's  only  producing  asset at this time.  Shell and Chevron hold the
remaining   60  percent   and  20  percent   undivided   ownership   interests,
respectively.   The  Muskeg   River  Mine  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.

The Joint  Venture's  asset base has grown rapidly as all Joint Venture  Owners
were active in 2005 and 2006 in acquiring  additional  acreage in the Athabasca
region which may be suitable for bitumen recovery either through surface mining
or in-situ recovery  techniques.  In 2006, the Joint Venture Owners  sanctioned
Expansion 1, the first mining  expansion of AOSP on portions of Lease BT 31 and
the east side of Lease 13. Early stage  assessments are underway for subsequent
mining expansions of the AOSP on other leases in which Western has the right to
participate.  Moreover, early drilling is being conducted on leases acquired by
both Western and Chevron which may be conducive for in-situ development.

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 improve  product mix; and  identification  and evaluation of
opportunities  in resource  development  of oil sands and other  ventures  with
significant long-life hydrocarbon resource potential.


THE ATHABASCA OIL SANDS PROJECT


MINING - BASE OPERATIONS

Construction  of the existing  operating  Mine and  Upgrader  was  completed in
December  2002, at a total capital cost of $5.7 billion  ($1.14  billion net to
Western).  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). Increasing reliability and availability of the
Extraction  Plant and Upgrader  was a focus  during  2005,  resulting in annual
production of  approximately  160,000  barrels per day for 2005 (32,000 barrels
per day net to  Western).  During the summer of 2006,  the first major  planned
turnaround of the Mine and Upgrader was completed. Production subsequent to the
full  turnaround has met or exceeded  rates leading up to the  turnaround  with
production in the fourth quarter of 2006 of  approximately  177,600 barrels per
day (35,520 barrels per day net to Western).

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 300,000 tonnes per day of
ore, in addition to  approximately  150,000 tonnes per day of  overburden,  low
grade  (waste) oil sand and  Extraction  Plant rejects are mined from the Mine.
Approximately  165,000 to 170,000  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.  Western  takes
in-kind its pro rata share of the various crude oil streams  processed  through
the Upgrader and markets these products  independent of the other Joint Venture

<PAGE>
                                      -6-


Owners.  Currently,  all of Western's  net revenues are derived from  petroleum
products produced from the Project.

The current operating 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;

      o    at the  Upgrader,  the bitumen  feedstock  is  distilled  to recover
           diluent,   and  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.  Vacuum gas oil is sold to
           Shell Canada's 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.


OPERATING ACTIVITIES

As of February  2007,  the Project has been in commercial  operation for almost
four years. The maturation of the Project has proceeded  without major incident
but for the fire  that  occurred  at the Mine on  January  6, 2003  during  the
start-up and commissioning.  Repairs were completed and start-up recommenced on
April 4, 2003 with the Project  achieving fully integrated  operations  between
the Mine and the Scotford Upgrader on April 19, 2003. This incident resulted in
the  submission of insurance  claims  pursuant to various  policies both by the
Project  and Western  itself.  See  "Narrative  Description  of the  Business -
General Corporate Information - Insurance".

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
and by the end of 2003,  which was nine months after start-up,  the Project was
operating at 89 percent of design capacity.

Production  averaged  slightly over 135,500 barrels per day (27,100 barrels per
day  net to  Western)  in  2004  which  was a 15 per  cent  increase  in  daily
production  from the prior year.  Successive  gains in production were achieved
during  2004  until  the  fourth  quarter  when two  minor  operational  upsets
occurred.  Operations  were  brought  to full  capacity  at both  the  Mine and
Upgrader upon completion of these repairs. Design and other operational changes
were enacted to prevent  future  occurrence  of this type of minor upset.  Full
production at both the Mine and the Upgrader re-commenced on January 30, 2005.

In 2005, the Project and Western itself achieved many operational and financial
records.  Successive  quarterly  production  records  were  established  in the
second,  third and fourth quarters  reaching a level of 178,000 barrels per day
(35,600  barrels net to Western)  which lead to a record  annual  production of
160,000 barrels per day (32,000  barrels per day net to Western).  During 2006,
Albian became the first company in Canada to become ISO 14001  certified  under

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                                      -7-


the new standards and achieved one year without a lost time incident on July 1,
2006.  July 5th of that year marked four million  person  hours  without a lost
time incident. Financially, records were established in revenue, net income and
cash flow. The strong financial  performance  resulted in Western  aggressively
repaying amounts owed under its Revolving Credit Facility. These solid results,
both  operationally  and financially,  set the stage for continued  operational
stability and profitability for the Project and Western.

Early in 2006,  a  longitudinal  tear in the  conveyor  belt used to  transport
bitumen  ore from the  primary  crushers  at the Mine to the  Extraction  Plant
occurred  resulting in an unplanned  slowdown at the Mine. The Project operated
at  approximately  one-third of stated design rates while the replacement  belt
was prepared for  installation.  The installation was completed with production
curtailed  for three  weeks.  Full  production  resumed on March 20,  2006 and,
subsequent to this repair to the end of the first  quarter of 2006,  production
averaged 34,000 barrels per day net to Western  (compared to the design rate of
31,000, net to Western).

In May 2006,  the Project  undertook  its first major  turnaround of all of the
units at the Mine and the Upgrader  with full  production  resuming in mid-July
2006.  Following the initial  cleaning and inspection of the equipment,  it was
determined  that  additional  maintenance  and repair work at the  Upgrader was
required in order to remove large amounts of coke from the reactor  vessels and
to complete other work to enhance long-term performance.  The turnaround period
totalled 56 days. As a result of the full  turnaround,  production was reduced,
averaging 15,540 barrels per day net to Western for the second quarter of 2006.
Operating  expenses  increased  significantly  due to the  associated  expenses
incurred with the  turnaround.  Following the turnaround,  production  exceeded
rates achieved  leading up to the  turnaround.  Further  reliability  and minor
production  optimization activities over the next several years are expected to
result in sustained production of approximately 200,000 barrels per day.

Noteworthy 2006 milestones include:

      o    production of over 183 million barrels of bitumen in just over three
           and a half years of operation;

      o    successful completion of the first major planned turnaround;

      o    record stream day bitumen  production rate of nearly 219,000 barrels
           achieved in the fourth quarter of 2006 (post-turnaround);

      o    near record  cash flow from  operations  for  Western  despite a two
           month turnaround process;

      o    Muskeg River Mine expansion permit approval in December 2006; and

      o    only one lost time injury  accident  resulting in a record Lost Time
           Injury Frequency ("LTIF") factor for the Project of 0.02 per 200,000
           man hours.

The Project's  demonstrated  ability to safely  extract,  transport and process
significant  volumes  of  bitumen  provides  comfort  that  production  targets
established  by the Joint  Venture  (which could see  production  range between
180,000 to 200,000  barrels per day in the next several years) are  attainable.
These production  goals will be achieved through the systematic  implementation
of production optimization activities primarily at the Upgrader.

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                                      -8-


Operating costs for 2006 were $28.38 per processed  barrel, or $24.50 excluding
turnaround  costs, up from $22.06 per processed barrel in 2005,  largely due to
inflationary impacts to labour and associated with the robust commodity market,
partially offset by lower natural gas costs.


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
undertaken  by the  Corporation  in the last  three  years up to and  including
fiscal 2006:

      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) was completed on April 8, 2004;

      o    in 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  (although  only  $305
           million  could be drawn due to covenant  restrictions  in  Western's
           note indenture).  The additional $100 million is subject to the same
           terms and  conditions  as those  contained in the  Revolving  Credit
           Facility;

      o    in October  2005,  Western  successfully  amended  its $340  million
           Revolving  Credit  Facility with respect to lower pricing or spreads
           on both drawn and un-drawn 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;

      o    during  2006,  Western  successfully  re-financed  its  share of the
           Hydrogen  Manufacturing  Unit Credit Facility to bring the financing
           terms in line with the terms of Western's  Revolving Credit Facility
           whereby  financing  rates  charged  are a  function  of a  financial
           covenant; and

      o    debt credit facilities increased by $35 million during the course of
           fiscal 2006 (which resulted in full access to Western's $340 million
           Revolving  Credit  Facility)  to  partially  finance $312 million in
           capital expenditures.


<PAGE>
                                      -9-


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, 2006    JUNE 30, 2006   SEPTEMBER 30, 2006  DECEMBER 31, 2006
                                  --------------    -------------   ------------------  -----------------
<S>                                   <C>              <C>                <C>                <C>
Average Daily Production -
dry bitumen basis (bbl/day)           25,945           15,540             32,836             35,515

Average Net Prices Received
($Cdn/bbl)                            79.38             96.95             90.04               70.69

Royalties ($Cdn/bbl)                   0.27             0.51               0.51               0.36

Operating Expenses ($Cdn/bbl)         27.38             63.28             22.00               20.34

Feedstocks ($Cdn/bbl)                 19.79             29.63             21.76               12.92

Netback Received ($Cdn/bbl)(2)        31.94             3.53              45.77               37.08
</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 bitumen production from the AOSP will be between 165,000
to 175,000  barrels per day (33,000 to 35,000  barrels per day, net to Western)
for 2007.  Production  from the Project  accounts  for 100 percent of Western's
estimated production in 2007. See "Forward-Looking  Information" and "Risks and
Uncertainties".


EXPANSION 1

A key strategic  milestone for the AOSP was the  sanctioning  of Expansion 1 in
the  fourth  quarter  of 2006,  the first  major  expansion  of the AOSP.  This
expansion  represents the first of several  anticipated  expansions of the AOSP
over the next 10 to 15 years.  Expansion 1 is a 100,000  barrel per day (20,000
barrels per day net to Western)  fully  integrated  expansion  of the  existing
Project  facilities,  with both new oil sands mining  operations on Lease BT 31
and the east side of Lease 13 and associated additional bitumen upgrading using
similar  process  as that  of the  Scotford  Upgrader.  It  also  includes  the
construction  of common upstream  infrastructure  that will be sized to support
future  mining  expansions.  The  capital  cost  estimate  for  Expansion  1 is
approximately  $11.2 billion ($2.2 billion net to Western),  with contingencies
and Owners' costs representing a significant portion of this estimate.

Expansion 1 is the first  phase in the  long-term  AOSP's  goal to  construct a
series of similar  100,000  barrel  per day  expansions  that  could  result in
production  capacity of the AOSP surpassing 770,000 barrels per day from mining
operations alone in the next seven to ten years. This "building-block" strategy
has several competitive  advantages including economies of scale in engineering
design, procurement of components and materials and labour retention.

Of the total $11.2  billion  capital cost  estimate,  approximately  77 percent
represents component and labour costs, 20 percent represents the combination of
Owners' costs and contingencies (the majority of which are contingency related)
with the remaining three percent comprised of inflation adjustments.  As at the

<PAGE>
                                     -10-


end of 2006,  Western had incurred $222.8 million on the Expansion 1 in respect
of its 20 percent  interest.  Long-lead  items such as the  reactors  have been
ordered to ensure the Project maintains its cost and schedule. First production
from the upstream operations north of Fort McMurray is anticipated in late 2009
with first  production  of synthetic  oil from the Upgrader  towards the end of
2010.  As part of  Expansion 1, Kinder  Morgan will be  expanding  the Corridor
pipeline that connects the extraction and ore preparation  facilities near Fort
McMurray  to  the  upgrading  facilities  outside  of  Edmonton.  The  pipeline
expansion will include  construction of a 42 inch diameter pipeline to parallel
the  existing  dual  pipeline  system.  The 24 inch  line  which  is  currently
transporting  the diluted bitumen will be reversed to become the diluent return
line. The existing 12 inch line which  currently  fulfills this purpose will be
taken out of the pipeline rate base and used by the pipeline  owner for its own
purposes.  The expanded Corridor pipeline will be dedicated exclusively for the
benefit  of  the  Joint  Venture   Owners  and  is  sized  to  facilitate   the
transportation of diluted bitumen for the next several expansions.

As currently  designed,  expansion plans would result in the AOSP's  production
from mining operations  increasing from 180,000 to 200,000 barrels per day upon
the completion of minor production optimization  initiatives to 770,000 barrels
per day (154,000 barrels per day net to Western) by 2015. See  "Forward-Looking
Information" and "Risks and Uncertainties".


EXPANSIONS 2 AND 3

In addition to Expansion 1, the Owner's longer term  optimization plan includes
development  of  additional   resources  associated  with  the  Jackpine  Mine.
Resources  associated  with Expansion 2 and 3 would support two discrete trains
of approximately 100,000 barrels per day of bitumen production. This additional
production of 200,000 barrels per day from Expansions 2 and 3 is anticipated in
the 2013-2014 timeframe.

Mining  expansions  of the AOSP beyond  Expansion 1 at the Joint  Venture level
will be limited only to upstream or mining operations. The Joint Venture Owners
have  contemplated  combining  Expansions  2 and 3 in order to achieve  greater
economies of scale and accelerate the production profile of future expansions.

Shell will be filing with applicable government authorities an application that
will enable the AOSP to mine up to 770,000 barrels per day (154,000 barrels per
day net to  Western).  The  permitting  capacity  under this  application  also
involves  resources on Leases 88, 89 and 9 which are associated with Expansions
3, 4 and 5  (described  below).  This  permit  does  not  consider  any  future
development  of leases  recently  acquired by Shell which are located  north of
Lease 9 which have not been formally  evaluated to this point.  This additional
acreage,  should  recoverable  resources  be  found  on  them,  could  have the
potential to support two additional expansions of the AOSP.

Completion  of  Expansions  2  and  3 is  subject  to a  number  of  risks  and
uncertainties and constitutes forward-looking information. See "Forward-Looking
Information" and "Risks and Uncertainties.


EXPANSIONS 4 AND 5

With the mining  leases owned by Joint Venture  Owners under the  Participation
and AMI Agreement,  it is estimated that sufficient  resources exist to support
expansions beyond the first three phases.  Following Expansions 1, 2 and 3, the
Owner's  longer term  optimization  plan  involves  development  of  additional
resources associated with the Pierre River Mine which initially will be located
on the west  side of the  Athabasca  River on  Lease  9. As  further  core-hole
drilling is completed to delineate  the resource  potential of the Pierre River
Mine,  Western  believes that two  additional  100,000  barrels per day (20,000
barrels per day net to Western) expansions of the AOSP (Expansions 4 and 5) may
be supported. The regulatory permit application referred to above would address

<PAGE>
                                     -11-


these volumes.  An active core hole drilling program is planned on Lease 17 and
any  recoverable  resource  established  for this lease  would form part of the
Pierre River Mine. At this point,  no formal  evaluation  has been completed on
Lease 17.

As additional  acreage is acquired and  evaluated,  future  expansions  will be
included as part of the Project should the Owners choose to participate.  It is
anticipated that the Owners will undertake the following  activities as part of
their longer term optimization plan:

      o    evaluation of additional  mineable leases acquired recently by Shell
           in the Athabasca  region,  namely Leases 15, 309, 310, 350, 351, 631
           and 632;

      o    evaluation  drilling on the  substantial  land base acquired by both
           Chevron and Western.  Chevron acquired approximately 75,000 acres in
           2006 while  Western  acquired  over  21,000  acres in 2006 which may
           support in-situ  development.  Western's view is that the Ells River
           Project  could  contain  bitumen  in place  (with pay  thickness  of
           greater than 18 metres)  suitable for in-situ  development in excess
           of 7.4 billion  barrels  (approximately  1.5 billion  barrels net to
           Western).  Based on this  estimate,  production  from the Ells River
           Project,  combined with volumes from Western's  in-situ  project (in
           which the Company holds an average 64 per cent land interest), could
           support  production  in  excess  of  50,000  barrels  per day net to
           Western; and

      o    analyses  of  processes  and/or  equipment  that  will  result  in a
           reduction of unit operating costs in the extraction process for both
           mineable and in-situ  resources along with the dependency on natural
           gas, together with assessments of procedures and/or  introduction of
           equipment  designed to increase  the  production  throughput  of the
           facilities  for a  significantly  lower  capital  intensity  than an
           initial construction project.

Taken as a whole,  forecasted  expansion  plans  for both  in-situ  and  mining
operations  would  increase  Western's  total  bitumen  production to more than
200,000 barrels per day within the next 15 to 20 years.  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.  There can be no assurance  that any expansion  will proceed on
the basis contemplated or at all. 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  certain
de-bottlenecking  volumes  as well as the  first  phase  of the  Jackpine  Mine
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 portions of Lease BT 31 and the east side of
Lease 13 and includes a mining and extraction  facility.  The Project  received
the final necessary  regulatory  approval on December 21, 2006 to mine from the
Expansion 1 area.

In addition,  Western  announced that the Joint Venture is preparing an omnibus
regulatory  permit that, once submitted and approved,  would enable the Project
to produce 770,000 barrels per day (154,000 barrels per day net to Western). It
is  envisioned  that  this  permit  will be  submitted  during  2007  with  the
expectation that approval will be received in mid-2009.  This will increase the
approved  permitting  capacity of the Joint Venture by 300,000  barrels per day

<PAGE>
                                     -12-


over the 470,000 barrels per day originally in place.  The incremental  300,000
barrels per day can be allocated into a further  100,000 barrels per day at the
Jackpine Mine area with an  incremental  200,000  barrels per day allocated for
the Pierre River Mine. It is currently envisioned that this permitting capacity
would be sufficient for the first five mining expansions of the AOSP.

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


RESERVES, RESOURCES AND LAND POSITION


RESERVES

Lease 13  encompasses  49,872 acres 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. Bitumen  production from
the east side of Lease 13 is  anticipated  to occur in 2009 with  synthetic oil
from the upgrading facilities sometime during 2010.

GLJ Petroleum Consultants Ltd. ("GLJ") prepared a reserve report dated February
7, 2007 (the "GLJ Reserves  Report") which evaluated the reserves  attributable
to Western as of December 31, 2006.  The  combination  of the Muskeg River Mine
and the Jackpine Mine has been  estimated by GLJ to contain  approximately  577
million barrels of working interest oil reserves.  Of this total  approximately
496 million barrels net to Western are proved reserves while 81 million barrels
net to Western are  considered  probable  reserves.  Based on GLJ's  forecasted
AOSP's undiluted  bitumen  production rate of 175,000 barrels per day for 2007,
the proved plus probable reserves have a reserve life index of 44 years.

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

--------------------------------------------------------------------------------
                                                                       WESTERN'S
                                                             TOTAL       SHARE
PROVED AND PROBABLE SYNTHETIC CRUDE OIL RESERVES            (MMbbls)    (MMbbls)
--------------------------------------------------------------------------------

JOINT VENTURE (RESERVES)
  Muskeg River Mine (Western portion of Lease 13)            1,545        309
  Jackpine Mine (Eastern portion of Lease 13)                1,339        268
                                                          ----------------------
   TOTAL RESERVES                                             2,884        577
--------------------------------------------------------------------------------

The tables below  summarize the upgraded  bitumen  reserves  ("synthetic  crude
oil") and the value of future net revenue  attributable to Western's  ownership
as evaluated in the GLJ Reserves  Report.  Synthetic  crude oil reserves do not
include  blendstock  volumes.  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  CONTAINED IN THE GLJ RESERVES REPORT WILL
BE  ATTAINED  AND  VARIANCES   COULD  BE  MATERIAL.   Other   assumptions   and
qualifications  relating  to costs and other  matters  are  included in the GLJ

<PAGE>
                                     -13-


Reserves 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
Reserves  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, 2006

                                         CONSTANT PRICES AND COSTS      FORECAST PRICES AND COSTS
                                         -------------------------      -------------------------
                                             SYNTHETIC CRUDE OIL           SYNTHETIC CRUDE OIL
                                         -------------------------      -------------------------
                                          GROSS              NET         GROSS              NET
                                         (MMBBL)           (MMBBL)      (MMBBL)           (MMBBL)
                                         -------           -------      -------           -------
<S>                                        <C>               <C>          <C>               <C>
Proved Developed Producing                 268               242          268               244
Proved Developed Non-Producing              7                 6            7                 6
Proved Undeveloped                         221               202          221               204
                                         --------------------------------------------------------
Total Proved                               496               450          496               454
Total Probable                              81                72           81               71
                                         -------           -------      -------           -------
Total Proved Plus Probable                 577               522          577               525
                                         =======           =======      =======           =======
</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                        DISCOUNTED AT
                                   UNDISCOUNTED             10%           UNDISCOUNTED            10%
                                      (MM$)                 (MM$)             (MM$)               (MM$)
                                  -------------          -----------       ---------          -----------
<S>                                   <C>                   <C>              <C>                <C>
Proved Developed Producing            8,402                 3,449            6,347              2,763
Proved Developed Non-Producing         294                   141              203                 93
Proved Undeveloped                    4,874                  41              3,438              (129)
                                  -------------          -----------       ---------          -----------
  Total Proved                       13,570                 3,631            9,988              2,726
Total Probable                        3,190                  902             2,258               654
                                  -------------          -----------       ---------          -----------
  Total Proved Plus Probable         16,760                 4,533           12,247              3,381
                                  -------------          -----------       ---------          -----------
</TABLE>

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

<PAGE>
                                     -14-


<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     29,666      2,709       9,447        3,940             -          13,570     3,581     9,988
Total Proved
Plus
Probable         34,517      3,279       10,288       4,191             -          16,760     4,513    12,247
</TABLE>

                     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  synthetic crude oil
reserves  attributable  to  Western's  ownership  interest in the Project as at
December 31, 2006 are $3,631 million and $4,533 million, respectively, 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     7,684    4,561    3,049   2,239    1,762    5,819   3,569    2,470    1,873   1,515
Proved Developed
Non-producing                   281      196      127      80       49      192     131       81      47       25
Proved Undeveloped             4,699    1,059    (220)   (706)    (898)    3,292    617     (343)    (718)   (871)
                               -------  ------- -------- -------  ------- -------- -------  ------- -------- -------
Total Proved                   12,663   5,816    2,957   1,613     913     9,303   4,317    2,208    1,201    668
Total Probable                 3,554    1,616     912     607      451     2,510   1,158     669      459     352
                               -------  ------- -------- -------  ------- -------- -------  ------- -------- -------
Total Proved Plus Probable     16,217   7,432    3,868   2,220    1,365   11,813   5,475    2,877    1,660   1,020
                               =======  ======= ======== =======  ======= ======== =======  ======= ======== =======
</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      34,799   3,012       14,149         4,975            -           12,663     3,360     9,303
Total Proved
Plus Probable     40,954   3,737       15,267         5,373            -           16,217     4,404    11,813
</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  synthetic crude oil
reserves  attributable  to  Western's  ownership  interest in the Project as at
December 31, 2006 are $2,957 million and $3,868 million, respectively, based on
forecast prices and costs.

<PAGE>
                                     -15-


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

Both fiscal 2006 and 2005  represent  full years of  production.  The following
table sets forth a reconciliation  of the changes in Western's bitumen reserves
as at December 31, 2006 against such  reserves as at December 31, 2005 based on
the constant price and cost assumptions set forth in Note 8 below:

<TABLE>
<CAPTION>
                                                       SYNTHETIC CRUDE OIL
                                          ------------------------------------------------
                                                                           NET PROVED PLUS
                                          NET PROVED       NET PROBABLE        PROBABLE
                                            (MMBBL)          (MMBBL)            (MMBBL)
                                            -------          -------            -------
<S>                                         <C>              <C>                <C>
At December 31, 2005                          186              109                295
                                            -------          -------            -------
     MRM Extension                            79               (73)                6
     Improved Recovery                         -                -                  -
     Technical Revisions                       -                2                  2
     Discoveries                               -                -                  -
     AOSP Expansion 1 Addition                202               42                244
     Dispositions                              -                -                  -
     Economic Factors                         (7)              (8)               (15)
     Production                              (10)               -                (10)
                                            -------          -------            -------
At December 31, 2006                          450               72                522
</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,  2006  against  such
reserves as at December 31, 2005:

<TABLE>
<CAPTION>
                                                                                             (MM$)
                                                                                             -----
    <S>                                                                                      <C>
    Estimated Future Net Revenue at December 31, 2005                                        2,575
                                                                                             -----
      Sales and Transfers of Oil and  Gas Produced, Net of Production Costs and Royalties    (339)
      Net Change in Prices, Production Costs and Royalties Related to Future Production      (232)
      Changes in Previously Estimated Development Costs Incurred During the Period            66
      Changes in Estimated Future Development Costs                                          (256)
      Extensions and Improved Recovery                                                        507
      Discoveries                                                                              -
      Acquisitions of Reserves                                                                41
      Dispositions of Reserves                                                                 -
      Net Change Resulting from Revisions in Quantity Estimates                                -
      Accretion of Discount Pre Tax                                                           334
      Net Change in Income Taxes                                                              30
      Changes Resulting from Technical Revisions                                               -
                                                                                             -----
    Estimated Future Net Revenue at December 31, 2006                                        2,726
                                                                                             =====
</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 Reserves 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
      "Proved Undeveloped" reserves are those reserves expected to be recovered
      from known accumulations  where a significant  expenditure is required to
      render them capable of production.
      "Probable"  reserves  are  those  reserves  that are less  certain  to be
      recovered than proved 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.

<PAGE>
                                     -16-


(2)   Project reserves associated with the Muskeg River Mine are all 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 particular Mine. All of the reserves
      associated  with the  AOSP  Expansion  1 are  classified  as  undeveloped
      reserves  given  the  significant  capital  investment  to bring  them to
      production.  Western's  share of the capital costs  associated  with AOSP
      Expansion 1 is  estimated at  approximately  $2.2  billion.
(3)   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)   Reserves are stated on a synthetic crude oil basis.  This recognizes that
      intrinsic in the Project's  operations,  bitumen production from the Mine
      receives  an  uplift  as a  result  of the  hydrotreating/hydroconversion
      process.  GLJ has used an  uplift  of two  percent  on the  total  proved
      reserves  and three  percent on the  probable  reserves
(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, 2006  Edmonton Par less
      $7.87/bbl  in 2006,  reflecting  the  average  December  2006  offset  to
      Edmonton Par for each feedstock product and marketable product stream and
      anticipated  composition of feedstock and sales. Western's sales mix is a
      combination  of heavy and light  materials.  Each  product type trades at
      either a premium or discount  to an  appropriate  benchmark  based on the
      crude  qualities.  In the forecast price case, these offsets change based
      on the forecasted prices of the underlying commodity.  For the purpose of
      2007 in the forecast  case,  GLJ estimates the oil pricing to be Edmonton
      Par less $8.85/bbl.
(6)   Bitumen production has been forecast by GLJ to be 163,000 barrels per day
      in 2007 in the total proved  category  growing to 265,000 barrels per day
      by 2014 in the total proved  category.  In the proved plus probable case,
      production is forecast to grow from a rate of 175,000  barrels per day in
      2007  to an  average  rate  of  290,000  barrels  per  day by  2014.  The
      incremental production for the probable reserves reflect the current mine
      plan as well as  improved  extraction  recovery  relative  to the  proved
      category.  Significant increase under each scenario reflects the addition
      of  production  from the AOSP  Expansion 1.
(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 $39.00/bbl
      based upon the December 2006 offset and a posted  December 31, 2006 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, 2006 is  estimated  at $1,650  million.
(8)   The  constant  price  reflects  December  31, 2006  prices of  $67.58/bbl
      Edmonton Par oil,  $47.62/bbl LLB Crude Oil at Hardisty,  $6.07/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)
---------------------------------------------------------------------------------------------------------------------
<S>       <C>            <C>         <C>                      <C>                      <C>                <C>
2007      2.0            0.87        62.00                    70.25                    39.25              7.00
2008      2.0            0.87        60.00                    68.00                    40.00              7.25
2009      2.0            0.87        58.00                    65.75                    39.75              7.55
2010      2.0            0.87        57.00                    64.50                    39.75              7.60
2011      2.0            0.87        57.00                    64.50                    40.25              7.65
2012      2.0            0.87        57.50                    65.00                    41.50              7.95
2013      2.0            0.87        58.50                    66.25                    42.50              8.10
2014      2.0            0.87        59.75                    67.75                    43.50              8.30
2015      2.0            0.87        61.00                    69.00                    44.25              8.50
2016      2.0            0.87        62.25                    70.50                    45.25              8.65
2017      2.0            0.87        63.50                    71.75                    46.00              8.85
2018+     2.0            0.87       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 upstream or bitumen production  component of the
      project  during the period 2007 through  2009,  4.0 percent in 2010,  3.0
      percent in 2011 followed by 2.0 percent thereafter.
(9)   Western's weighted average historical  realized price for 2006 was $60.51
      per  synthetic  barrel  sold.  Western  had no crude oil  hedges in place
      during 2006.
(10)  GLJ is an independent  qualified reserves evaluator appointed pursuant to
      NI 51-101.


<PAGE>
                                     -17-

                            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 Reserves 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$)
                                                  -------------------     -------------------       --------------
<S>                                                       <C>                     <C>                    <C>
2007                                                      603                     625                    626
2008                                                      763                     821                    824
2009                                                      549                     608                    611
2010                                                      282                     313                    325
2011                                                       69                      82                     91
Total   for  all   years   of   reserve   life,
undiscounted                                             3,940                   4,975                  5,373
Total for all years discounted at 10%/year               2,342                   2,663                  2,745
</TABLE>

Western  intends to finance these  development  costs through a combination  of
free cash-flow from operations  together with existing  banking  facilities and
incremental debt  financings.  To the extent that bank facilities or other debt
financings  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.


UNDEVELOPED RESERVES

The entire volume of undeveloped  reserves relates to Expansion 1. During 2006,
all Joint Venture  Owners  sanctioned  the  construction  of Expansion 1. It is
anticipated  that the capital  costs  associated  with this  expansion  will be
approximately $11.2 billion  (approximately $2.2 billion net to Western).  This
construction  effort will take place over several years with first oil from the
mine  operations  anticipated  to occur during 2009. Two separate crude streams
are  expected to be produced  from this  expansion.  One stream will be a heavy
synthetic oil similar to the heavy synthetic stream currently produced from the
base operations,  while a second stream will be light sour synthetic oil. It is
currently  envisioned  that VGO will not be produced with this expansion as the
Scotford  Refinery,  which takes the VGO as feedstock from the base operations,
does not have the capacity to take further VGO volumes.


COSTS INCURRED

The  following  table sets forth  costs  incurred  by Western in respect of the
Project for the year ended December 31, 2006:

      PROPERTY ACQUISITION COSTS          EXPLORATION COSTS   DEVELOPMENT COSTS
                 (MM$)                         (MM$)                (MM$)
---------------------------------------   -----------------   -----------------
PROVED PROPERTIES   UNPROVED PROPERTIES
-----------------   -------------------
          nil             $25.0(1)              Nil               $251.1(2)

Notes:
(1)   Represents  amounts spent on in-situ land acquisitions for both Western's
      interest in Chevron's  Ells River  Project as well as Western's  operated
      in-situ properties.
(2)   Includes $184.6 million incurred to fund Western's  commitments  pursuant
      to the first phase of Expansion 1.

<PAGE>
                                     -18-


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, 2006 is $20.8
million ($85.1 million undiscounted). These liabilities relate to Western's 20
percent 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. The
Corporation's share of the asset retirement obligation at December 31, 2006 was
approximately $20.8 million which is less than one per cent of the total
discounted cash flows of the proved plus probable reserves under the constant
pricing case. 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.


SIGNIFICANT FACTORS OR UNCERTAINTIES ON RESERVES DATA

Western's  reserves to date represent the addition of reserves  associated with
the current  producing Muskeg River Mine on the west side of Lease 13, together
with  reserves  associated  with the Jackpine  Mine on Lease BT 31 and the east
side of Lease 13. All  infrastructure  components  are in place to extract  the
independently  evaluated  reserves  for the Muskeg  River Mine,  and the Owners
formally sanctioned the construction of the Jackpine Mine which is projected to
cover a period of four  years.  Significant  capital  costs have  already  been
incurred for the Project,  however,  the  exposure to rising  capital  costs is
heightened with respect to the Jackpine Mine as the  construction  period is in
the early stages.  Significant  capital cost pressures  would have an impact on
both the volume  and future net  revenue  associated  with the  Jackpine  Mine.
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 Plant 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

<PAGE>
                                     -19-


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.


RESOURCES

The  Participation  and AMI  Agreement  provides that the Owners have rights to
participate in any additional  leases that are acquired by any one of the other
Owners in the Athabasca  region prior to December 6, 2009.  Western is entitled
to participate in all future  expansions on Lease 13 and in the other oil sands
opportunities  with Shell and  Chevron in  respect of Shell's  Other  Athabasca
leases, and within a defined area of mutual interest.

In respect of an ongoing  delineation  drilling program on Leases 88, 89, 90, 9
and the remainder of Lease 13, Western  engaged  Norwest to prepare  volumetric
estimates of recoverable  bitumen  associated  with mining pits. GLJ used these
geological and mining assessments to determine Contingent Resources as detailed
in the GLJ  Contingent  Resource  Report.  Western will  disclose  reserves and
resources  on a project  basis  rather  than lease by lease,  as the mine plans
straddle lease  boundaries  and contingent  resources are related to a specific
mine plan. Disclosure in this manner will also create alignment with regulatory
permits and proposed mine plans.

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

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

<PAGE>
                                     -20-


The following table outlines the  independently  evaluated volume of contingent
resources  available for future expansion  opportunities on each of the various
projects  that  have  been  sanctioned  by the  AOSP or that  are  planned  for
subsequent  development.  The results of the GLJ Contingent Resource Report are
detailed below.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
WESTERN'S SHARE OF MINEABLE SYNTHETIC CRUDE OIL VOLUMES (mmbbls)
-------------------------------------------------------------------------------------------------------------
                                                                                      PROVED PLUS PROBABLE
                                                                                         RESERVES PLUS
                            CONTINGENT RESOURCES (1)              RESERVES            CONTINGENT RESOURCES
------------------------------------------------------- ---------------------------- ------------------------
                                                                      PROVED PLUS
PROJECT AREAS               LOW     BEST        HIGH       PROVED        PROBABLE           BEST        HIGH
------------------------------------------------------- ---------------------------- ------------------------
<S>                         <C>      <C>         <C>          <C>             <C>            <C>         <C>
Muskeg River Mine (2)       188      228         291          275             309            537         600
Jackpine (3)                314      458         645          220             268            726         913
Pierre River (4,5)          102      205         306            -               -            205         306
------------------------------------------------------- ---------------------------- ------------------------
TOTAL                       604      891       1,242          495             577          1,468       1,819
------------------------------------------------------- ---------------------------- ------------------------
</TABLE>
Notes:
(1)  Contingent  resources have been evaluated for Leases 13, 88, 89, 90 and 9.
     Categories  of Low,  Best and High  are  used as  recommended  in the COGE
     Handbook.

(2)  Includes the west side of Lease 13, 90 and Sharkbite areas. Reserve status
     has been  assigned only to the portion of Muskeg River Mine pit located to
     the east of Highway 63.

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

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

(5)  Represents Expansions 4 and 5.


In addition to the above,  Western's  view is that the Ells River Project could
contain  bitumen  in place  (with pay  thickness  of  greater  than 18  metres)
suitable for in-situ  development in excess of 7.4 billion  barrels of original
oil in place (approximately 1.5 billion barrels net to Western).  Based on this
estimate,  production  from the Ells River Project,  combined with volumes from
Western's  in-situ  project (in which the Company  holds an average 64 per cent
land  interest),  could support  production in excess of 50,000 barrels per day
net to Western.

These in-situ  volumes,  together with production  associated with the recently
announced future mineable  expansions,  would increase  Western's total bitumen
production to more than 200,000  barrels per day net to Western within the next
15  to  20  years.   See   "Forward-looking   Information"   and   "Risks   and
Uncertainties".

LAND POSITION

During 2005,  Shell  purchased  Leases 15, 309,  310,  351, 352, 631 and 632 at
public land auctions held by the Alberta  Government.  These lands have not yet
been  evaluated  through  core-hole  drilling  and  analysis.  Pursuant  to the
Participation and AMI Agreement, Western has the right to participate to its 20
percent  interest  in the  development  of these  leases.  An  extensive  2,500
core-hole  drilling program over the next five years is planned to evaluate the
resource potential of these additional leases.

In August 2006,  Western  exercised its option to  participate  to a 20 percent
interest in Chevron's  Ells River  Project.  The Ells River  Project is located
approximately  50  kilometers  northwest of Fort  McMurray in the Athabasca oil
sands  region.  An  evaluation  program is planned on these  leases  during the
2006/2007 winter drilling program to further delineate the resource potential.

<PAGE>
                                     -21-


Western's  undeveloped  land  position also includes  in-situ  leases  acquired
during 2005 and 2006  covering  21,000 gross acres,  namely Leases 353, 442 and
472.  Both Shell and Chevron  have elected to  participate  to their 20 percent
interest  in Lease 353  pursuant to a separate  agreement  among the Owners and
only Shell has elected to participate for a 33? percent  interest in Leases 442
and 472. In the  absence of  specific  agreements,  the  Participation  and AMI
Agreement  provides  that  Owners  are  entitled  to  participate  for an equal
interest in leases acquired by the Owners in the Athabasca region.

Only a fraction of Western's undeveloped land position has been evaluated.  The
lands  associated  with  Western's  proved  and  probable  reserves   represent
approximately  11 per  cent  of  the  more  than  69,000  net  acres  of  total
undeveloped lands in which Western has the right to participate. As delineation
of these lands continues,  Western expects its reported  resources and reserves
to increase and will be updated accordingly

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

                                        GROSS         WESTERN        NET AREA TO
                                        AREA          INTEREST          WESTERN
                                       (ACRES)          (%)             (ACRES)
                                    --------------------------------------------
AOSP MINEABLE (EVALUATED)
     Lease 13                          48,216            20%             9,643
     Lease 88                          23,176            20%             4,635
     Lease 89                          14,763            20%             2,953
     Lease 90                          2,882             20%              576
     Lease 9                           14,895            20%             2,979
     Additional Leases (1)             8,010             20%             1,602
--------------------------------------------------------------------------------
                                      111,942             -              22,388
--------------------------------------------------------------------------------
ADDITIONAL MINEABLE LEASES (UNEVALUATED)
     Lease 15                          3,795             20%              759
     Lease 17                          21,507            20%             4,301
     Lease 351                         22,772            20%             4,554
     Lease 352                         16,447            20%             3,289
     Lease 631/632                     6,642             20%             1,328
     Lease 309                         11,386            20%             2,277
     Lease 310                         7,591             20%             1,518
--------------------------------------------------------------------------------
                                       90,140             -              18,026
--------------------------------------------------------------------------------
IN-SITU LEASES (UNEVALUATED)
     Lease 353 (Western)               8,223             60%             4,934
     Lease 442 (Western)               10,121            67%             6,747
     Lease 472 (Western)               3,163             67%             2,109
     Chevron Leases (2)                74,643            20%             14,929
--------------------------------------------------------------------------------
                                       96,150             -              28,719
--------------------------------------------------------------------------------
TOTAL                                 298,232             -              69,133
--------------------------------------------------------------------------------

Notes:
(1)  Includes Leases AT30, AT34, AT36, BT30 AND BT31.

(2)  Includes Leases 348,349,350,673,675.


<PAGE>
                                     -22-


IN-SITU PROJECTS


WESTERN IN-SITU PROJECT

During 2005,  Western  acquired Lease 353 and in 2006,  acquired Leases 442 and
472 which are  contiguous  to Lease 353 in the Athabasca  region.  All of these
leases are considered  prospective  for in-situ  development.  Taken  together,
these three leases bring the total acreage under leases which would be operated
by Western to over 21,000 acres or nearly 14,000 acres net to Western.  Western
is currently  executing a 2006/2007  winter core hole drilling program on these
leases consisting of approximately 19 wells. See "Narrative  Description of the
Business - The  Athabasca  Oil Sands  Project -  Reserves,  Resources  and Land
Position - Land Position".


ELLS RIVER PROJECT

Western holds a 20 percent interest in the Chevron operated Ells River Project.
An  evaluation  program  is  planned  for  the  2006/2007  winter  season.  See
"Narrative  Description  of the Business - The  Athabasca  Oil Sands  Project -
Reserves, Resources and Land Position - Land Position".

Both of  these  in-situ  developments  are  suitable  for SAGD  application,  a
technology  utilizing  injected  steam to  mobilize  the bitumen  source.  As a
precursor to development,  these projects are proceeding with initial appraisal
drilling during the winter of 2006/2007.  To assist in the critical analysis of
these  opportunities  and develop any Western led in-situ  project,  Mr.  Graig
Ritchie was hired during 2006 to lead this team.  Mr. Ritchie was formerly with
EnCana  Corporation  and  Imperial  Oil where he was involved in all aspects of
production, engineering and market development.


DOWNSTREAM

Beyond  Expansion  1,  Western is  independently  pursuing  its own  downstream
integration  opportunity to maximize value from its growing oil sands resources
and undeveloped  acreage position.  Western's overall objective with respect to
this key  strategic  initiative  is to reduce  capital  intensity  and  improve
product realizations.  Western intends to explore and pursue opportunities that
will  realize  the full value of the  Corporation's  assets  and future  growth
opportunities.  These opportunities may be within or outside of Canada and will
focus on North  American  demand.  This may result in an acquisition or sale of
assets,  merger or other corporate  transaction.  Western's advisors,  Goldman,
Sachs & Co and TD Securities  Inc., will be assisting in these activities which
will involve  contacting third parties.  There can be no assurances that any of
these activities will result in the consummation of an agreement or transaction
or result in any change to Western's current ongoing business strategy.


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
Corridor  pipeline  system that connects the Mine to the Scotford  Upgrader and
the Scotford Upgrader to certain third party pipelines. Terasen was acquired in
2005 by Kinder Morgan, Inc. ("Kinder Morgan").  Kinder Morgan now operates this
pipeline system directly. The Owners are severally responsible for the costs of
transportation  on the  Corridor  pipeline  system,  which  is on a take or pay
basis.  As part of  Expansion  1, Kinder  Morgan is currently in the process of
expanding  the  Corridor  pipeline  system  which will  include  upgraded  pump
stations  and  a new  42  inch  pipeline.  Once  completed,  the  new  pipeline
infrastructure will support the next several expansions of the AOSP.

<PAGE>
                                     -23-


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.

ATCO  Pipelines  owns and operates the Muskeg River Gas Pipeline which provides
natural  gas  supply  to the  Muskeg  River  Mine.  The  Owners  are  severally
responsible for the costs of this pipeline.


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 percent 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)  other  than the  volume  sold to Shell  Canada  Products
Limited, Western sells all of its production volumes into the traditional North
American markets.


KURDISTAN EXPLORATION PROJECT

Western,  through its wholly-owned  subsidiary,  WesternZagros,  negotiated the
initial form of an EPSA with the Kurdistan Regional Government ("KRG"), subject
to  finalization  of key  terms  and  ratification  by the KRG to  comply  with
expected federal petroleum  legislation.  The EPSA provided for the exploration
of  conventional  oil and gas in the Federal  Region of  Kurdistan  in northern
Iraq.  WesternZagros continues to work towards ratification of an EPSA with the
KRG which is  expected  to include  the  finalization  of terms  including  its
contract area and the corresponding work program commitments.


                         GENERAL CORPORATE INFORMATION


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 the 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 carry-forwards.


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.

<PAGE>
                                     -24-


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 percent lower than the original case that was approved by
the Alberta Energy and Utilities Board and a number of further  initiatives are
under development.  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.  The Project's  goal is to further  reduce  emissions by
another 40 percent by 2010 through a combination of energy efficiency projects.
To achieve  this goal,  the Owners are  pursuing a  multi-faceted  plan,  which
includes energy conservation and efficiency projects,  investigation of cleaner
technology, the purchase of offsets and tree-planting offset programs.


INSURANCE

The Owners  obtained  insurance to protect against certain risks of loss during
the  construction  of the Mine,  the  Extraction  Plant and the  Upgrader.  The
insurance policy (the "Policy") is typical for a project of this nature.

In addition,  Western obtained,  for its own account,  $200 million of coverage
under Section IV of the 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 directly  related to achieving the guaranteed
production  levels;  and (iv)  debt  servicing  costs  related  to  obligations
incurred to finance any of (i), (ii) or (iii).

Western  has filed  insurance  claims  for the full $200  million  limit  under
Section IV of the Policy as a result of cost overrun and Project  delay claims.
Arbitration proceedings (the "Arbitration") have been initiated seeking payment
of approximately  $181 million together with interest and legal costs. A second
arbitration  seeking  payment of $16.5  million from insurers who provided cost
overrun and Project delay coverage  pursuant to a separate  policy is currently
being held in abeyance.  In addition,  Western has commenced an action  against
the brokers  involved in the placement of the Section IV Policy  coverage which
has been stayed pending the conclusion of the Arbitration.

Western  has also  received  certain  payments  from  insurers  as a result  of
property damage and loss of profits claims relating to the January,  2003 fire.
To date,  Western has received $16.1 million from insurers in respect of claims
relating to the fire and ensuing  freeze  damage.  Those  insurers who are also
involved in the  Arbitration  with Western  have  withheld  insurance  proceeds
payable to Western  for damages  related to the  January  2003 fire and related
freezing damage. See "Narrative Description of the Business - The Athabasca Oil
Sands Project - Mining - Base Operations".

During 2005, the Joint Venture  announced it had reached a settlement  with the
insurers  on its loss of profits  claim under  Section  III of the Policy.  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

<PAGE>
                                     -25-


insurers on Western's  Section IV cost overrun and Project delay coverage under
the Policy which, as discussed above, is currently in Arbitration.

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 an  appropriate  analysis to
determine where to best deploy the funds.

Western, together with its other Joint Venture Owners, have secured appropriate
construction  and delay and start-up  insurance for Expansion 1. These policies
will be in place until certain  milestones  are achieved once  construction  is
complete.  As operations  commence with  Expansion 1, Western will reassess its
corporate insurance policies to ensure appropriate levels of coverage exist.

RISK MANAGEMENT ACTIVITY

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 price 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, 2007, the following
positions are in place:

                                                  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 hedging  activities  in the GLJ  Reserves
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,   capital  cost
classification of the AOSP expansions 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.


EMPLOYEES

As at December 31, 2006, Western had 58 employees.  Most of these employees are
dedicated  exclusively  to the  development of the reserve and resource base of
the  AOSP.  Western   significantly   increased  its  internal   organizational
capabilities  during 2006 with the addition of various senior  technical  staff
for the in-situ business  initiative as well as Western's  conventional oil and
gas  initiative in Kurdistan.  This expanded  technical  team gives Western the

<PAGE>
                                     -26-


ability to make assessments of both the Shell and Chevron  property rights,  in
addition to  pursuing  the  purchase of  undeveloped  properties  directly  and
offering reciprocal participation rights to Shell and Chevron.


                                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 credit agreement governing Western's bank
facilities and the note indenture  governing the Notes contain  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.


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.

<PAGE>
                                     -27-


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>
                                     -28-


                             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.

         MONTH        HIGH            LOW           CLOSING          VOLUME
---------------- ------------- --------------- --------------- ----------------
January               36.09          28.57           34.86         14,482,839
February              38.90          29.82           31.00         13,258,128
March                 34.39          30.59           32.39         13,322,284
April                 38.09          32.85           33.81         19,880,830
May                   36.25          29.50           30.78         24,814,811
June                  33.69          25.70           30.94         26,728,260
July                  31.60          24.50           25.96         25,993,181
August                30.40          24.60           29.50         40,370,355
September             30.55          25.71           28.60         59,495,169
October               29.95          24.47           28.95         35,429,462
November              32.45          27.17           31.85         18,225,089
December              34.00          30.23           32.71          8,290,068

                                 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             BBB-                 Ba3
-------------------------------------------------------------------------------

S&P Rating  Definition - Western's  Notes  previously were assigned a rating of
BB+ but were upgraded to BBB- on December 27, 2006.  Obligations  rated BBB- or
higher are generally considered "Investment Grade" under the S&P rating system.
This implies that  adequate  protection  parameters  exist on the credit issue.
However,  adverse economic conditions or changing circumstances are more likely
to lead to a weakened capacity of the obligor to meet its financial  commitment
on the  obligation.  Ratings  below  this  threshold  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.  The (-) sign is added to show
relative  standing  within the major rating  categories.  The corporate  rating
assigned  to  Western is BB+ with a stable  outlook  which  indicates  that the
current  rating  implies  Western  will be able to manage its capital  spending
commitments an maintain debt levels within its current credit profile.

Moody's Rating Definition - 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

<PAGE>
                                     -29-


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
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.
Moody's has assigned a Ba2 corporate rating to Western.

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 EXECUTIVE OFFICERS

The following table lists the names of the directors and executive officers of
Western as at the date hereof, 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.

Geoffrey A. Cumming(3)(5)        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.

Fred Dyment((1))(2)(8)           Director          Independent    businessman.     Formerly,      January 2007
Calgary, Alberta                                   Chief  Executive  Officer  of Ranger  Oil
                                                   Limited   (sold   to   Canadian    Natural
                                                   Resources    Limited    in   2000)    with
                                                   increasingly    senior   positions   prior
                                                   thereto,    including    Chief   Financial
                                                   Officer. Currently serving on the board of
                                                   a number of public corporations.

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>
                                            -30-

<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(1)(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)               Chairman and      Chairman  of  the  Board  of   Directors.        July 1999
Calgary, Alberta; Canada         Director          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(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 WHO ARE NOT DIRECTORS

Steve Reynish                    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>
                                            -31-

<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 Officer     Financial President Finance & Administra-
                                                   tion and 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.

Joanne L. Alexander (9)          Corporate         Vice   President,   General   Counsel  and          --
Calgary, Alberta; Canada         Secretary         Corporate  Secretary  of  the  Corporation
                                                   since January 2007.  Prior thereto General
                                                   Manager,    Stakeholder   Engagement   and
                                                   Regulatory   Affairs   at   ConocoPhillips
                                                   Canada from April 2006 to January 2007 and
                                                   prior  thereto Vice  President,  Legal and
                                                   Corporate    Secretary    of    Burlington
                                                   Resources Canada Ltd. since May 2000.
</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)  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  subsequently  ceased  traded  for  failing  to  file
     financial statements and other related documents.
(8)  Appointed to the Board and Committees effective January 1, 2007.
(9)  Charles W. Berard  resigned as Corporate  Secretary in connection with the
     appointment of Ms. Alexander.


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 February  21,  2007,  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 3,486,578 Common
Shares or approximately 2% of the issued and outstanding  voting  securities of
the  Corporation.  Not included in the amount above is 5,138,581  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, banking relationships or relationships with companies
that have competing  businesses 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>
                                     -32-


                                AUDIT COMMITTEE


COMPOSITION AND QUALIFICATIONS

The Audit Committee consists of four outside independent  directors:  Robert G.
Puchniak (Chair), Randall Oliphant,  Oyvind Hushovd and Fred Dyment all of whom
are  financially  literate.  Mr.  Dyment was  appointed to the Audit  Committee
commensurate with his appointment to the Board of Directors on January 1, 2007.

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 Board of Directors  reviews  committee  membership  periodically  to ensure
appropriate utilization of expertise,  experience and time of the Corporation's
directors.  Changes to committee membership occur from time to time as a result
of this assessment.

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 & Gas Limited,  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,  Strad Energy  Services Ltd 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.
Mr. Puchniak has been determined to be an "Audit Committee financial expert".

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 Bachelor
of  Commerce  Degree  from  the  University  of  Toronto  and  is  a  Chartered
Accountant.  Mr.  Oliphant  has  been  determined  to  be an  "Audit  Committee
financial expert".

<PAGE>
                                     -33-


OYVIND HUSHOVD, INDEPENDENT DIRECTOR

Mr.  Oyvind  Hushovd was the  Chairman and Chief  Executive  Officer of Gabriel
Resources Ltd., a public mining corporation, from March 2003 to May 2005. Prior
to that, he was the President and Chief Executive Officer of Falconbridge Ltd.,
a public mining  corporation,  from 1996 to February  2002. Mr. Hushovd holds a
Masters of Economics and Business  Administration  from the Norwegian School of
Business,  Bergen and a Master of Law from the  University of Oslo. Mr. Hushovd
has been determined to be an "Audit Committee financial expert"

FRED DYMENT, INDEPENDENT DIRECTOR

Mr. Dyment is currently is an independent  businessman  and serves on the Board
of Directors of Tesco  Corporation and ZCL Composites Inc., two leading design,
manufacture and service companies. In addition, Mr. Dyment is a director of ARC
Energy Trust and Transglobe Energy Corporation.  Previously,  he spent the bulk
of his career at Ranger Oil Limited  holding the positions of Controller,  Vice
President Finance, Chief Financial Officer and finally Chief Executive Officer.
After Ranger Oil Limited was sold to Canadian  Natural  Resources  in 2000,  he
served as CEO of Maxx  Petroleum  Company  from 2000 to 2001.  Mr.  Dyment also
served as Governor of the Canadian  Association of Petroleum  Producers  (CAPP)
from 1995 - 1997. He holds a Chartered Accountant  designation.  Mr. Dyment has
been determined to be an "Audit Committee financial expert"


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.

<PAGE>
                                     -34-


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, 2006 and December
31, 2005

                                             2006(1)                  2005
                                             -------                  ----
         Audit Fees                       $296,529(2)            $146,396(4)
         Tax Fees                           Nil(3)                 $133,108
------------------------------------------------------------------------------
         TOTAL                             $296,529                $279,504

Notes:
(1)  Paid or estimated to be payable for 2006 services.
(2)  Includes  $160,000  related to initial year of  compliance  with  Sarbanes
     Oxley legislation.
(3)  Western  engaged  independent  tax  advisors to address  taxation  matters
     during 2006.
(4)  Includes audit fees relating to 2004 of approximately $38,000.

Audit fees were paid for professional services rendered by the auditors for the
audit of the Corporation's  annual financial  statements,  services provided in
connection  with  statutory  and  regulatory  filings and for costs  related to
professional   services   rendered  by  the  auditors  for  the  audit  of  the
Corporation's internal control over financial reporting. Tax fees were paid for
tax advice and assistance with tax audits.

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




<PAGE>
                                     -35-


                            RISKS AND UNCERTAINTIES

The Corporation is exposed to a number of risks and  uncertainties  relating to
its operations. The following is a listing of the material risks that affect or
may affect Western's stated business initiatives, however it is not meant to be
exhaustive.

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 global and  regional  supply and demand  factors  beyond  Western's
control.  Worldwide economic growth, political developments,  especially in the
Middle East,  compliance or non-compliance  with quotas imposed upon members of
the  Organization  of Petroleum  Exporting  Countries and weather,  among other
things,  can affect  world oil supply and demand and oil  prices.  Natural  gas
prices realized by Western are primarily  affected by North American supply and
demand and by prices of alternative sources of energy.

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 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.

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  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;

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

     o   entering into fixed priced swap 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

<PAGE>
                                     -36-


increases. In addition, by entering into these hedging activities,  Western may
suffer financial loss if it is unable to produce  sufficient  quantities of oil
or have sufficient cash flow 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.

FLUCTUATIONS  IN THE US AND CANADIAN  DOLLAR  EXCHANGE RATE MAY CAUSE WESTERN'S
OPERATING COSTS AND CAPITAL COSTS RELATING TO AOSP EXPANSION 1 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 certain 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.

Secondly,  a portion of the capital costs associated with AOSP Expansion 1 will
be denominated in US dollars. Capital costs may rise when converted to Canadian
dollars should the Canadian dollar weaken against that of the US dollar.

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.  In addition the differential to
West Texas  Intermediate for certain product streams can vary  dramatically and
can have a material impact on Western's revenues.

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 may have lower operating costs and may have proprietary downstream assets.
The crude oil industry  also  competes with other  industries  and  alternative
energy sources in supplying energy, fuel and related products to consumers.

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;

<PAGE>
                                     -37-


     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.  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.

Processing of bitumen ore is dependant on ore quality.  As the mining  operator
mines  the  pit,  mixing  techniques  are  employed  to  produce  a  consistent
bituminous sand from the mine to manage ore quality and optimize  throughput at
the mine site. There can be no assurances that future ore qualities will remain
at current levels which could potentially result in lower throughput and higher
costs.

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
     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.

<PAGE>
                                     -38-


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.

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  remaining  areas  of Lease 13 in
addition to Shell's Other Athabasca  Leases and the AMI Leases.  The Owners are
evaluating potential long-term development  opportunities relating to resources
contained  within  Lease 13 and  Shell's  Other  Athabasca  Leases  and the AMI
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.

STATUS OF THE FIRST EXPANSION OF THE ATHABASCA OIL SAND PROJECT.

Expansion 1 will be entering the  construction  stage.  Western's  share of the
total costs to construct  the  Expansion 1 has been  estimated at $2.2 billion.
There is a risk that the Expansion 1 will not be completed on time or on budget
or at all.  Additionally,  there  is a risk  that  Expansion  1 may  experience
delays,  result in  interruption of existing  mineable  operations or increased
costs due to many factors, including, without limitation:

     o   inability to attract sufficient numbers of qualified workers;
     o   breakdown or failure of equipment or processes;
     o   construction  performance  falling below expected  levels of output or
         efficiency;
     o   changes in scope;
     o   shortages of, or delays in obtaining equipment, construction materials
         or services;
     o   increases in materials or labour costs;
     o   contractor or operator errors;
     o   non-performance by, or financial failure of, third party contractors;
     o   disruption or delays in availability of transportation services;
     o   delays in obtaining, or conditions imposed by, regulatory approvals;
     o   design errors;
     o   errors in construction
     o   start-up and commissioning;

<PAGE>
                                     -39-


     o   labour disputes, disruptions or declines in productivity;
     o   adverse weather conditions affecting construction or transportation;
     o   transportation or construction accidents;
     o   unforeseen site surface or subsurface conditions;
     o   violation of permit requirements;
     o   disruption in the supply of energy; and
     o   catastrophic events such as fires, earthquakes, storms or explosions.

Given the stage of development of the Expansion 1, various  changes may be made
prior to the Owners completing the Expansion 1. Based upon current  scheduling,
full  start-up  of  Expansion  1 is  expected  in late  2010.  There  can be no
assurances  that the current  construction  schedules  will continue as planned
without any delays or on budget. Any such delays will likely increase the costs
of the Expansion Project and may require additional financing.

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

If Western does not participate in certain future expansions, some of Western's
voting  interests  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 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 on Shell's Other Athabasca  Leases and will 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, there can be no assurance that
Western  will  be  able  to  fund  its  share  of  the   expansion.   Western's
participation  in any  expansion  would  be  subject  to  numerous  conditions,
including Western's  satisfaction with feasibility studies and Western's access
to the necessary capital resources.

UPGRADING CAPACITY BEYOND THE EXPANSION 1 HAS NOT BEEN SECURED.

Expansions  beyond  Expansion  1 will not  include a joint  upgrading  solution
therefore  management  continues to pursue alternate  downstream  solutions for
future  volumes beyond  Expansion 1. However,  there can be no assurance that a
downstream solution can be found in time to process additional volumes from the
future planned  expansions.  This could result in significantly  lower realized
prices from  selling  bitumen  rather than a synthetic  crude blend as planned.
Additional  capital  funding and a commitment of management  resources  will be
required to identify, develop and implement a downstream solution.

Western has engaged third party  advisors to assist in these  activities  which
will involve  contacting  third  parties.  This may result in an acquisition or
sale  of  assets,  merger  or  other  corporate  transaction.  There  can be no
assurances that any of these  activities will result in the  consummation of an
agreement or transaction or result in any change to Western's  current  ongoing
business strategy.

COMPETITION FOR LABOUR AND MATERIALS.

With the  expansion  of the  industry  and the  impact of new  entrants  to the
business, risks in the form of availability/competition  for skilled labour and
materials  supply  continue  to build.  There  are  other  oil  sands  projects
currently under construction and significant  expansions have been announced by
other oil sands developers. Western anticipates that some of these projects and
expansions will proceed in the same time frame as its proposed expansions. This
means Western will compete with these other projects for  equipment,  supplies,
services, and labour in this environment which could result in increased costs,

<PAGE>
                                     -40-


shortages  of goods and  services  that delay  progress,  or both.  In addition
participation  in  expansions  will  significantly   increase  the  demands  on
Western's management and administrative  resources.  Western may not be able to
effectively  manage  the  expansions,  and any  failure  to do so could  have a
material adverse effect on Western's  business,  financial condition or results
of operations.

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 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.

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 products.

SHELL AND CHEVRON MAY NOT AGREE WITH WESTERN ON MATTERS  RELATED TO THE PROJECT
INCLUDING EXPANSION 1.

The Project including  Expansion 1 is a joint venture among Shell,  Chevron and
Western.  Future plans,  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 unit 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 OR EXPANSION 1.

Western is subject  to the risk of  non-payment  by Shell or Chevron in meeting
their payment  obligations to the Project including  Expansion 1. 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  certain  of  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 its obligations under the Joint Venture
Agreement,  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  fair  market  value  (subject  to  certain  adjustments  for  future
reclamation costs).

<PAGE>
                                     -41-


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

Western  sells  its  share of  vacuum  gas oil  produced  by the  Project  to a
subsidiary of Shell on a long-term basis. Since a large portion of our revenues
will be received from a subsidiary of Shell,  Western will have a concentration
of credit risk. Furthermore, if the Shell subsidiary 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 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  subsidiary 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
subsidiary, or at all.

Additionally, the price Western receives for products sold to the subsidiary 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  subsidiary  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.

PRODUCTION FROM EXPANSION 1 MAY NOT MEET THE PLANNED SCHEDULE OR BUDGET.

There is a risk that production from Expansion 1 may not commence when planned,
or at the costs  anticipated.  Many factors in addition to the risks  described
below under "Risk  Factors - The Mine,  Extraction  Plant and  Upgrader may not
perform as planned"  could impact the pace of Expansion 1 start-up and economic
efficiency of production including:

     o   the operation of any part of Expansion 1 falling below expected levels
         of performance, output or efficiency; and

     o   unanticipated or unplanned  shutdowns or curtailments of any component
         of the Expansion 1.

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  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.

IN-SITU EXTRACTION MAY NOT BE ECONOMIC OR SUSTAINABLE.

In-situ  developments  are  based on  expectations  of  successful  exploration
drilling  results.  While the Athabasca  resource in composite is  significant,
lease  specific  resource  qualities may vary greatly and can only be confirmed
through exploration and full delineation.  Only after this drilling is complete
and feasibility studies of the appropriate  technology to apply to the resource
are done can the potential of there resource be quantified.

<PAGE>
                                     -42-


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.

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 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,  2006,  Western  had  approximately  $723  million of debt
(including  obligations  under the HMU lease and net option  premiums  deferred
associated  with Western's  strategic crude oil hedging  program).  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.

WESTERN  MAY  NOT  BE  ABLE  TO  SECURE   FINANCING  FOR  FUTURE   EXPLORATION,
DEVELOPMENT, PRODUCTION, EXPANSION AND ACQUISITION PLANS.

Depending  on  Western's  future   exploration,   development,   production  or
acquisition plans, Western may require additional financing. The ability of the
Corporation  to arrange  such  financing in the future will depend in part upon
prevailing  financing market conditions as well as the business  performance of
Western. If Western's petroleum's revenues or reserves decline, it may not have
the capital  necessary  to undertake or complete  future  drilling  programs or
expansions.  There can be no  assurance  that debt or equity  financing or cash
generated  by  operations  will  be  available  or  sufficient  to  meet  these
requirements or for other corporate purposes or, if debt or equity financing is
available,  that  it will  be on  terms  acceptable  to  Western.  Transactions

<PAGE>
                                     -43-


financed partially or wholly with debt may increase Western's debt levels above
industry  standards.  The inability of Western to access sufficient capital for
its operations and planned  expansions  could have a material adverse effect on
Western's business and financial  condition.  If additional financing is raised
by the  issuance  of shares from  treasury  of Western,  control of Western may
change and shareholders may suffer dilution.

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.

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,  royalties,
transportation,  production,  exports,  labour standards,  occupational health,
waste  disposal,  protection  and  remediation of the  environment,  aboriginal
matters, 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 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 any expansions,  and the mining,
oil sands and oil and gas industries generally, will not be changed in a manner
which may adversely affect Western.

Oil sands  leases may be subject to the OIL SANDS TENURE  REGULATION  (Alberta)
which was introduced in 2000. This legislation deems certain leases to continue
beyond  their  primary  term to the extent  that the lessee  has  attained  the
minimum level of  evaluation of the oil sands or the lease 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 their leases.  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 certain leases may be in question.

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

<PAGE>
                                     -44-


enforcement policies thereunder,  and claims for damages 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
(including any  expansions)  will be a significant  producer of some greenhouse
gases covered by the treaty.  The Government of Canada  indicated it intends to
put forward an emission reduction plan for Canada and Clean Air Act legislation
that 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 not be
achievable or 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 percent undivided interest in the Project,  is subject
to a  provincially  administered  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.

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,  individual
shareholders  can reduce their income subject to personal income taxes.  During
the third quarter of 2006, it was communicated to Western that the CRA proposes
to challenge the characterizing of certain expenditures capitalized as Canadian
Exploration  Expense which were incurred in 2001 and 2002. If CRA is successful
in  assessing  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. if
such renunciations are reduced under the Income Tax Act (Canada).

<PAGE>
                                     -45-


ABORIGINAL  CLAIMS  MAY BE  MADE  AGAINST  WESTERN  OR THE  PROJECT,  INCLUDING
EXPANSION 1.

Aboriginal  peoples may make claims  against  Western or the Project  including
Expansion 1, regarding the lands on which the Project including Expansion 1 are
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.

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 and may not
be related to the oil sands industry.  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,  acts of terrorism 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.

EXPLORING  IN  THE  FEDERAL  REGION  OF  KURDISTAN,  POLITICAL  AND  REGULATORY
INSTABILITY

In May 2006,  Western,  through  its  wholly  owned  subsidiary,  WesternZagros
Limited,  entered  into the EPSA  with the  Kurdistan  Regional  Government  to
explore for conventional oil and gas in the Federal Region of Kurdistan pending
ratification  by the KRG. The Federal  Region of Kurdistan is in Northern Iraq.
Iraq is  currently  experiencing  periods  of civil  unrest and  political  and
economical  instability.  Oil and gas exploration and development activities in
this jurisdiction may be affected in varying degrees by political  instability,
government  regulations  relating  to the  oil  and gas  industry  and  foreign
investors  therein  and the  policies  of other  countries  in respect of those
nations. Any changes in regulations or shifts in political condition are beyond
the control of Western and may adversely affect its business.

Operations  may be  affected  in  varying  degrees by  government  regulations,
policies or  directives  with respect to  restrictions  on production or sales,
price controls, export controls,  repatriation of income, income taxes, carried
interests  for  the  state,   expropriation   of  property  and   environmental
legislation.  Western will also be required to negotiate  property  development
agreements with the government having jurisdiction over some of its properties.
Such  government  may impose  conditions  that will affect the viability of the
project  such as  providing  the  government  with free  carried  interests  or
providing  subsidies for the development of the local  infrastructure  or other
social assistance. There can be no assurance that Western will be successful in
concluding  such  agreements  on  commercially  acceptable  terms or that these
agreements will be successfully  enforced in the foreign  jurisdiction in which
Western's  properties  are located.  Operations may also be affected in varying
degrees by political  and  economic  instability,  economic or other  sanctions
imposed by the other countries,  terrorism,  civil wars, guerrilla  activities,
military repression,  crime,  material  fluctuations in currency exchange rates
and high  inflation.  The political  status of the Kurdistan  Region on Iraq in
which  Western  operates may make it more  difficult  for Western to obtain any
required  project  financing  from senior  lending  institutions  because  such
lending  institutions may not be willing to finance projects in this region due
to the perception of investment risk.

<PAGE>
                                     -46-


No  assurances  can be given that  WesternZagros  will be able to  maintain  or
obtain  effective  security or  insurance  of any of its assets or personnel in
Iraq where, at times, terrorism and insurgent activities have disrupted various
business  activities  during the past and may affect  Western's  operations  or
plans in the future.  Current military  participation from the United States of
America and other allied  countries are operating within Iraq to assist the new
local  government to maintain peace and national  security and law and order at
the national  level.  There can be no  assurances  to the  commitment  of these
foreign  nations to continue to maintain their military  presence nor can there
be  assurances  that the  local  government  of Iraq  can  assert  the  ability
themselves to provide the  necessary  degree of peace,  order and security.  As
such, WesternZagros' ability to maintain effective security over its assets may
be adversely  impacted.  A high degree of security is also required to mitigate
the risk of loss by theft, either by Western's employees,  contractors or third
parties.

Infrastructure  development  in the  Kurdistan  Region of Iraq is  limited.  In
addition,  WesternZagros' properties are located in remote areas, many of which
are  difficult to access.  These factors may affect  WesternZagros'  ability to
explore and develop its  properties  and to store and transport its oil and gas
production.  There can be no assurance that future  instability in this region,
actions  by  companies   doing  business   there,   or  actions  taken  by  the
international  community will not have a material adverse effect on this region
and in turn on WesternZagros' financial condition or operations.

THE EPSA MAY NOT BE RATIFIED.

The EPSA is not  effective  until  it is  passed  into  law.  Although  Western
continues to work towards  ratifying  the EPSA,  there is no assurance  that it
will be  passed  into law and  thus may not be  effective.  Any  change  in the
Kurdistan  local or Iraqi  national  government or  legislation  may affect the
status of  WesternZagros'  contractual  arrangements or its ability to meet its
contractual  obligations and may result in the loss of its interests in its oil
and gas properties. The laws of Canada do not apply to any of these contractual
arrangements and no assurances can be given that these contractual arrangements
will be  enforced  or  interpreted  in the same manner or to the same extent as
would be the case if the laws of Canada did apply.

TERMS OF THE EPSA, IF RATIFIED, MAY DIFFER FROM THOSE OF THE INITIAL CONTRACT.

The terms of the initial EPSA may be modified from those previously  negotiated
in the  spring of 2006 as a result of the  ratification  process.  There is the
possibility  that these amended terms, if agreed to by all parties,  may reduce
the economic  value  attributable  to  WesternZagros.  These  amended terms may
include,  but are not limited to,  modifications  to concession  area, term and
work commitments.

TITLE MATTERS IN THE FEDERAL REGION OF KURDISTAN

As a result of the  limited  infrastructure  present in the  Federal  Region of
Kurdistan,  land titles  systems are not  developed to the extent found in many
industrialized nations and Western is subject to potential competing claims.

No  assurance  can be given that  applicable  governments  will not revoke,  or
significantly   alter  the  conditions  of,  the  applicable   exploration  and
development   authorizations   and  that  such   exploration   and  development
authorizations will not be challenged or impugned by third parties. There is no
certainty that such rights or additional  rights applied for will be granted or
renewed on terms satisfactory to WesternZagros.  There can be no assurance that
claims by third parties against WesternZagros'  properties will not be asserted
at a future date.

<PAGE>
                                     -47-


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

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
percent ownership interest in the AOSP and also through direct investments made
by Western into oil sands, through the ESPA and other ventures with significant
long-life hydrocarbon resource potential.

Western's 20 percent  ownership  interest in the AOSP gives Western the option,
upon satisfying  certain  conditions,  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  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,  economic,
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.

Western's future international conventional oil and natural gas exploration may
involve unprofitable  efforts, not only from dry wells, but from wells that are
productive but do not produce  sufficient net revenues to return a profit after
drilling,  operating  and other costs.  Completion  of a well does not assure a
profit on the  investment  or recovery of drilling,  completion  and  operating
costs.  In addition,  drilling  hazards or  environmental  damage could greatly
increase the cost of operations  and various  field  operating  conditions  may
adversely affect the production from successful wells.

Whether  Western  ultimately  undertakes an exploration or development  project
depends upon a number of factors,  including  availability and cost of capital,
current and  projected  oil and gas prices,  receipt of  government  approvals,
access to the property,  the costs and  availability of drilling rigs and other
equipment,  supplies  and  personnel  necessary  to conduct  these  operations,
success or failure of  activities in similar areas and changes in the estimates
to  complete  the  projects.  Failure by the  Corporation  to secure  necessary
equipment could adversely affect the Western's business,  results of operations
or financial condition.

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.

<PAGE>
                                     -48-


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 pre-tax 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, 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.

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.

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.

<PAGE>
                                     -49-


FUTURE  LITIGATION  COULD  ADVERSELY  AFFECT  WESTERN'S  BUSINESS,  RESULTS  OF
OPERATIONS OR FINANCIAL CONDITION.

From  time to  time,  Western  is  subject  to  litigation  arising  out of its
operations.  Damages  claimed under such  litigation  may be material or may be
indeterminate,  and  the  outcome  of such  litigation  may  materially  impact
Western's business, results of operations or financial condition. While Western
assesses the merits of each lawsuit and defends itself  accordingly,  it may be
required to incur  significant  expenses  or devote  significant  resources  to
defending itself against such litigation.  In addition,  the adverse  publicity
surrounding  such  claims  may have a  material  adverse  effect  on  Western's
business.


                         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

GLJ  Petroleum  Consultants  Ltd.,  independent  petroleum  consultants  to the
Corporation,  prepared the GLJ Reserve Report and Contingent  Resource  Report,
both  referenced  herein.  As at  the  date  of  the  respective  reports,  the
principals  of Norwest  and GLJ,  as  respective  groups,  owned  beneficially,
directly or indirectly,  less than 1% of the  outstanding  Common  Shares.  GLJ
neither  received nor 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 reports.


                               LEGAL PROCEEDINGS

There are no legal proceedings which Western is a party to that involve a claim
for damages that exceed ten percent of the current  assets of Western.  Western
is however involved in arbitration  proceedings  arising from insurance claims.
See "Narrative  Description of the Business - The Athabasca Oil Sands Project -
Mining - Base Operations".


                             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>


                                    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;

"AMI LEASES" Oil sands  leases in the  Athabasca  oil sands region  (other than
Shell's  other  Athabasca  leases) which are acquired by an Owner and which are
subject to the Participation and AMI Agreement.

"AOSP"  or  the  "PROJECT"   Athabasca  Oil  Sands  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
Lease 13 in addition to any Bitumen  Recovery Project  implemented  pursuant to
the Participation and AMI Agreement;

"ATCO"  ATCO Power Canada Limited;

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

"CHEVRON"  Chevron Canada Limited;

"COGE HANDBOOK" Canadian Oil and Gas Evaluation Handbook;

"COMMON SHARES"  The Class A shares of Western;

"DOW"  Dow Chemicals Canada Inc.;

"ELLS RIVER  PROJECT"  Chevron's  proposed oil sands  in-situ  project which is
located approximately 50 kilometers northwest of Fort McMurray in the Athabasca
Oil Sands region;

"EPSA"  Exploration and Production Sharing Agreement dated May 4, 2006 with the
Kurdistan  Regional  Government to explore for  conventional oil and gas in the
Federal Region of Kurdistan;

"EXPANSION  1"  The  fully   integrated   expansion  of  the  existing  Project
facilities,  with both new mining  operations  which includes the Jackpine Mine
and associated  additional  bitumen  upgrading at the Scotford  Upgrader,  with
construction of common upstream infrastructure to support future expansions;

"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;

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

"GLJ  RESERVES  REPORT"  The  report  prepared  by GLJ dated  February  7, 2007
evaluating the reserves attributable to Western as of December 31, 2006;

<PAGE>
                                     -51-


"GLJ CONTINGENT RESOURCE REPORT" The report prepared by GLJ dated February 7,
2007 evaluating the mineable resources attributable to Leases 88, 89, 90, 9 and
the remainder of Lease 13 not included in the Muskeg River Mine or the Jackpine
Mine and after giving effect to the swaps with Syncrude Canada and Imperial
Oil, as well as Permits 15 and 631;

"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;

"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,  the western portion of which is the site
for the Muskeg River Mine and the eastern  portion of which is the site for the
Jackpine Mine;

"MD&A"  Management Discussion & Analysis;

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

"MMBBLS"  Millions of barrels;

"MUSKEG RIVER MINE" or "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;

"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" or "JOINT VENTURE 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;

"PARTICIPATION AND AMI AGREEMENT" The Participation and Area of Mutual Interest
Agreement dated December 6, 1999 among the Owners;

"PIERRE RIVER MINE" The anticipated expansion area to be developed by the Joint
Venture  as  Expansions  4 and 5,  physically  located  on the west side of the
Athabasca River, initially on Leases 9 and 17;

"SAGD"  Steam-assisted gravity drainage;

<PAGE>
                                     -52-


"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;

"SHELL"  Shell Canada Limited; and

"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,  740512031,  AT30  -  728009AT30,  AT34 -
728011AT34,  BT31 - 728010BT31,  AT36 - 728101AT36,  BT30 - 728009BT30  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 evaluated the Corporation's  reserves data as at December 31, 2006. The
     reserves data consist of the following:

     (a)  (i)  proved and proved plus  probable oil and gas reserves  estimated
               as at December 31, 2006, 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, 2006,
               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, 2006,  and identifies the
     respective  portions thereof that we have evaluated and reported on to the
     Corporation's board of directors:

<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>
     February 7, 2007     Canada     0             $3,868 MM$   0           $3,868 MM$
</TABLE>

<PAGE>
                                      -2-


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.

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

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

Executed as to our report referred to above:

GLJ Petroleum Consultants Ltd.,
Calgary, Alberta, Canada                                 Dated: February 7, 2007

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, 2006 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, 2006
               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.

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

<PAGE>
                                      -2-


(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

February 22, 2007



<PAGE>


                                   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 approve,  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 or any other  document  required to be
          filed  or  publicly   disclosed  pursuant  to  applicable  legal  and
          regulatory requirements;

     (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

<PAGE>
                                      -2-


          position of the  Corporation,  and the manner in which these  matters
          may be, or have been, disclosed in the financial statements;

     (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,  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;

<PAGE>
                                      -3-


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

     (c)  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;

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

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

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

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

     (h)  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,  experience 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 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

<PAGE>
                                      -4-


     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 and shall be reviewed at least annually.

     If a member of the Audit  Committee  ceases to be independent  for reasons
     outside that member's  reasonable  control,  the member shall  immediately
     notify the Chair of the Board as to this fact and shall  resign his or her
     position  as a member of the Audit  Committee  on the  earliest of (i) the
     appointment  of his or her  successor;  (ii) the next  annual  meeting  of
     shareholders  of the  Corporation;  and (iii) the date that is six  months
     from the  occurrence  of the  event  which  caused  the  member  to not be
     independent.

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,  provided
     that  meetings  shall be  scheduled so as to permit  timely  review of the
     quarterly and annual financial  statements and reports.  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.

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                                      -5-


6.   QUORUM

     A majority of the members of the Audit Committee,  present in person or by
     telephone  or by other  telecommunication  device that  permits all person
     participating  in the  meeting  to  communicate  with  each  other,  shall
     constitute a quorum.

7.   PROCEDURE, RECORDS AND REPORTING

     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.