EXHIBIT 3
                                                                       ---------


MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion of financial condition and results of operations was
prepared as of February 25, 2005 and should be read in conjunction with the
Consolidated Financial Statements and Notes thereto. It offers Management's
analysis of our financial and operating results and contains certain
forward-looking statements relating but not limited to our operations,
anticipated financial performance, business prospects and strategies.
Forward-looking information typically contains statements with words such as
"anticipate", "estimate", "expect", "potential", "could", or similar words
suggesting future outcomes. We caution readers to not place undue reliance on
forward-looking information because it is possible that predictions, forecasts,
projections and other forms of forward-looking information may differ materially
from actual results achieved by Western. Western does not maintain a policy nor
is under any obligation to update publicly or revise any forward-looking
information contained in the following discussion of financial condition and
results of operations as a result of new information or events.

         By its nature, our forward-looking information involves numerous
assumptions, inherent risks and uncertainties. A change in any one of these
factors could cause actual events or results to differ materially from those
projected in the forward-looking information. These factors include, but are not
limited to, the following: market conditions, law or government policy,
operating conditions and costs, project schedules, operating performance, demand
for oil, gas, and related products, price and exchange rate fluctuations,
commercial negotiations or other technical and economic factors.

         Additional information relating to Western, including our 2004 Annual
Information Form, is available at www.sedar.com.

OVERVIEW

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

         At this time, Western's 20 per cent investment in the AOSP is our only
material asset. We generate revenue from the sale of our 20 per cent portion of
the synthetic crude oil produced at the Scotford Upgrader. Currently our
processes produce two grades of crude oil: Premium Albian Synthetic (PAS) and
Albian Heavy Synthetic (AHS). Another one-third of the volumes produced are a
mixture of light, medium and heavy vacuum gas oil (LMHVGO) which is sold to
Shell Canada Products under a long-term contract for use in their adjacent
refinery.

         After a three and a half year construction phase, the AOSP began
producing bitumen and synthetic crude oil. Western commenced commercial
production from the Project on June 1, 2003 and production has steadily
increased since that time. Oil sands mining and upgrading processes such as
those used at our AOSP are highly complex and technical operations that
integrate many established mineral extraction and chemical processes to mine oil
sands deposits and extract and upgrade the bitumen. Our teams of project
operators at Muskeg River and Scotford are constantly adjusting and fine tuning
the processes - what we call the ramp-up phase - to optimize the operations and
production from the Project. We are also at the early stages of planning the
expansion involving other leases available to the Joint Venture.


                                     Page 1
<PAGE>

         The Joint Venture is currently developing and producing from the
western portion of Lease 13. Numerous expansion opportunities exist, including
expanding the existing Muskeg River Mine operations, moving into the undeveloped
eastern portion of Lease 13 and five other nearby oil sands leases owned by
Shell, referred to as Leases 88, 89, 90, 9 and 17. Permit and feasibility
studies for multiple expansions are now underway. The first expansion phase is
expected to be sanctioned by early 2006. Components with long lead times will be
ordered by the end of 2005. This will position the Joint Venture to begin
construction in 2006 at a total capital cost for the first expansion of $4.0 to
$4.5 billion. This first expansion, together with de-bottlenecking initiatives,
is expected to increase the productive capacity of the AOSP by 74 to 94 per cent
depending on performance variables from 270,000 to 300,000 barrels per day
(54,000 to 60,000 barrels per day net to Western).

         In April 2004, the Project received federal and provincial cabinet
approvals to develop the eastern portion of Lease 13, known as the Jackpine Mine
- Phase 1. This expansion project has the potential to add 200,000 barrels per
day (40,000 barrels per day net to Western) of bitumen production. Phase 2 of
the Jackpine Mine Expansion could contribute a further 100,000 barrels per day
(20,000 barrels per day net to Western) and would include Leases 88 and 89.
Since this permit was received, the Owners have been evaluating other expansion
options, one of which is to execute multiple 90,000 to 100,000 barrel per day
single train projects, back-to-back on an accelerated basis, leading to 500,000
to 600,000 barrels per day (100,000 to 120,000 barrels per day net to Western)
at full development with the current suite of leases available to the Owners.
The capital cost of future phases should be optimized through continuous
construction and capitalizing on the utilization of similar extraction and
upgrading processes for all trains. The timing and details of any expansion will
be subject to the outcome of future evaluations of economics, market needs,
regulatory requirements and to sustainable development considerations.

         The resources underlying these leases are significant. The west side of
Lease 13 has been independently evaluated and is estimated to contain 1.6
billion barrels of reserves (317 million barrels net to Western). It is further
estimated that the Project's other resources total 8.1 billion barrels (1.6
billion barrels net to Western). These amounts represent mineable oil sands
only. The Project's reserves and resources are but one component of the overall
Alberta oil sands resources which, based on recoverable barrels alone,
represents the world's largest oil deposit outside of Saudi Arabia

         Fiscal 2004 represented the first year of 12 consecutive months of
commercial operations of the AOSP. It was a year characterized by continued
learning, ongoing challenges, and success in overcoming most of those
challenges. Our goal in 2004 was to achieve steady and continuous improvement in
all areas of operations including health, safety, environment and other
sustainability programs, production volumes and production costs. We achieved
all of these objectives in 2004 with the exception of production volumes in the
fourth quarter. Unfortunately, during the fourth quarter, we experienced
operational issues including unplanned maintenance at both the Mine and the
Upgrader, which reduced the annual production rate to 135,542 barrels per day
compared to the average rate of 144,135 barrels per day for the nine-month
period ending September 30, 2004. In August, we realized record daily bitumen
production of 197,000 barrels and record monthly production of 182,000 barrels
per day. Both these levels are well above the stated design capacity of 155,000
barrels per day and were in line with our ramp-up objectives. Despite the
disappointing performance during the fourth quarter of 2004, annual production
increased 15 per cent over the 117,980 barrels per day achieved in 2003. Average
production in 2004 represents 87 per cent of the design capacity rate. The
Project has clearly moved beyond the construction phase and we believe
sustainable production design rates will be achieved in 2005. At the same time,
future growth will accelerate.

         In 2004, our Health, Safety and Environment ("HS&E") performance was
strong. The Project recorded positive results for the Lost Time Injury Frequency
("LTIF") and, on a Total Recordable Injury Frequency ("TRIF") basis, the results
were outstanding. At 0.78, we outperformed the industry average by 30 per cent
over


                                     Page 2
<PAGE>

the course of 2004. We recorded no Class 21 environment incidents. These results
underscore our commitment to operating our HS&E program at the highest possible
level.

(1) A minor effect. An incident sufficiently large to impact the environment.
Single breach of statutory or prescribed limit, or single complaint. No
long-term effect on the environment.

         During 2004, we consolidated a plan for continuous improvement and
identified nine key areas to be addressed by the end of 2005. These areas
included: health, safety and the environment, production and cost performance,
bitumen recovery from variable ore grades, equipment and plant reliability,
equipment design deficiencies, wear rates, energy efficiency, technology
enhancements and personnel training. Our greater understanding of each of these
areas will impact and enhance our success during the de-bottlenecking and
expansion phases in which we are now fully engaged.

OPERATING RESULTS - HIGHLIGHTS

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

<TABLE>
<CAPTION>
                                                                       2004                 2003               2002
-------------------------------------------------------------------------------------------------------------------
<S>                                                              <C>                  <C>                <C>
OPERATING DATA
     Bitumen Production (bbls/d)                                     27,108               23,596                 --
     Synthetic Crude Sales (bbls/d)                                  36,210               32,207                 --
     Operating Expenses per Processed Barrel ($/bbl)                  21.17                20.71                 --

FINANCIAL DATA ($ thousands, except as indicated)
     Revenues                                                       636,911              281,093                 --
     Realized Crude Oil Sales Price -
       Oil Sands ($/bbl) (1) (2)                                      34.60                32.81                 --
     Cash Flow from Operations (3)                                   23,044                5,803             (8,603)
     Cash Flow per Share - Basic ($/Share) (1) (4)                     0.44                 0.12              (0.18)
     Net Earnings (Loss) Attributable to
       Common Shareholders (6)                                       19,452               15,003            (10,286)
     Net Earnings (Loss) per Share ($/Share)
       Basic                                                           0.37                 0.30              (0.21)
       Diluted                                                         0.37                 0.29              (0.21)
     EBITDAX (1) (5)                                                 87,587               47,615             (5,698)
     Net Capital Expenditures (7)                                    39,968              148,473            527,541
     Total Assets                                                 1,470,870            1,458,424          1,359,638
     Long-Term Financial Liabilities                                662,620              860,580            775,820
     Weighted Average Shares Outstanding -
       Basic (Shares)                                            52,308,838           50,344,332         48,330,320
-------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Please refer to page 58 for a discussion of Non-GAAP financial measures.
(2)  The realized crude oil sales price is the revenue derived from the sale of
     Western's share of the Project's synthetic crude oil, net of the risk
     management activities, divided by the corresponding volume. Please refer to
     page 33 for calculation.
(3)  Cash flow from operations is expressed before changes in non-cash working
     capital.
(4)  Cash flow per share is calculated as cash flow from operations divided by
     weighted average common shares outstanding, basic.
(5)  Earnings before interest, taxes, depreciation, depletion, amortization,
     stock based compensation, accretion on asset retirement obligation and
     foreign exchange as calculated on page 42. 2003 has been restated to
     exclude $0.3 million of stock-based compensation.
(6)  Western has not paid cash dividends in any of the above referenced fiscal
     years.
(7)  Net capital expenditures are capital expenditures net of any insurance
     proceeds received during the period.


                                     Page 3
<PAGE>

PRODUCTION

MINE SITE

During the early part of 2004, we reached a significant milestone with respect
to our mine development. Mineable oil sands are present in depths ranging from
50 to a few hundred feet below the surface. As with most ore bodies, different
grades persist throughout. With respect to mineable oil sands, generally
speaking, the higher grade ore is located near the lowest point and, with
massive operations such as ours, it takes considerable time to increase the size
of the pit in order for the deepest ore to be effectively mined. Consequently,
access to the highest grade ore allows us, in turn, to freely access the full
range of ore types available on our lease. This provides us with the first
opportunity since start-up in early 2003 to feed the extraction plant with a
representative blend that it has been designed to accept. After we were able to
provide this blend, the Albian team was in a position to set the production
records noted earlier. Technical innovation in the plant's primary separation is
now a central focus. Early indications from some of these initiatives are very
encouraging and, if results are sustainable, we will be in a position to unlock
further value from our reserves through improved bitumen yields from the mine
site. This improved bitumen yield will result in more efficient extraction,
increased bitumen recovery and our ability to process lower grade ores, which
will lead to real value creation by lowering costs and increasing mine life.


UPGRADER

Following an excellent start-up in early 2003, we began 2004 with great
expectations, many of which were realized. The production records noted earlier
require the sustained operation of an integrated system including the Mine,
Upgrader, connecting pipelines, cogeneration facilities, and an array of other
plant and equipment. Time and experience play an important role in anticipating
problems and responding effectively to the Upgrader's complexity. In the fourth
quarter, these elements were challenged as it was a struggle to run both trains
trouble-free. In October 2004, a pump failure caused the shutdown of one of the
two production trains, reducing production to approximately 65 per cent of
design capacity at the Upgrader. The repairs were completed successfully;
however, an operational error during start-up resulted in another issue and, for
safety reasons, it was decided to delay a restart in order to inspect other
parts of the process that could have also been affected. Taking advantage of
this delayed start-up, we advanced some of the maintenance work scheduled for
2005. As a result, the full maintenance shutdown for the AOSP originally planned
for 2005 may not be necessary. The maintenance and repairs on the production
train at Scotford were completed by the end of January, and we have ramped back
up to full production. The result of this repair work was unsatisfactory fourth
quarter performance following an outstanding third quarter, and we ended 2004
knowing a great deal more about how to operate and maintain this plant. We are
confident that the experience gained will assist us in our objective of
continuous improvement as we progress into 2005.


EXPANSIONS

GROWTH INITIATIVES

As a partner in the AOSP, Western is in a strong growth position with
substantial additional resources available for development. These resources are
capable of supporting production increases of three to four times current
production levels. Western, together with its partners, is focused on the bigger
picture of fully developing this resource base from its initial base output of
155,000 barrels per day to between 500,000 and 600,000 barrels per day. With
construction and start-up of the base project now complete, the partners are
optimizing these facilities through a process which we refer to as the
de-bottlenecking phase. Concurrently, we are building an extensive owners team
which, by year-end 2005, will be at an advanced stage of planning for the first
phase of our major expansion. We see our growth over the next ten years
following a course that will include:


                                     Page 4
<PAGE>

o    de-bottlenecking of the base project;

o    environmental studies, engineering and construction management planning for
     our first major expansion with subsequent back-to-back expansions to
     follow;

o    reserve acquisitions; and

o    other value creation initiatives.


DE-BOTTLENECKING OF THE BASE PROJECT

The key achievement of 2004 was the ramp-up of the Project to full production.
Concurrent with that ramp-up is the process of working out the `bugs' that are
inherent in new plant operations and identifying measures which will optimize
the output of our base plant. The objective of the de-bottlenecking process is
to identify those parts of the plant that have underutilized capacity, then
accessing this additional capacity through incremental plant modifications
staged over the next three years. One such example of de-bottlenecking is the
decision to add a third tailings line at the Mine, allowing us to maintain
production while repairs and maintenance occur on one of the two lines now in
operation. Modifications are also proposed at the Upgrader to enable the
processing of the heaviest product streams into lighter, higher value crude oil
blend components. Other such initiatives include adding more extraction capacity
in the froth flotation circuit and a water cooling tower to ensure that
sufficient cooling water is present during the summer months. Through these
kinds of initiatives, the Joint Venture believes it can add 25,000 to 45,000
barrels per day of incremental production capacity at unit costs substantially
lower than our base plant costs, and bring total bitumen production to between
180,000 to 200,000 barrels per day. The Joint Venture plans to stage plant
modifications over the next three years to minimize interference to ongoing
operations and to monitor the effectiveness of each modification before
proceeding with the next.

EXPANSION PROJECTS

Progress to date has allowed us to assess the merits of the base project and
provided the tools to evaluate the appropriate size and design of subsequent
projects which will fully exploit our resource base and operate at a steady
production rate for the next 30 to 40 years. Our view of future oil prices
supports the development of an execution plan that will place us in a continuous
construction mode for the next ten years, adding additional trains back-to-back,
in a manner not dissimilar to multi-train liquid natural gas plants which have
been constructed in different parts of the world.

         The Joint Venture's first major expansion will add an incremental
90,000 to 100,000 barrels per day and it will essentially represent a third
train at both the Mine and at the Upgrader. Western's current thinking is that
successive similar sized trains will be added back-to-back over the next ten
years. We believe that in order to undertake these projects on-budget and
on-schedule, we must execute strategies which are fundamentally different from
how projects have been built in the northern Alberta landscape in the past.
Planning commenced in 2004 and by mid-2006 we will be ready for a final
investment decision on the first major expansion of the AOSP potentially
exploiting resources on the east side of Lease 13 known as the Jackpine Leases.

         The first expansion is expected to increase production to the 270,000
to 300,000 barrels per day level. Expansion projects will explore resources from
new areas, initially on Lease 13, and then extend to our other leases as
additional expansions are undertaken. Concurrent expansions of the Scotford
Upgrader would include additional hydro-conversion units and associated
utilities. The preliminary capital cost for these expansion projects is in the
range of $4 to $4.5 billion of which Western's share would be $800 to $900
million.

         Construction is expected to take place over the 2006 to 2009 timeframe
with full bitumen production anticipated in 2010. Actual timing will depend on
the outcome of the regulatory process, market conditions, final project costs
and approvals and sustainable development considerations.

RESERVE ACQUISITIONS

During 2004, Shell acquired two additional leases, 9 and 17, from EnCana
Corporation. Western is party to an Area of Mutual Interest ("AMI") and
Participation Agreement which allows us to participate in the development of
these leases. The leases are located 20 kilometers northwest of the Muskeg River
Mine. Shell estimates that Lease


                                     Page 5
<PAGE>

9 contains approximately 1 billion barrels of recoverable bitumen and could
support a mine producing 100,000 barrels per day. Lease 17 will require further
drilling and resource evaluation before data is available. Using available
information, these leases increase the resources accessible within the Joint
Venture to approximately ten billion barrels of which Western's share is
approximately two billion barrels.

OTHER INITIATIVES

Recognizing the capital intensity of mineable oil sands projects, the Joint
Venture is pursuing technology initiatives with these objectives in mind:

o    reduce energy intensity;

o    reduce environmental impact;

o    increase production barrels from our existing plant;

o    reduce operating costs; and

o    increase the value of product streams.

         These technology initiatives are included within a Joint Venture budget
which utilizes the capabilities of Shell's Calgary Research Center and other
research facilities in Alberta which specialize in oil sands technology
development. While it is premature to discuss any particular program, management
believes these initiatives will enhance the value of the Joint Venture assets
through wider margins and increased volumes with early capital payback.

         In addition, Western is pursuing its own suite of technology
development initiatives with objectives common to the Joint Venture and, if
successful, may be applied to the Joint Venture assets. These initiatives may
also afford Western the opportunity to leverage our successes to opportunities
elsewhere where we would act independent of our Joint Venture Partners. From a
broader corporate standpoint, Western's strategy is to leverage our strength as
a heavy oil producer and upgrader to other opportunities which are consistent
with our primary goal of value creation for our shareholders.


MARKETING

Western has an established marketing department responsible for creating and
marketing our share of the AOSP's produced streams. Two-thirds of our bitumen
products derived from the Upgrader, together with acquired feedstocks and
blendstocks, are upgraded and combined into saleable synthetic crude oil. Our
PAS and AHS crudes as well as requested variations of each type, are marketed
directly to refineries within North America. In addition to marketing our
proprietary volumes, we actively market displaced third-party quantities as well
as sourcing third-party volumes as required. The remaining one-third of our
production is comprised of LMHVGO and is sold under a long-term supply agreement
to Shell Canada Products.

         In 2004, we enhanced our market presence through third-party
transactions. This allowed Western to supply our customers with crude oil during
times of operational upsets as well as developing new markets, thereby creating
additional opportunities to enhance the value of our proprietary barrels. These
efforts will continue to benefit Western and increase our profile within the
crude oil industry.

         The same aggressive strategy used to introduce our two synthetic crude
oil blends in 2003 is being used to attract additional customers and find higher
valued markets. In certain circumstances, this included marketing and brokering
displaced volumes from these customers to other third parties. This innovative
approach allows refiners to assess these new crude oil blends without having to
disrupt their normal supply arrangements. Through these third-party
opportunities and our ongoing marketing efforts, we have become an active
shipper on most major crude oil pipeline systems, further enhancing Western's
status as a reliable full-service marketer of crude oil.

         Producing specific crude oil blends to target specific refineries
allows Western to maximize its returns. While our upgrading provides synthetic
crude oil with superior qualities for processing, our products lend themselves
to blending and customizing. This flexibility may lead to significant
improvements in refinery


                                     Page 6
<PAGE>

efficiencies. In addition to proprietary crude oil blending, Western continues
to work with other parties towards producing other marketable streams that will
maximize the utilization of refiners' facilities.

         Given the critical link between crude oil production at the Upgrader
and refinery requirements, Western's marketing department is heavily involved
with the Joint Venture expansion groups to ensure the expansion crude oil
quality meets refiners' needs. In late 2004, the need arose, both internally and
in the market, for the production of a new heavy oil crude product. We developed
and introduced a new crude oil stream, Albian Resid Blend ("ARB") allowing the
Joint Venture to maximize the throughput of bitumen.

         Our focus on value creation extends to other streams and feedstocks
associated with current and future production requirements. Western's marketing
group continues to work with the other Joint Venture partners to reduce yearly
natural gas consumption, effectively decreasing operating costs. Additionally,
we continue to look for opportunities to increase the netback of our Upgrader
byproduct streams, namely sulphur. These initiatives will improve our
competitive advantage within the oil sands environment.

         As we move into 2005, we will continue to build on our strengths. We
will foster new customer relationships and build on the competitive advantages
that have set us apart from other marketers. Western will remain a full
participant on industry pipeline committees, which will ensure our future crude
oil production volumes are represented to existing and new markets. We will
continue to monitor new western Canadian production (both conventional and
upgraded) initiatives and respond to new feedstock opportunities. As we continue
to grow, Western's role will be to respond to the ongoing changes in the
industry as well as meet our customers' long-term oil requirements.

         The broad market penetration achieved this year has given us a wide
customer base to position us for the next phases of our growth. Our long-term
growth strategies will provide our customers with access to secure, long-term
supplies of feedstock for their refinery facilities.

FINANCIAL PERFORMANCE

REVENUE

Western earned $636.9 million (2003 - $281.1 million) in crude oil sales revenue
in 2004, including $458.5 million (2003 - $226.2 million) from proprietary
production, at an average realized price of $34.60 per barrel (2003 - $32.81 per
barrel). Revenue rose significantly from fiscal 2003 as a result of a full year
of production during 2004, together with higher price realizations. Gross
revenues include the effects of commodity hedges which reduced revenue by $131.4
million (2003 - $8.2 million), dramatically decreasing the average realized
price by $9.92 per barrel during 2004. The Edmonton PAR benchmark averaged
$52.96 per barrel over the year, resulting in an average synthetic crude oil
quality differential of $8.44 per barrel for Western (2003 - $6.91 per barrel).
The quality differential widened in 2004 in large part due to factors that
occurred in the fourth quarter, some of which were outside Western's control
(ie. market forces and the corresponding effects on heavy crude oil prices) and
those within our control (ie. production interruptions which led to selling a
greater proportion of heavier blends). As the graph on the left indicates,
Western's sales price realizations prior to the fourth quarter were correlated
to a high degree with movements in West Texas Intermediate ("WTI"). Due to
unscheduled repairs at the Mine and the Upgrader, Western sold a greater
proportion of heavy oil streams in the fourth quarter and consequently, the
correlation to WTI weakened considerably. The market factors at the root of this
wide differential somewhat reversed themselves in January 2005 as heavy oil
differentials came more in line with historical norms.

         The quality differential continued to reflect a greater discount to
Edmonton PAR than our long-term target of $1.75 to $2.75 per barrel. While
Western is not able to control market forces, we can influence Project
operations. By improving our reliability factor, together with completing
various Upgrader optimization initiatives, lighter products will represent a
larger percentage of our overall product mix over time. This will reduce our
exposure to heavy oil price differentials. Once attained, we firmly believe that
our previously disclosed target


                                     Page 7
<PAGE>

can be achieved. In addition, we expect overall realizations to improve during
2005 as fewer proprietary barrels will be subject to fixed price hedges,
allowing us to more fully participate in bouyant commodity markets. Hedges
effective during 2004 constrained cash flow. The hedges were implemented upon
careful analysis and deliberation at both the management and Board level. The
decision to hedge was prudent in light of Western's highly levered position at
the start-up of production to protect a known cash flow stream.

         Western generated net revenue of $321.0 million in 2004 compared to
$163.5 million in 2003, representing a 96 per cent increase. Net revenue
excludes the amount recorded for purchased feedstocks and transportation costs
downstream of Edmonton. Feedstocks are crude products introduced at the
Upgrader. Some are introduced into the hydrocracking/hydrotreating process and
some are used as blendstock to create various qualities of synthetic crude oil
products. The cost of these feedstocks depends on world oil markets and the
spread between heavy oil and light crude oil prices.

<TABLE>
<CAPTION>
NET REVENUE
(THOUSANDS, EXCEPT AS INDICATED)                                       2004                  2003(2)
----------------------------------------------------------------------------------------------------
<S>                                                             <C>                      <C>
REVENUE
     Oil Sands(1)                                               $   458,502              $   226,154
     Marketing                                                      176,835                   54,512
     Transportation                                                   1,574                      427
----------------------------------------------------------------------------------------------------
     Total Revenue                                                  636,911                  281,093

PURCHASED FEEDSTOCKS AND TRANSPORTATION
     Oil Sands                                                      137,810                   62,437
     Marketing                                                      176,174                   54,412
     Transportation                                                   1,942                      731
----------------------------------------------------------------------------------------------------
     Total Purchased Feedstocks and Transportation                  315,926                  117,580

NET REVENUE
     Oil Sands(1)                                                   320,692                  163,717
     Marketing                                                          661                      100
     Transportation                                                    (368)                    (304)
----------------------------------------------------------------------------------------------------
     Total Net Revenue                                          $   320,985              $   163,513

Synthetic Crude Sales (bbls/d)                                       36,210                   32,207
Crude Oil Sales Price ($/bbl)(3)                                $     34.60              $     32.81
----------------------------------------------------------------------------------------------------
</TABLE>

(1)  Oil Sands Revenue and Net Revenue are presented net of Western's hedging
     activities.
(2)  The 12 Months Ended December 31, 2003 presented above represent Western's
     operations from June 1, 2003, the date commercial operations commenced.
(3)  Realized Crude Oil Sales Price ($/bbl) is calculated as Oil Sands Revenue
     divided by total Synthetic Crude Sales for the period.


OPERATING COSTS

We have previously communicated that this Project is expected to achieve unit
operating costs in the $12 to $14 per barrel range assuming a natural gas price
of Cdn$7.00 per mcf. Although we are disappointed with some of the operating
results to date, higher unit operating costs, especially in the early years of
operation, are not unexpected. More importantly, we achieved unit operating
costs for the month of August 2004 that approached this targeted band. Not only
is it anticipated that incremental production volumes will reduce unit operating
costs, absolute cost reductions as a result of de-bottlenecking initiatives will
assist in this regard.

         Our share of Project operating costs totalled $213.0 million in 2004.
Included in this total are the costs associated with removing overburden at the
Mine and the costs of transporting bitumen from the Mine to the Upgrader, as
well as one-time costs associated with resolving various start-up issues. This
equates to unit operating costs of $21.17 per processed barrel of bitumen for
2004. This compares to a unit operating cost of $20.71 (restated) per processed
barrel for the seven-month operating period in 2003. Higher unit operating costs
compared to 2003 are largely attributable to one-off production interruptions
which occurred throughout the fourth quarter of


                                     Page 8
<PAGE>

2004. Unit operating costs during the fourth quarter totalled $28.22 per
processed barrel which materially skewed our operating costs of $19.32 per
processed barrel to the end of September 2004.

<TABLE>
<CAPTION>
OPERATING COSTS
(THOUSANDS, EXCEPT AS INDICATED)                                                     2004         2003(1)(2)
------------------------------------------------------------------------------------------------------------
<S>                                                                               <C>               <C>
Operating Expenses for Bitumen Sold
     Operating Expense - Income Statement                                         212,993           106,825
     Operating Expense - (Inventoried)/Expensed in Purchased Feedstocks            (3,058)              430
------------------------------------------------------------------------------------------------------------
     Total Operating Expenses for Bitumen Sold                                    209,935           107,255
------------------------------------------------------------------------------------------------------------

Sales (barrels per day)
     Total Synthetic Crude Sales                                                   36,210            32,207
     Purchased Upgrader Blend Stocks                                                9,112             8,011
------------------------------------------------------------------------------------------------------------
     Synthetic Crude Sales Excluding Blend Stocks                                  27,098            24,196
------------------------------------------------------------------------------------------------------------
Operating Expenses per Processed Barrel ($/bbl) (3)                                 21.17             20.71
------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Fiscal 2003 presented above represent Western's operations from June 1,
     2003, the date commercial operations commenced.
(2)  2003 operating costs have been restated to conform with Western's
     convention for reporting operating costs since the second quarter of 2004.
     Operating expenses are now calculated on the basis of costs associated with
     the synthetic crude sales excluding purchased blend stocks for the relevant
     period. This calculation recognizes that, intrinsic in the Project's
     operations, bitumen production from the Mine receives an approximate three
     per cent uplift as a result of the hydrotreating/hydroconversion process,
     which is included in synthetic crude sales excluding blendstocks.
     Previously unit operating costs were calculated on the basis of barrels of
     bitumen produced which is lower by default.
(3)  Operating Expenses per Processed Barrel ($/bbl) is calculated as Total
     Operating Expenses for Bitumen Sold divided by Synthetic Crude Sales
     Excluding Blend Stocks.

         Producing synthetic crude oil from oil sands is perceived to cost more
than oil production from conventional sources. When one considers the total cost
of production, including finding and development costs, operating costs,
royalties, depletion and taxation, oil sands production costs are very
competitive; arguably less expensive. In order to properly compare conventional
crude oil to crude oil derived from oil sands, an analysis of product quality
must also be considered. For example, our PAS stream has a considerably lower
sulphur content than conventional crude oil and therefore demands a premium
price. In addition, operating costs for oil sands operations typically decline
over time as the technological and engineering challenges are addressed and
resolved. This is already occurring for our project and we expect to see a
continued reduction in operating costs over the coming years. Given our
state-of-the-art technology platform, and what we assess as a superior ore body,
we believe we can be one of the lowest cost producers of synthetic crude oil.

         All greenfield resource projects are unique. Unlike expansions that
draw from operating experience, the AOSP is a technological extension of the
past 30 years of industry's oil sands operating experience and development. As
such, many assumptions were made relating to ore grade, grain structure and
distribution, wear, flow velocities, settling rates, and heating and cooling
rates in the detailed design stages of the Project. As operations began, these
assumptions were tested and modified and will have an impact on costs until
corrected. Costs associated with addressing these corrections are expensed as
incurred rather than capitalized to the balance sheet. This is a conservative
approach and will result in higher operating costs in the initial years as these
operational issues are systematically addressed. We believe the majority of
these issues have been addressed and expect operational costs to fall within the
targeted range in the upcoming years. In addition, as the cost structure for the
AOSP is predominantly fixed in nature, as increased through-put is achieved
through initiatives such as de-bottlenecking, unit costs will continue on a
downward trend.

         Despite the difficulties experienced in the fourth quarter of 2004,
Western maintained a respectable netback per barrel, excluding commodity hedge
impacts, as compared to previous quarters. Marketing of our ARB stream in the
fourth quarter, while positive from the perspective of maximizing bitumen sales,
negatively impacted our blended differential. This was exacerbated by market
forces such as lower demand for heavy streams by refineries towards the end of
fiscal 2004 as they undertook year-end maintenance programs, reducing their


                                     Page 9
<PAGE>

capacity. With our belief of continued robust commodity prices for 2005,
together with fewer barrels subject to fixed priced hedging instruments over the
course of 2005, we fully expect to achieve materially higher netbacks.


ROYALTIES

Royalties amounted to $3.0 million or $0.30 per barrel in 2004 compared to $1.2
million or $0.23 per barrel of bitumen produced for the seven months of
operations in 2003. Higher gross royalties reflect a full year of production.
Initially, royalties are calculated at one per cent of the gross revenue from
the bitumen produced (based on its deemed value prior to upgrading) until we
recover all capital costs associated with the Muskeg River Mine and Extraction
Plant, together with a return on capital equal to the Government of Canada
federal long-term bond rate. After full capital cost recovery, the royalty is
calculated as the greater of one per cent of the gross revenue on the bitumen
produced or 25 per cent of the net revenue on the bitumen produced. We estimate
our royalty horizon to be between 2008 to 2010, after which we will be paying
royalties at the higher rates. This assumes a long-term WTI price of US$30. The
timing of this will depend in part on the prices we receive for our production
as well as any additional capital costs incurred through expansion activities,
which would have the effect of deferring this royalty horizon.

RESERVES

Gilbert Laustsen Jung Associates Ltd. (GLJ), an independent engineering firm
located in Calgary, evaluates our reserves. The table below summarizes the
Project reserves and our share of those reserves as at December 31, 2004, based
on GLJ's forecast of escalating prices and costs.

<TABLE>
<CAPTION>
RESERVES SUMMARY

                                       GROSS   OWNERSHIP
                                     PROJECT    INTEREST    NET AFTER         PRESENT VALUES OF ESTIMATED FUTURE
                                    RESERVES    RESERVES      ROYALTY          NET CASH FLOW BEFORE INCOME TAXES
                                    (MMBBLS)    (MMBBLS)     (MMBBLS)         0%         10%        15%        20%
-------------------------------------------------------------------------------------------------------------------
                                                                                          ($ MILLIONS)
<S>                                  <C>        <C>         <C>            <C>         <C>        <C>        <C>
Proved                                 1,021         204          183      3,332       1,766      1,395      1,146
Probable                                 565         113           97      2,563         565        315        197
-------------------------------------------------------------------------------------------------------------------
Proved Plus Probable                   1,586         317          280      5,895       2,331      1,710      1,343
-------------------------------------------------------------------------------------------------------------------
<CAPTION>

RESERVES RECONCILIATION
                                                                                                       PROVED PLUS
                                                                                      PROVED              PROBABLE
                                                                                    (MMBBLS)              (MMBBLS)
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>                <C>
December 31, 2003                                                                        214                   311
Production (1)                                                                           (10)                  (10)
Revisions                                                                                 --                    16
-------------------------------------------------------------------------------------------------------------------
December 31, 2004                                                                        204                   317
-------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Upgraded bitumen production, which is dry bitumen, uplifted by 3.0 per cent
     for hydrocracking/hydrotreating.

This analysis by GLJ includes only those reserves to the west of the Muskeg
River on Lease 13 to be mined by the Joint Venture. These reserves translate
into a reserve life index of approximately 27 years based on the Project design
capacity.

The following table outlines the potential undeveloped resources available on
the remainder of Lease 13 and on five nearby oil sands leases owned by Shell,
namely Leases 88, 89, 90, 9 and 17. As we prepare to participate in the
expansion opportunities, development of these resources will provide for
substantial growth in our proved and probable reserve base at that time.


                                    Page 10
<PAGE>

POTENTIAL RESOURCES

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

Remainder of Lease 13 and Lease 90                 3,200                   640
Leases 88 and 89                                   3,900                   780
Lease 9                                            1,000                   200
------------------------------------------------------------------------------
Total                                              8,100                 1,620
------------------------------------------------------------------------------


CORPORATE RESULTS

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses ("G&A") were $8.1 million in 2004 or $0.82
per barrel (2003 - $6.3 million or $1.24 per barrel). This year-over-year
increase is primarily a result of additional personnel at Western and the
associated salary and benefit costs. It also reflects higher consulting fees and
director compensation incurred in 2004 compared to 2003.

INSURANCE EXPENSES

Insurance expenses were $9.4 million in 2004 (2003 - $1.7 million). Western
maintains adequate and sufficient insurance policies covering property, business
interruption, director and officer liability, in addition to various corporate
policies. Insurance expense in 2004 is higher than the previous year since a
portion of the expense was capitalized as part of the Project in 2003. The
annual premium for these policies is approximately $6.0 million for the
2004/2005 policy term ($9.0 million for the 2003/2004 policy term). This
represents a reduction of 33 per cent compared to the prior year which is
primarily a result of lower premiums associated with our business interruption
policy. The reduction is also a result in the strengthening of the Canadian
dollar in the last 12 months as these premiums are paid in US dollars. At
December 31, 2004, $1.0 million had been expensed for the 2004/2005 policy term
while $5.0 million remained in prepaid expenses.

INTEREST EXPENSE

During 2004 we incurred $59.1 million in interest charges on our debt
obligations (2003 - $60.5 million) and $2.0 million (2003 - $1.4 million) on our
capital lease obligations. These obligations include US$450 million Senior
Secured Notes, a $100 million Senior Credit Facility and a $240 million
Revolving Credit Facility. During 2003, interest charges in the amount of $23.5
million incurred prior to commercial production on June 1 were capitalized and
will be amortized over the life of the Project's reserves. Interest costs of
$38.4 million were expensed over the seven-month operating period in 2003. The
following table summarizes our interest expense and average cost of debt for the
past two fiscal years.

INTEREST AND LONG-TERM DEBT FINANCING

(THOUSANDS, EXCEPT AS INDICATED)                         2004              2003
-------------------------------------------------------------------------------
INTEREST EXPENSE
Interest Expense on Long-term Debt              $   59,118(3)     $   60,522(1)
Less: Capitalized Interest                                 --          (23,479)
-------------------------------------------------------------------------------
Net Interest Expense on Long-term Debt                 59,118            37,043
Interest on Obligations under Capital Lease             2,036             1,386
-------------------------------------------------------------------------------
Net Interest Expense                            $      61,154     $      38,429
-------------------------------------------------------------------------------
LONG-TERM DEBT FINANCING
US$450 Million Senior Secured Notes (2)         $     541,620     $     581,580
Revolving and Senior Credit Facilities             216,000(3)        279,000(1)
-------------------------------------------------------------------------------
Total Long-term Debt                            $     757,620     $     860,580
-------------------------------------------------------------------------------
Average Long-term Debt Level                    $     809,100     $     818,200
Average Cost of Long-term Debt                          7.31%             7.40%
-------------------------------------------------------------------------------


                                    Page 11
<PAGE>

(1)  Includes $88 million in Convertible Notes that were repaid and refinanced
     October 24, 2003, with the $240 million Revolving Credit Facility,
     described in Note 8(c) of the Consolidated Financial Statements.
     Accordingly interest has only been included since October 24, 2003, in
     respect of this amount, as interest on the Convertible Notes was previously
     charged directly to the deficit as described in Note 2(i) of the
     Consolidated Financial Statements.
(2)  Under Canadian GAAP, the Senior Secured Notes are recorded in Canadian
     dollars at exchange rates in effect at each balance sheet date. Unrealized
     foreign exchange gains or losses are then included on the Consolidated
     Statement of Operations. Prior to June 1, 2003, all foreign exchange gains
     or losses were capitalized as part of the financing costs of the Project.
(3)  For comparative purposes, amounts include the $95 million principal
     outstanding under the $100 million Senior Credit Facility or interest
     thereon, as applicable, which is classified for accounting purposes as
     short-term liabilities pursuant to its maturity on April 23, 2005.


DEPRECIATION, DEPLETION & AMORTIZATION

In 2004, we recorded $44.5 million as depreciation, depletion and amortization
expense (2003 - $27.5 million). Depletion is calculated on a unit of production
basis for our share of Project capital costs while previously deferred financing
charges are amortized on a straight-line basis over the remaining life of the
debt facilities. The increase for 2004 is a result of a full year of production
in 2004 versus 2003. Depletion and amortization have only been recorded since
June 1, 2003, the date commercial operations commenced.

<TABLE>
<CAPTION>
DEPRECIATION, DEPLETION & AMORTIZATION

YEAR ENDED DECEMBER                                                2004                               2003
-------------------------------------------------------------------------------------------------------------------
                                                 (THOUSANDS)                $/BBL      (THOUSANDS)           $/BBL
-------------------------------------------------------------------------------------------------------------------
<S>                                              <C>                  <C>               <C>              <C>
Depreciation and Depletion                       $    41,933          $      4.23       $   19,994       $    3.96
Amortization                                           2,582                 0.26            7,537            1.49
-------------------------------------------------------------------------------------------------------------------
Total Depreciation, Depletion and Amortization   $    44,515          $      4.49       $   27,531       $    5.45
-------------------------------------------------------------------------------------------------------------------
</TABLE>

FOREIGN EXCHANGE

In 2004, WTI averaged US$41.40 per barrel, representing an increase of 33 per
cent compared to an average of US$31.04 per barrel in 2003. This significant
appreciation in the commodity price was somewhat tempered by the strengthening
Canadian dollar that rose from US$0.77 to US$0.83 during the year. For Western,
the foreign exchange impact on revenues was somewhat offset by lower interest
costs expressed in Canadian dollars on our US dollar denominated Senior Secured
Notes and a reduced liability (as measured in Canadian dollars) associated with
this debt. In 2004, we recorded an unrealized foreign exchange gain of $40.0
million (2003 - $129.3 million gain) relating to the conversion of the Senior
Secured Notes to Canadian dollars. In 2003, we capitalized $94.0 million of this
foreign exchange gain and the remaining $35.3 million was recognized as income
for the period, in accordance with Canadian Generally Accepted Accounting
Principles ("GAAP").

INCOME TAXES

Western has sizeable tax pools totalling $1.5 billion that accumulated in
conjunction with our 20 per cent share of the construction costs for the Muskeg
River Mine and Extraction Plant and Scotford Upgrader. These tax pools will be
used to offset future taxable income and extend the time horizon until we must
pay cash taxes.

         For the year ended December 31, 2004, we recognized a future income tax
asset of $14.5 million compared to a future income tax asset at December 31,
2003 of $6.3 million. This asset is comprised mainly of non-capital loss carry
forwards, net of the future income tax effect of the book values of assets in
excess of tax values, and of the unrealized foreign exchange gains on the US$450
million Senior Secured Notes. During 2004, we expensed $1.7 million (2003 - $3.1
million) with respect to the Large Corporations Tax. This year-over-year
decrease is a result of the federal government's decision to gradually phase out
this tax policy.


                                    Page 12
<PAGE>

<TABLE>
<CAPTION>
TAX POOLS

DECEMBER 31 (THOUSANDS)                                                                 2004                  2003
-------------------------------------------------------------------------------------------------------------------
<S>                                                                             <C>                   <C>
Canadian Exploration Expense                                                    $    141,327          $    123,178
Canadian Development Expense                                                          33,795                15,993
Canadian Exploration and Development Overhead Expense                                     --                 2,677
Cumulative Eligible Capital                                                            7,479                 4,114
Capital Cost Allowance                                                                89,194                25,661
Accelerated Capital Cost Allowance                                                 1,087,056             1,180,940
-------------------------------------------------------------------------------------------------------------------
Total Depreciable Tax Pools                                                     $  1,358,851          $  1,352,563
Loss Carry Forwards                                                                  163,740               129,340
Financing and Share Issue Costs                                                       15,130                25,239
-------------------------------------------------------------------------------------------------------------------
Total Tax Pools                                                                 $  1,537,721          $  1,507,142
-------------------------------------------------------------------------------------------------------------------
</TABLE>

RECONCILIATION: NET EARNINGS (LOSS) TO EBITDAX

The following table provides the reconciliation between Net Earnings (Loss)
Attributable to Common Shareholders, Cash Flow from Operations (before changes
in non-cash working capital) and EBITDAX:

<TABLE>
<CAPTION>
DECEMBER 31 (THOUSANDS)                                             2004                2003                  2002
-------------------------------------------------------------------------------------------------------------------
                                                                                  (RESTATED)
<S>                                                         <C>                 <C>                   <C>
NET EARNINGS (LOSS) ATTRIBUTABLE
     TO COMMON SHAREHOLDERS                                 $     19,452        $     15,003          $    (10,286)
Add (Deduct):
     Depreciation, Depletion and Amortization                     44,515              27,531                  192
     Accretion on Asset Retirement Obligation                        471                 471                    --
     Stock-based Compensation                                        967                 278                    --
     Write-off of Deferred Charges                                    --                  --                22,759
     Impairment of Long-lived Assets                               4,733                  --                    --
     Unrealized Foreign Exchange Gain                            (39,960)            (35,280)                   --
     Future Income Tax Recovery                                   (7,104)             (4,330)              (22,551)
     Charge for Convertible Notes                                     --               2,130                 1,283
     Cash Settlement on Asset Retirement Obligations                 (30)                 --                    --
-------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS, BEFORE
     CHANGES IN NON-CASH WORKING CAPITAL                    $     23,044        $      5,803          $     (8,603)
Add (Deduct):
     Interest                                                     61,154              38,429                    --
     Realized Foreign Exchange Loss                                1,610                 304                    --
     Large Corporations Tax                                        1,749               3,079                 2,905
     Cash Settlement on Asset Retirement Obligations                  30                  --                    --
EBITDAX                                                     $     87,587        $     47,615          $     (5,698)
-------------------------------------------------------------------------------------------------------------------
</TABLE>

Please refer to page 58 for a discussion of Non-GAAP financial measures.

         Our net earnings totalled $19.5 million ($0.37 per share) in 2004
compared with $15.0 million ($0.30 per share) in 2003, including the seven
months of commercial operations. Earnings for the 2004 period reflect $40.0
million ($33.5 million net of tax) of unrealized foreign exchange gains on our
US$450 million Senior Secured Notes and a future income tax recovery of $7.1
million. Earnings before interest, taxes, depreciation, depletion and
amortization, stock-based compensation, accretion on asset retirement obligation
and foreign exchange gains were $87.6 million. Cash flow from operations for
2004 before changes in non-cash working capital was $23.0 million ($0.44 per
share) compared to $5.8 million ($0.12 per share) in 2003. We look forward to
continued improvement in EBITDAX and cash flow from operations in 2005 as we
further stabilize production, realize early benefits from de-bottlenecking
activities, increase synthetic crude sales and reduce operating costs.



                                    Page 13
<PAGE>

QUARTERLY INFORMATION

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

<TABLE>
<CAPTION>
(MILLIONS, EXCEPT PER SHARE AMOUNTS)            Q1               Q2               Q3            Q4           TOTAL
-------------------------------------------------------------------------------------------------------------------
<S>                                     <C>               <C>              <C>           <C>            <C>
2004
Net Revenue                             $     82.7        $    93.3        $   104.1     $    40.9      $    321.0
Net Capital Expenditures                       5.5              7.3             13.5          13.7            40.0
Long-term Debt                               852.7            715.2            638.8         662.6           662.6
Cash Flow from Operations (1)                  9.0             19.4             32.5         (37.9)           23.0
Cash Flow per Share (2) (5)                   0.18             0.36             0.62         (0.72)           0.44
Earnings (Loss) Attributable
     to Common Shareholders (4)               (5.7)            (9.2)            42.4          (8.0)           19.5
Earnings (Loss) per Share
     Basic                                   (0.11)           (0.17)            0.80         (0.15)           0.37
     Diluted                                 (0.11)           (0.17)            0.79         (0.15)           0.37
-------------------------------------------------------------------------------------------------------------------

2003
Net Revenue                             $       --        $    16.1        $    73.0     $    74.4      $    163.5
Net Capital Expenditures                     112.2             25.3              3.3           7.7           148.5
Long-term Debt                               757.2            780.9            852.7         860.6           860.6
Cash Flow from Operations (1)                 (2.2)            (5.0)             9.6           3.4             5.8
Cash Flow per Share (2) (5)                  (0.04)           (0.10)            0.19          0.07            0.12
Earnings (Loss) Attributable
     to Common Shareholders (3)               (2.4)             1.3             (1.5)         17.6            15.0
Earnings (Loss) per Share,
     Basic (3)                               (0.05)            0.03            (0.03)         0.35            0.30
     Diluted (3)                             (0.05)            0.02            (0.03)         0.35            0.29
-------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Cash flow from operations is expressed before changes in non-cash working
     capital.
(2)  Cash flow per share is calculated as cash flow from operations divided by
     weighted average common shares outstanding, basic.
(3)  Restated from quarterly releases to reflect changes in accounting policies
     regarding asset retirement obligations and stock-based compensation adopted
     in the fourth quarter of 2003.
(4)  Includes unrealized foreign exchange gains(losses) on US$450 million Senior
     Secured Notes (Q1(loss) - $8.1 million Q2(loss) - $13.5 million, Q3 - $34.4
     million, Q4 - $27.1 million).
(5)  Please refer to page 58 for a discussion of Non-GAAP financial measures.


FINANCIAL POSITION

Prior to commercial operation, one of our primary objectives has been to fund
our share of construction costs and to ensure that the timing of proceeds from
financings coincides with the funding requirements for the Project. We have
consciously structured our financing activities to maximize the value for our
shareholders by minimizing the amount of equity issued and to issue equity at
successively higher prices. Now that we have a modest track record of
operations, our primary objective is to ensure sufficient working capital exists
to fund our operations and, looking forward, to ensure we have sufficient
financial resources to enable Western to participate in expansion projects or
other investment opportunities that may arise.

DEBT FINANCING

In 2004, we maintained our US$450 million of Senior Secured Notes along with the
$240 million Revolving Credit Facility that was established in October 2003 to
provide a long-term working capital facility to sustain us through operations.
The $100 million Senior Credit Facility is held with a syndicate of chartered
banks; $75 million of which was used primarily to fund the first year's debt
service of the Senior Secured Notes as well as construction completion costs,
while the remaining $25 million was for working capital and letter of credit
requirements. In total, at December 31, 2004, $216 million (2003 - $279 million)
had been drawn under these facilities, with letters of credit issued in the
amount of $8.1 million (2003 - $7.6 million). The $100 million senior credit
facility matures in April 2005 and as such has been classified as a current
liability at December 31, 2004. Western is currently in the process of
refinancing this facility through the assumption of the full $100 million into
the Revolving Credit Facility where the additional amount will be subject to the
identical terms and conditions that currently apply under the Revolver. As such,
this debt component would then be re-classified as long-term. This ability to
roll the amount into the Revolving Facility was specifically structured at its
inception. Western expects this to be completed by the end of the first quarter
in 2005.


                                    Page 14
<PAGE>

EQUITY FINANCING

In April 2004, Western issued 2,000,000 Class A shares ("Common Shares") at a
price of $34.00 per share for gross proceeds of $68 million (net proceeds of
approximately $65.1 million) pursuant to Western's previously announced public
offering. The Common Shares were offered to the public on a bought-deal basis
through a syndicate of Canadian underwriters. Net proceeds from the issue were
used for general corporate purposes and for expansion opportunities. Western
applied a portion of these net proceeds to temporarily reduce its indebtedness.

EQUITY CAPITAL

AT DECEMBER 31                                                           2004
------------------------------------------------------------------------------
Issued and Outstanding:
     Common Shares                                                 53,278,762
Outstanding:
     Stock Options                                                  1,255,646
------------------------------------------------------------------------------
Fully Diluted Number of Shares                                     54,534,408
------------------------------------------------------------------------------

         Western's outstanding shares at December 31, 2004, reflects the
conversion of all 666,667 Class D Preferred Shares on a one for one basis into
common shares of the Company during the fourth quarter for no additional
consideration. This conversion feature was at the option of the holder. No
dividends or interest were paid on the Class D Preferred Shares.

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

YEAR                            2001    2002    2003     2004      COMPOUNDED
------------------------------------------------------------------------------
Rate of Return (%)                27      27      22       42              29
------------------------------------------------------------------------------

CAPITAL EXPENDITURES

Capital expenditure programs are conducted under the Joint Venture Agreement
whereby we participate in the operations of the Project to our 20 per cent
working interest and we are responsible for our respective share of the costs.
Our net capital expenditures totalled $40.0 million in 2004 (2003 - $148.5
million) which included: $36.4 million (2003 - $122.6 million) of project
related expenditures; $3.6 million (2003 - $1.7 million) of capitalized
insurance costs; $2.6 million (2003 - $2.2 million) of diluent purchases; $3.8
million (2003 - $3.0 million) in other assets and $nil (2003 - $22.9 million) of
direct capitalized finance costs. Included in the project related expenditures
were $23.2 million for our share of profitability and de-bottlenecking and
growth initiatives and $13.2 million for sustaining capital for the Project.
Insurance proceeds received during the year of $6.4 million (2003 - $9.7
million) were applied against the total cash capital expenditures.

ANALYSIS OF CASH RESOURCES

Our cash balances totalled $3.7 million at the end of 2004 which is consistent
with the $3.8 million at December 31, 2003. Cash inflows included $67.9 million
of net equity raised, $6.4 million of insurance proceeds, net operating cash
flow of $23.0 million and a working capital increase of $13.3 million. Cash
outflows included repayments of long-term debt and obligations under capital
leases of $64.4 million and capital expenditures of $46.4 million.

         As the AOSP Project approaches its second year of full production,
operations generate more than adequate cash flow for Western to meet its ongoing
operating and capital commitments. Our strategy is to maintain a minimal cash
balance and apply free cash flow to fund our 2005 capital expenditure program of
$110 million. Any excess free cash flow will be applied to reduce our
outstanding bank indebtedness. The 2005 capital expenditure program of $110
million incorporates capital projects relating specifically to the AOSP as well
as


                                    Page 15
<PAGE>

unrelated activities as Western continues to search for opportunities where we
can utilize our expertise to deliver substantial shareholder value.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

We have assumed various contractual obligations and commitments in the normal
course of our operations. Summarized on page 47 are significant financial
obligations that are known as of February 25, 2005, and which represent future
cash payments that we are required to make under existing contractual agreements
that we have entered into either directly, or as a partner in the Joint Venture.

         Feedstocks are included in the table to comply with continuous
disclosure obligations in Canada; however, Western could sell these products
back to the market and eliminate any negative impact in the event of operational
curtailments.

<TABLE>
<CAPTION>
CONTRACTUAL OBLIGATIONS AND COMMITMENTS

                                                                        PAYMENTS DUE BY PERIOD
-------------------------------------------------------------------------------------------------------------------
                                                 <1 YEAR       1 - 3 YEARS      4 - 5 YEARSAFTER 5 YEARS      TOTAL
-------------------------------------------------------------------------------------------------------------------
<S>                                            <C>             <C>             <C>         <C>          <C>
US$450 Million Senior Secured Notes            $      --       $        --     $     --    $ 541,620    $  541,620
Senior Credit Facility                            95,000                --           --           --        95,000
Revolving Credit Facility (1)                         --                --           --      121,000       121,000
Obligations Under Capital Lease                    1,340             2,680        2,680       44,909        51,609
Feedstocks                                        79,437           220,368      168,520       62,117       530,442
Utilities                                         31,807            65,690       69,513      590,377       757,387
Mobile Equipment Lease                             5,960             6,280       27,440        8,700        48,380
-------------------------------------------------------------------------------------------------------------------
Total Contractual Obligations                  $ 213,544       $   295,018     $268,153    $1,368,723   $2,145,438
-------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  The Revolving Credit Facility is a 364-day extendible facility that
     incorporates a two year term-out. Management considers this to be part of
     our long-term capital structure.
(2)  In addition, we have an obligation to fund Western's share of the Project's
     Pension Fund and have made commitments related to our risk management
     program: see Notes 16 and 17, respectively, of the Consolidated Financial
     Statements.

INSURANCE CLAIMS

Arbitration proceedings have been initiated to resolve the disputes with
insurers surrounding the claims for payment pursuant to our Cost Overrun and
Project Delay Insurance Policy. We have filed insurance claims for the full $200
million limit of the policy, and we will also be seeking interest and other
damages. The arbitration process is underway and we anticipate that the hearings
will commence in the fall of 2005. In order to preserve Western's rights with
regard to the policy, we have filed a Statement of Claim in the Court of Queen's
Bench of Alberta against such parties in an amount exceeding $200 million.
Aggravated and punitive damages totalling $650 million have also been claimed
against the insurers. The Statement of Claim will only be served on the
defendants and pursued in the courts in the event that resolution procedures
cannot otherwise be agreed to on a timely basis.

         During 2003, the Joint Venture also submitted claims under the
insurance coverage provided in our Joint Venture construction policies, in
respect of the fire that occurred in January 2003 at the Muskeg River Mine
Extraction Plant. The Joint Venture has extensive insurance coverage in place
and is seeking to recover from the insurers the full amount of the costs
incurred for repairs. A total of $16.1 million has been received by Western as
of December 31, 2004, for property damages. Insurers involved in the Cost
Overrun and Delay Insurance dispute with Western have withheld insurance
proceeds payable to Western for damages related to the January fire. With the
exception of the amounts withheld, these claims have now been resolved. The
Joint Venture has also filed a $500 million claim ($100 million net to Western)
in respect of loss of profits due to production delays from the fire. The claim
is being disputed by the insurers and, as a result, the matter has been referred
to arbitration. The arbitration panel has been constituted and the arbitration
process is underway.

         No amounts, other than those collected at December 31, 2004, have been
recognized in these statements relating to these insurance policies nor will an
amount be recognized until the proceeds are received due to the uncertainty in
the timing of receipt of these payments.


                                    Page 16
<PAGE>

FOURTH QUARTER

During the fourth quarter, the AOSP experienced a series of unrelated production
interruptions. These interruptions stemmed from the failure of an ebulating pump
in the residual hydro-cracker ("RHC") unit of Train 1. An operational upset
occurred within the RHC leading to catalyst materials cycling through the pump,
eventually resulting in its failure. Measures have been taken to ensure such
events cannot occur in the future.

         During the ramp-up of the RHC in December, a tubing leak was detected
in one of the aerial coolers. For safety reasons, the Train was once again
brought down in order to repair this specific tube as well as inspect the
remaining tubes for that Train. Train 2 operated at full capacity during this
time and was not susceptible to the same operational upset issues.

         Due to these production interruptions, revenue generated during the
fourth quarter was below prior periods. In turn, these reductions resulted in
Western selling a higher percentage of heavy crude oil products translating into
a lower realized sales price per barrel. This issue was exacerbated by the
record wide light to heavy crude oil differential that persisted throughout the
fourth quarter. Sales price realizations equalled $27.33 per barrel in the
fourth quarter, $43.94 per barrel excluding hedging activities. As many of our
costs are fixed in nature, the decreased production levels resulted in a higher
operating cost per barrel of $28.22 for the fourth quarter. Due to lower
production, lower realized prices and the continued incurrence of fixed costs,
negative cash flow from operations for the fourth quarter totalled $37.9
million. Of this amount, losses due to hedging activities totalled $47.1
million. As a result of the production interruptions, Western drew an additional
$51 million on its Revolving Facility, thereby increasing overall bank debt to
$216 million at year-end. With the resumption of production in the first
quarter, we plan to aggressively reduce our existing bank lines throughout 2005.
Net oil sands revenue was $40.9 million for the fourth quarter, representing a
61 per cent decrease from the previous quarter, which is also lower than all
previous quarters for fiscal 2004.

OUTLOOK

OPERATING

December 2004 marked the 19th month of commercial operations of the AOSP. A
continued focus on plant reliability will remain a major initiative for 2005 in
order to attain production levels at or above design capacity rates for a
greater proportion of the year compared to 2004. Given that our cost structure
is predominantly fixed in nature, it follows that we anticipate unit operating
costs to improve as non-recurring challenges, typically associated with a
start-up of this magnitude, are systematically addressed. We continue to hold
that unit operating costs of $12 to $14 per processed barrel are attainable by
the end of 2007. We anticipate unit operating costs in the range of $17 to $19
per processed barrel produced for 2005. Fiscal 2005 was originally planned to be
a full plant turnaround year, but the Joint Venture accelerated certain
turnaround activities into 2004 as a result of the unplanned downtime in the
fourth quarter. Minor turnaround activities are now planned for 2005. Our 2005
capital expenditure program is estimated at $110 million (2004 - $46 million),
comprised of $58 million for de-bottlenecking and profitability projects, $35
million for growth initiatives including the Muskeg River Expansion project and
$17 million for sustaining capital. With the continued efforts towards
de-bottlenecking over the next three years, Western anticipates production from
the AOSP to total 180,000 to 200,000 barrels per day (36,000 to 40,000 barrels
per day net to Western) by the end of 2007. Excess free cash flow will be
applied to reduce our credit facilities. For 2005, we are forecasting cash flow
from operations of $3.00 per share (basic) with EBITDAX of $4.19 per share
(basic). We have assumed a WTI price of US$40 combined with a gas cost of
US$6.67 per mcf and a $0.82 CDN/US exchange rate for the purposes of this 2005
guidance.

         Western will maintain its current hedges for the immediate foreseeable
future. Future risk management activities will be considered for production
volumes in 2006 and beyond; however, the exact nature and structure of these
activities has not yet been determined. No matter the structure chosen, downside
risk will be mitigated while, at the same time, allowing for participation in
upward swings in crude prices. Western will continue to


                                    Page 17
<PAGE>

assess the existing hedges as fewer barrels are subject to fixed priced
structures as 2005 unfolds in the context of actual crude prices.

EXPANSION

As announced in September 2004, expansion initiatives were outlined for the
Muskeg River Mine. Increased production levels ranging from 90,000 to 100,000
barrels per day associated with the $4.0 to $4.5 billion capital program ($800
to $900 million net to Western) are anticipated to commence in 2009. Expansion
initiatives include mining plans, additional mining recovery equipment and an
additional train for bitumen extraction and froth treatment processing.
Expansion also entails the addition of a third hydro-conversion unit and
associated utilities at the Scotford Upgrader. The AOSP also received both
federal and provincial cabinet approval for Phase 1 of the Jackpine Mine which
could add 200,000 barrels per day (40,000 barrels per day net to Western) by
2013. Concurrent with these developments, current thinking at the Joint Venture
level is to execute multiple 90,000 to 100,000 barrel per day single train
projects, back-to-back on an accelerated basis leading to ultimate production in
the range of 500,000 to 600,000 barrels per day (100,000 to 120,000 barrels per
day net to Western). This concept is being thoroughly analyzed to determine if
further consideration is warranted. The timing and details of any expansion
initiatives will be subject to the outcome of future evaluations of economics,
market needs, regulatory requirements and sustainable development
considerations. We are also considering the acquisition of additional oil sands
leases that are or may become available in the Athabasca oil sands area.

         The AOSP provides Western with aggressive generic growth for at least
the next ten years, and we are pursuing technology development in order to
further enhance AOSP performance. These same programs may also apply to
opportunities outside of the Joint Venture, and Western is actively pursuing
these opportunities. Access to attractive new resources to create shareholder
value is a primary goal, and such resources, if acquired and developed, will
expand our revenue generation beyond a single joint venture.

SUSTAINABILITY

Western and our Joint Venture partners in the Project are committed to carrying
out operational activities in a manner that is fully compatible with the
principles of sustainable development. To us, this means creating value for our
shareholders while protecting the environment, managing resources, respecting
and safeguarding people, benefiting communities and working with stakeholders.
Western's commitment to sustainable development and corporate responsibility is
critical to sound operations and it forms the foundation for building our
future.

ENVIRONMENT

Environmental performance was impressive with a sulphur recovery rate exceeding
the 98 per cent requirement, and not one Class 2(1) incident for the year. We
have worked diligently in the design of the Project to ensure environmental
effects can be managed, and so there will be no unacceptable long-term effects
upon closure and ultimate reclamation. As part of our commitment to sound
environmental management, reclamation is carried out progressively and is
initiated at the earliest opportunity.

(1) A minor effect. An incident sufficiently large to impact the environment.
Single breach of statutory or prescribed limit, or single complaint. No
long-term effect on the environment.

         The AOSP has implemented a voluntary comprehensive greenhouse gas
("GHG") management plan. The plan focuses on monitoring actual GHG emissions at
both the Mine and the Upgrader, identifying and pursuing opportunities for
energy efficiency and the capture of carbon dioxide, and investing in other
emissions reduction activities outside of the AOSP. The GHG management plan
takes into consideration both voluntary targets and the emerging regulatory
framework. Under our current baseline operation, the AOSP is under the 0.065
tonnes CO2/bbl estimate as per the 1999 feasibility study. Further initiatives
are actively being pursued to reduce emissions. One such project involves
enhanced oil recovery techniques at nearby fields. During 2004, the AOSP's first
greenhouse gas report was filed with Alberta Environment. The Joint Venture
partners have continued to engage the federal government on key policy issues
stemming from the Kyoto Accord which, with Russia's


                                    Page 18
<PAGE>

ratification, came into force in February 2005. As a result, the Joint Venture
does not envision the greenhouse gas program to restrict economic growth of the
AOSP.

         A second key concern on the environmental front is the consumption of
fresh water. We are pleased to report that at both the Mine and Upgrader, water
use is tracking below or near design rates. In fact, at the Mine, we are well
below the licence limit set by the Alberta government and we are targeting to
stay below the original limit despite the incremental water usage associated
with the Muskeg River Mine expansion.

SAFETY

The AOSP made significant achievements in the critical area of safety in 2004.
For the Project as a whole, no employee experienced serious injury during the
year. Other safety metrics include:

o   A Lost Time Injury frequency(2) of 0.18 per 200,000 hours worked compared
    with the oil sands mining and extraction industry average(3) of 0.11.


o   A total Recordable Injury frequency(2) of 0.78 per 200,000 hours worked
    compared with the the oil sands mining and extraction industry average(3) of
    1.06.


COMMUNITIES

The AOSP continues to build on commitments made during early consultation for
the Project, including maximizing local benefits. In 2003, local procurement
figures were $229 million to Wood Buffalo contractors, including close to $25
million to Aboriginal companies. Through a number of community investment
initiatives, the AOSP is working with communities to provide skills and job
training, build local business capacity and contribute to various community
organizations and events. As well, jobs created by the AOSP are filled by our
neighbours whenever possible, resulting in a 60 per cent local hire rate for the
Muskeg River Mine. In the mining area, this figure is closer to 90 per cent.

(2)  Calculated as the number of incidents multiplied by 200,000 (100 person
     years) divided by the number of combined exposure hours of all direct
     contractors and employees.
(3)  Oil sands mining and extraction industry average based on the average of
     Shell, Syncrude and Suncor.


         To date, the Regional Municipality of Wood Buffalo and Scotford have
also benefited through community investments of over $1.5 million by the Joint
Venture. This includes donations towards capital funding for the construction of
the new Technology Centre at Keyano College, and contributions towards the
purchase of two medical outreach vehicles for outlying aboriginal communities.
The Project has also donated $330,000 to Tree Canada as part of its commitment
to fund a tree-planting program. Trees purchased from this donation are being
planted in parks and natural areas to preserve the greening of various
communities and contribute to animal habitat improvement, soil stabilization and
reduced greenhouse gas emissions. Albian Sands Energy, the operating company of
the Muskeg River Mine, has donated $300,000 to the Northern Light Regional
Health Foundation, assisting in the purchase of a new CT Scan machine.

RISK AND SUCCESS FACTORS RELATING TO OIL SANDS

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

OPERATIONAL RISKS

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


                                    Page 19
<PAGE>

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

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

         As a partner in the AOSP, we actively participate in operational risk
management programs implemented by the Joint Venture to mitigate the above
risks. Our exposure to operational risks is also managed by maintaining
appropriate levels of insurance. To that end, in October 2004 we renewed our
US$500 million of Property and Business Interruption Insurance as well as our
US$100 million of Liability Insurance to protect our ownership interest against
losses or damages to the Owners' facilities, to preserve our operating income
and to protect against our risk of loss to third parties.

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

o    pipeline transportation is provided through the Corridor Pipeline;

o    electricity and steam are provided to the Mine and the Extraction Plant
     from the Muskeg River cogeneration facility;

o    transportation of natural gas to the Muskeg River cogeneration facility is
     provided by the ATCO pipeline;

o    hydrogen is provided to the Upgrader from the Hydrogen Manufacturing Unit
     and Dow Chemicals Canada Inc., or Dow; and

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

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

         We may be faced with competition from other industry participants in
the oil sands business. This could take the form of competition for skilled
people, increased demands on the Fort McMurray infrastructure (housing, roads,
schools, etc.), or higher prices for the products and services required to
operate and maintain the plant.

         We have significant plans for expansion and the strong working
relationship the Project's management has developed with the trade unions will
be an important factor in our future activities. Our relationship with our
employees and provincial building trade unions is important to our future
because poor productivity and work disruptions have the potential to adversely
affect the Project, whether in construction or in operations.

FINANCIAL RISKS

The following table details the steady state sensitivities of our cash flow and
net earnings per share to certain relevant operating factors of the Project. The
base case upon which the sensitivities are calculated assumes our share of
bitumen production is 31,000 barrels per day, a constant WTI price of US$30.00
per barrel, a foreign exchange rate of US$0.75 per Canadian dollar and a
constant Alberta gas cost of Cdn$6.67 per thousand cubic feet.


                                    Page 20
<PAGE>

<TABLE>
<CAPTION>
SENSITIVITY ANALYSIS

                                                                         BASIC                               BASIC
                                                    CASH FLOW        CASH FLOW          EARNINGS          EARNINGS
VARIABLE                          VARIATION      ($ MILLIONS)        PER SHARE      ($ MILLIONS)         PER SHARE
-------------------------------------------------------------------------------------------------------------------
<S>                          <C>                  <C>                <C>            <C>                 <C>
Production                   1,000 BBLS/DAY        $     8.56        $    0.16        $     4.67        $     0.09
Oil Prices                          US$1.00        $    11.63        $    0.22        $     8.40        $     0.16
Non-Gas Operating Costs           $1.00/BBL        $    11.30        $    0.21        $     8.19        $     0.15
Gas Prices (2)                    $0.10/MCF        $     0.59        $    0.01        $     0.43        $     0.01
Foreign Exchange (1)             US/CDN .01        $     4.38        $    0.08        $     3.65        $     0.07
-------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  Excludes unrealized foreign exchange gains or losses on long-term monetary
     items. The impact of the Canadian dollar strengthening by US$0.01 would
     increase net earnings by $2.7 million based on December 31, 2004, US dollar
     denominated debt levels.
(2)  Each $1.00 per thousand cubic feet change in gas price results in a change
     of $ 0.53 per barrel in operating cost.

         Our financial results will depend on the prevailing price of crude oil
and the Canadian/US currency exchange rate. Oil prices and currency exchange
rates fluctuate significantly in response to supply and demand factors beyond
our control, which could have an impact on future financial results.

         Any prolonged period of low oil prices could result in a decision by
the Joint Venture partners to suspend or reduce production. Any such suspension
or reduction of production would result in a corresponding substantial decrease
in our future revenues and earnings and could expose us to significant
additional expense as a result of certain long-term contracts. In addition,
because natural gas comprises a substantial part of variable operating costs,
any prolonged period of high natural gas prices could negatively impact our
future financial results.

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

         To mitigate our exposure to these financial risks, we have established
a financial risk management program in consultation with our Board of Directors.

         The objective of our hedging program is to mitigate exposure to the
volatility of crude oil prices, thereby stabilizing current and future cash
flows from the sale of our synthetic crude products. Our strategy is to protect
the base capital program and ensure funding of debt obligations by providing a
stable platform of cash flow. To this end Western has entered into the following
swaps:

<TABLE>
<CAPTION>
HEDGING SUMMARY

                                                                                            UNREALIZED INCREASE
                             NOTIONAL                               HEDGE         SWAP     (DECREASE) TO FUTURE
INSTRUMENT                     VOLUME                              PERIOD        PRICE      REVENUE (THOUSANDS)
---------------------------------------------------------------------------------------------------------------
<S>                     <C>                   <C>                             <C>          <C>
WTI Swaps               14,000 BBLS/D         JAN 1, 2005 TO MAR 31, 2005     US$26.06            (CDN$26,333)
WTI Swaps                7,000 BBLS/D         APR 1, 2005 TO DEC 31, 2005     US$26.87            (CDN$34,777)
---------------------------------------------------------------------------------------------------------------
Total                                                                                             (CDN$61,110)
---------------------------------------------------------------------------------------------------------------
</TABLE>

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

         As part of our original financing plan, we established a Cost Overrun
and Project Delay Insurance Policy in the amount of $200 million. This insurance
policy, which took effect in March 2000 and continued through April 2004,
covered certain costs, expenses and losses of revenue through the construction
period arising from causes beyond our control and included: (i) costs and
expenses or loss of revenues arising from a delay in


                                    Page 21
<PAGE>

achieving a guaranteed production level; (ii) costs and expenses incurred in
connection with the modification, repair or replacement of equipment or
material, which were directly related to achieving guaranteed production levels;
(iii) escalation in Project costs beyond the budgeted Project costs, which were
directly related to achieving guaranteed production levels; and (iv) debt
service costs related to obligations incurred to finance any of (i), (ii) or
(iii). In effect, the program provided coverage for increased costs for
Western's share of the Project of up to $200 million to the extent the increased
costs were incurred to meet bitumen production levels of 155,000 barrels per day
as contemplated in the initial design of the Project.

ENVIRONMENTAL RISKS

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

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

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

NON-GAAP FINANCIAL MEASURES

Western includes cash flow from operations per share and earnings before
interest, taxes, depreciation, depletion and amortization, stock-based
compensation, accretion on asset retirement obligation and foreign exchange
gains ("EBITDAX") as investors may use this information to better analyze our
operating performance. We also include certain per barrel information, such as
realized crude oil sales price, to provide per unit numbers that can be compared
against industry benchmarks, such as the Edmonton PAR benchmark. The additional
information should not be considered in isolation or as a substitute for
measures of operating performance prepared in accordance with Canadian Generally
Accepted Accounting Principles ("GAAP"). Non-GAAP financial measures do not have
any


                                    Page 22
<PAGE>

standardized meaning prescribed by Canadian GAAP and are therefore unlikely to
be comparable to similar measures presented by other issuers. Management
believes that, in addition to Net Earnings (Loss) per Share and Net Earnings
(Loss) Attributable to Common Shareholders (both Canadian GAAP measures), cash
flow from operations per share and EBITDAX provide a better basis for evaluating
our operating performance, as they both exclude fluctuations on the US dollar
denominated Senior Secured Notes and certain other non-cash items, such as
depreciation, depletion and amortization, and future income tax recoveries. In
addition, EBITDAX provides a useful indicator of our ability to fund our
financing costs and any future capital requirements.

CRITICAL ACCOUNTING ESTIMATES

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

COMMENCEMENT OF COMMERCIAL OPERATIONS

Effective June 1, 2003, Western commenced commercial operations as determined by
Management, as all aspects of the facilities became fully operational and the
Project achieved 50 per cent of the stated design capacity of 155,000 barrels
per day. Accordingly, we have recorded revenues and expenses relating to our
share of operations for the Project from that date. Prior to June 1, 2003, all
revenues, operating costs and interest were capitalized as part of the costs of
the Project, and no depreciation, depletion or amortization were expensed.

CAPITAL ASSETS

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

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

ASSET RETIREMENT OBLIGATION

Effective January 1, 2003, Western elected early adoption of the CICA 3110
"Asset Retirement Obligations". The new standard requires that we recognize an
asset and a liability for any existing asset retirement obligations, which is
determined by estimating the fair value of this commitment at the balance sheet
date. We determine the fair value by first obtaining third party estimates for
the expected timing and amount of cash flows that will be required for future
dismantlement and site restoration, and then present valuing these future
payments using a credit adjusted risk free rate appropriate for Western. Any
change in timing or amount of the cash flows subsequent to initial recognition
results in a change in the asset and liability, which then impacts the depletion
on the asset and the accretion charged on the liability. Estimating the timing
and amount of third party cash flows to settle this obligation is inherently
difficult and is based on Management's current experience.


                                    Page 23
<PAGE>

FUTURE INCOME TAX

We have recognized future income tax assets and liabilities at December 31,
2004. These assets and liabilities are recognized at the tax rates at which
Management expects the temporary differences to reverse. Management bases this
expectation on future earnings, which require estimates for reserves, timing of
production, crude oil price, operating cost estimates and foreign exchange
rates. As a result, future earnings are subject to significant Management
judgment and changes could result in the temporary differences reversing at
different tax rates.





                                    Page 24