EXHIBIT 99.3
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MANAGEMENT'S DISCUSSION & ANAYLSIS
The following discussion of financial condition and results of operations was
prepared as of February 18, 2004 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 will not be achieved
by Western.
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. For additional information relating to risk
factors please refer to the discussion on page 34 entitled Risk and Success
Factors Relating to Oil Sands. Additional Information relating to Western,
including Western's 2003 Annual Information Form, is available at www.sedar.com.
OVERVIEW
Interest in non-conventional resources including the oil sands has been growing,
particularly with the continued decline in conventional crude oil reserves and
production. The investment community, governments and other stakeholders
increasingly recognize the important role oil sands will play in the future of
the energy industry and of our economy. Canada's reserve base is now ranked
second largest in the world 1- after Saudi Arabia - due to the recognition of
the magnitude of undeveloped oil sands reserves in the Athabasca region of
northeastern Alberta.
Western Oil Sands Inc. is a Canadian oil sands corporation that holds a 20 per
cent undivided ownership interest in 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. Shell Canada Limited
("Shell") and Chevron Canada Limited ("ChevronTexaco") hold the remaining 60 per
cent and 20 per cent undivided ownership interests in the Joint Venture,
respectively. The Athabasca Oil Sands Project (the "AOSP" or the "Project"),
which includes facilities owned by the Joint Venture and third parties, uses
established processes to mine oil sands deposits, extract, and upgrade the
bitumen into synthetic crude oil and vacuum gas oil. Currently, apart from our
interest in the Project, we have no other material assets nor do we have any
other ongoing operations. Western is, however, actively pursuing other oil sands
and related business opportunities.
The Joint Venture is currently developing and producing from the western portion
of Lease 13, a large oil sands lease in the Athabasca region held by the Joint
Venture. Once bitumen has been extracted at the Mine it is shipped through the
Corridor Pipeline to the Scotford Upgrader where it is processed and combined
with feedstock, and at design capacity will produce approximately 190,000
barrels per day (38,000 barrels per day net to Western) of vacuum gas oil and
synthetic crude oil. The western portion of Lease 13 contains approximately 1.6
billion barrels of proved and probable reserves and is sufficient for 27 years
of non-declining bitumen production at a rate of 155,000 barrels per day (31,000
barrels per day net to Western). De-bottlenecking activities being initiated in
2004 are expected to further increase production capacity at the Muskeg River
Mine ("MRM" or the "Mine") to 180,000 barrels per day over the next two years.
Western is entitled to participate in future expansion opportunities, including
the undeveloped eastern portion of Lease 13 and three other nearby oil sands
leases owned by Shell, referred to as Leases 88, 89 and 90. We have commenced
work on permitting the expansion of our existing operations at the Muskeg River
Mine. Once approvals for the MRM Expansion are received, we expect to move ahead
with the project development phase, which will include feasibility studies and
continued community dialogue. Western anticipates that the MRM Expansion may
increase the productive capacity of our existing facilities by up to 50 per
cent. In addition, we recently received conditional approval from the joint
review panel established by the Alberta Energy and Utilities Board and the
Government of Canada to develop the eastern portion of Lease 13, known as the
Jackpine Mine - Phase 1. The application is subject to certain conditions and
must now be approved by the Cabinets of both the Provincial and Federal
governments. 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). 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.
2003 HIGHLIGHTS
o In 2003, following three years of construction, the Project moved into its
operational phase.
o Fully integrated operations between the Muskeg River Mine site and the
Scotford Upgrader were achieved on April 19, 2003.
o Western's threshold for commercial bitumen production from the Project of
77,500 barrels per day (15,000 barrels per day net to Western) was exceeded
on June 1. Production ramped up over the next seven months of 2003 to
average approximately 118,000 barrels per day (23,600 barrels per day net to
Western).
WESTERN OIL SANDS - MD&A 1
o Western successfully established itself as an independent full-service
marketer of crude oil.
o Market acceptance for the AOSP's two new synthetic crude products - Premium
Albian Synthetic (PAS) and Albian Heavy Synthetic (AHS) was strong and as
the Project nears full capacity on a sustained basis, we will manage the mix
of our synthetic crude oil products.
o The financial impact on Western of the increase in WTI pricing, to which our
products are benchmarked, has been tempered by a strengthened Canadian/US
dollar exchange rate.
o Western established a $240 million Revolving Credit Facility, replacing the
existing $110 million Revolving Facility and repaying $88 million in
Convertible Notes. We also raised $50.2 million in equity.
o Western filed claims totaling $200 million against our Cost Overrun and
Project Delay Insurance Policy and subsequently initiated arbitration
proceedings to resolve the outstanding claims.
o Western has recovered $9.7 million on insurance claims during the year for
costs to repair fire and freeze damages under the Project's Joint Venture
construction insurance policies.
o With the commencement of operations, Western established ongoing insurance
policies including US$500 million of Property and Business Interruption
Insurance and US$100 million of Liability Insurance.
o Preliminary approval has been received for the first phase of the Jackpine
Mine Expansion situated on the eastern portion of Lease 13. This expansion
has the potential to add up to 200,000 barrels per day of incremental
production (40,000 barrels per day net to Western).
o Western's share of proved plus probable reserves at December 31, 2003,
totaled 311 million barrels. Total remaining resources for the AOSP,
including adjoining leases for potential expansion, are 8.7 billion barrels
of which Western's share is 1.7 billion barrels.
o The Project's safety performance record, environmental protection and
stakeholder relations, were major successes and are seen as key to
sustainable development.
Financial results for the year ended December 31, 2003 include operating
revenues and expenses from June 1, 2003, the date Western commenced commercial
production.
2003 2002 2001
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OPERATING DATA (bbls/d)
Bitumen Production 23,596 -- --
Synthetic Crude Sales 32,207 -- --
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FINANCIAL DATA ($ thousands, except as indicated)
Revenues 281,093 -- --
Realized Crude Oil Sales Price - Oil Sands ($/bbl) (1)(2) 32.81 -- --
Cash Flow from Operations (3) 5,803 (8,603) (6,845)
Cash Flow per Share - Basic ($/Share) (1)(4) 0.12 (0.18) (0.17)
Net Earnings (Loss) Attributable to
Common Shareholders (7) 15,003 (10,286) (7,015)
Net Earnings (Loss) per Share ($/Share)
Basic 0.30 (0.21) (0.17)
Diluted 0.29 (0.21) (0.17)
EBITDA (1)(5) 47,337 (5,698) (5,310)
EBITDA ($/bbl) (1)(6) 9.37 -- --
Net Capital Expenditures 148,473 527,541 433,604
Total Assets 1,458,424 1,359,638 854,394
Long-Term Liabilities 921,910 827,133 368,306
Weighted Average Shares Outstanding - Basic (Shares) 50,344,332 48,330,320 41,404,904
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(1) PLEASE REFER TO PAGE 38 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 DIVIDED BY THE
CORRESPONDING VOLUME. PLEASE REFER TO PAGE 21 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.
WESTERN OIL SANDS - MD&A 2
(5) EARNINGS BEFORE INTEREST, TAXES, DEPRECIATION, DEPLETION, AMORTIZATION AND
FOREIGN EXCHANGE AS CALCULATED ON PAGE 26.
(6) EBITDA ($/BBL) IS EBITDA DIVIDED BY TOTAL BITUMEN PRODUCTION FOR THE YEAR.
(7) WESTERN HAS NOT PAID CASH DIVIDENDS IN ANY OF THE ABOVE REFERENCED FISCAL
YEARS.
OPERATING RESULTS
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, Western has recorded revenues and expenses for our
share of operations from the Project beginning on 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. Comparisons to prior year, pre-operating information are provided in
the following discussion where appropriate.
PRODUCTION
In 2003, the Project successfully ramped up production to an average rate of
130,000 barrels per day in the fourth quarter. As expected, we encountered
various operational challenges associated with start-up throughout the year;
however, each challenge became an opportunity for learning and improving the
performance of the systems, equipment and operational teams.
The year began with great anticipation following three intense years of
construction and commissioning. On December 29, 2002, operations began at the
Muskeg River Mine when Train 1, the first of two extraction units, officially
started producing bitumen for transportation through the Corridor Pipeline
system to the Scotford Upgrader at Fort Saskatchewan. The production process at
the Mine includes the following stages:
o Ore is mined with electric shovels which load the sand/bitumen mixture into
400-ton haul trucks for transport to one of two primary roll crushers. The
mixture is then taken by a conveyor system to rotary breakers that further
reduce the particle size. Warm water is introduced, waste rock is rejected
and the resulting slurry is pumped to the Extraction Plant.
o At the Extraction Plant the bitumen is separated from much of the sand, clay
and other materials. The extraction process adds air to the pumped slurry,
which is then discharged into two primary separation vessels where the
bitumen attaches to air bubbles and rises to the top forming a froth. A
steam stripper removes the air bubbles and the bitumen flows to two large
froth storage tanks.
o In the final stage, called froth treatment, a solvent is added that
separates out the remaining solids, water and heavy asphaltenes, leaving
clean diluted bitumen.
On January 6, 2003, we experienced a fire in the froth cleaning circuit at the
Mine resulting in damage to electrical and control cables, instrumentation and
insulation. Severe weather conditions caused broader freeze damage and impeded
progress in making repairs. Operations recommenced on April 4 at the Mine and on
April 19 fully integrated operations were achieved when the Scotford Upgrader
started receiving and processing bitumen from the Mine. Ramp-up of oil sands
throughput and bitumen production has continued uninterrupted and with steady
progress and increasing volumes throughout the year.
Mining and extraction processes were initiated successfully given the variables
expected in this type of operation. The Mine was able to achieve a ramp-up of
throughput and production approaching design levels by year-end, with production
of bitumen averaging approximately 130,000 barrels per day in the fourth
quarter. Issues such as ore variability, equipment reliability and robustness,
flow velocities, wear, and measurement and control were encountered; these
issues are normal to mine and extraction plant start-ups and are being addressed
and resolved systematically.
By the fourth quarter, the Project was operating at 84 per cent of design
capacity. This is very close to the original feasibility study ramp-up curve for
production at the Mine that was considered by many to be aggressive, and is
substantially better than what is typical for plants of this nature where
step-out technology2 has been incorporated. Management believes that this also
represents the best start-up performance for large scale projects that the
mineable oil sands industry has experienced to date, a credit to the entire team
involved in the project.
Other challenges encountered at the Muskeg River Mine were not unusual for
mining operations in northern Alberta, where temperatures typically range from
+40(degree)C to -50(degree)C. In 2003, the Mine and Extraction Plant experienced
no lost time for weather related events which confirms the robustness of our
plant and equipment and provides the confidence needed to de-bottleneck and
expand these operations in the earliest time frame. In the early part of 2004,
however, operations were severely tested with lower than normal temperatures,
and this experience gives us confidence that continued improvements can be
achieved in terms of increased production and reduced costs. Operators must
learn to work within these extremes, given the physical limitations of the
mining equipment, the nature of the ore, and the ground conditions of the ore
body, to optimize production levels and cost. At the Muskeg River Mine we are
nearing the top of this learning curve; we have had considerable success but
some challenges may remain for future seasonal cycles.
The Upgrader is among the largest of its type in the world and experienced a
world class start-up with production capacity and conversion rates moving
consistently towards design targets. Hydro-conversion and integrated
hydro-treating technologies performed exceptionally well, meeting design levels
and enabling the production of high quality on-spec vacuum gas oil and synthetic
crude oil. Management's evaluation of
WESTERN OIL SANDS - MD&A 3
the Solomon Survey of upgraders of similar size and complexity indicates that
this unit already ranks among the "best-in-class" but additional improvements
are possible as we address deficiencies and gain more operating experience and
familiarity with the plant. Currently, the primary areas of focus for the
Upgrader management are hydrocarbon management processes that are targeting
higher conversion levels, and various other initiatives to increase
profitability through improved energy efficiency and reliability, increased
production rates and lower operating costs. These initiatives began in 2003 and
will continue in earnest in 2004 as higher bitumen feed rates are received from
the Mine.
Our third party partners provided pipeline and cogeneration operations that
fully met our requirements and contributed to our successful start-up. Minor
equipment issues with pump station valves and a heat recovery steam generator
were resolved effectively.
Overall, 2003 was a year of significant achievements in starting up a
world-class project, aggressively increasing production towards design targets,
and establishing a base for continued improvements, de-bottlenecking and
expansion opportunities.
MARKETING
Western has established a marketing department comprised of four individuals who
are responsible for marketing Western's share of synthetic crude oil products.
Two-thirds of our bitumen products, together with feedstocks and blendstocks are
upgraded into synthetic crude oil - our Premium Albian Synthetic (PAS) and
Albian Heavy Synthetic (AHS) crude products. We take our 20% share of these
products in kind and market them directly to refineries within North America. In
addition to marketing our proprietary crude oil products, we have also been
actively marketing and brokering displaced and third party volumes. The
remaining one-third of our production is comprised of LMHVGO (light, medium and
heavy vacuum gas oil) which is sold under a long-term supply agreement.
Our primary marketing objective in 2003 was to establish market outlets and
transportation avenues to ensure that we never curtailed production. Other key
objectives were to establish Western's profile as an independent full-service
marketer of crude oil and to gain market acceptance for two new crude oil
products; PAS and AHS. In 2003 we achieved all of these objectives.
We adopted an aggressive strategy to introduce our two new synthetic crude
products to customers. In certain circumstances this included marketing and
brokering displaced volumes from these customers to other third parties. This
innovative approach allowed refiners to assess these new crude types without
having to disrupt their normal supply arrangements. It also allowed us to honour
our commitments throughout the ramp-up period. Through these third party
opportunities and our ongoing marketing efforts, we have become an active
shipper on most major crude oil trunkline systems, further enhancing Western's
status as a reliable full-service marketer of crude. As a result, we succeeded
in moving all of our production volumes into the traditional North American
markets.
As customers processed and evaluated our PAS and AHS, they recognized the
inherent value in Western's crude streams. While our upgrading provides
synthetic crude oil with superior qualities for processing, our products also
lend themselves to blending and customizing and this flexibility may lead to
significant improvements in refinery efficiencies for our customers. This is the
next step in meeting and exceeding continual changes in customer requirements.
As we move into 2004 we continue to forge new customer relationships and build
on the competitive advantages that have set us apart from other marketers.
Western's role as we continue to grow will be to respond to the continuing
changes in our customers' long-term crude oil requirements. Through our existing
and expanded infrastructure, we will support our customers by producing and
blending customized crude streams that are uniquely tailored to their
operations. These streams will be shipped via a dedicated pipeline to the
Edmonton terminals and to the customer in segregated batches to maintain quality
and ensure the integrity of our product.
The broad market penetration achieved this year has given us a wide customer
base to position ourselves for the next phases of our growth, from Western's
current year average production of approximately 23,600 barrels per day to the
projected 105,000 barrels per day of bitumen to be produced at the Mine in the
next decade. Our de-bottlenecking initiatives commencing in 2004 will give our
customers access to increasing production volumes in the near-term, while
proposed expansion projects will provide access to secure long-term supplies and
may yield new and different types of crude.
REVENUE
Western earned $281.1 million in crude oil sales revenue in 2003, including
$226.2 million from our share of synthetic crude oil from the Upgrader, at an
average realized price of $32.81 per barrel. This includes our risk management
activities which reduced revenue by $8.2 million and reduced the average
realized price by $1.20 per barrel. The Edmonton PAR benchmark averaged $40.92
per barrel over the seven months of commercial operations, resulting in an
average synthetic crude oil quality differential of $6.91 per barrel for
Western. This reflects a greater discount from Edmonton PAR than our long-term
target of $1.75 to $2.75 per barrel, mainly due to wider than anticipated heavy
oil price differentials and higher ratios of heavy synthetic product in the
overall sales mix during start-up. Our price realizations relative to Edmonton
PAR are expected to improve as our operations stabilize, our products become
more established in the marketplace and various Upgrader optimization
initiatives are undertaken. Differentials in 2004 should improve compared with
2003 but are still expected to be wider than our long-term target.
Western generated net revenue of $163.5 million, after considering the impact of
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
is dependent upon world oil markets and the spread between heavy and light crude
oil prices.
WESTERN OIL SANDS - MD&A 4
NET REVENUE
(thousands, except as indicated) 2003
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Revenue
Oil Sands $ 226,154
Marketing 54,512
Transportation 427
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Total Revenue 281,093
PURCHASED FEEDSTOCKS AND TRANSPORTATION
Oil Sands 62,437
Marketing 54,412
Transportation 731
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Total Purchased Feedstocks and Transportation 117,580
NET REVENUE
Oil Sands 163,717
Marketing 100
Transportation (304)
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Total Net Revenue $ 163,513
Synthetic Crude Sales (bbls/d) 32,207
Crude Oil Sales Price ($/bbl) $ 32.81
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OPERATING COSTS
Our share of Project operating costs totaled $106.8 million for the seven month
period in 2003. Included are the costs associated with removing overburden at
the Mine and the costs of transporting bitumen from the Mine to the Upgrader.
This equates to unit operating costs of $21.16 per barrel for the seven month
operating period based on an average production rate of approximately 118,000
barrels per day (23,600 barrels per day net to Western). We expect to see a
significant decline in these unit costs as production volumes grow and stabilize
and as the various equipment and operational challenges associated with ramp-up
are resolved. Cost reduction initiatives for 2004 are focusing on heat exchanger
performance, settler mechanical reliability, ore preparation plant issues,
energy efficiency improvements, wear and solvent recovery.
OPERATING COSTS
2003
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$ Millions 106.8
$/bbl 21.16
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The cost of producing synthetic crude oil from oil sands is perceived as being
higher than the cost to produce oil from conventional sources. However, when one
considers the total cost of production, including finding and development costs,
operating costs, royalties, depletion and taxation, oil sands are very
competitive. 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 next couple of years. Given our state of
the art technology and what we assess as a superior ore body, we believe we can
be one of the lowest cost producers of synthetic crude.
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.
Modification and optimization will be the focus in 2004 as we move toward our
objective of being one of the lowest cost operators in the sector. Part of our
cost improvement will come from the benefits inherent in increased throughput
above design levels that we expect to achieve through our de-bottlenecking
program, now underway. Other improvements in cost will come from energy
efficiencies, which were recognized opportunities in 2003 and are now being
pursued in earnest in 2004.
ROYALTIES
Royalties were triggered with the start of production and totaled $1.2 million
or $0.23 per barrel of bitumen produced in 2003. Initially, royalties are
calculated at one per cent of the gross revenue from the bitumen produced (based
on its deemed value prior to upgrading) until we recover all capital costs
associated with the Muskeg River Mine and Extraction Plant, together with a
return on capital equal to the Government of Canada federal long-term bond rate.
After full capital cost recovery, the royalty is calculated as the greater of
one per cent of the gross revenue on the bitumen produced and 25 per cent of the
net revenue on the bitumen produced. We estimate that payout will not be
achieved for several years, after which we will be paying royalties at the
higher rates. The timing of this will depend in part on the prices we receive
for our production as well any additional capital costs incurred through
expansion activities, which would have the effect of deferring this royalty
horizon.
WESTERN OIL SANDS - MD&A 5
RESERVES
Gilbert Laustsen Jung Associates Ltd. (GLJ), an independent engineering firm
located in Calgary, evaluates our reserves. The following table summarizes the
Project reserves and our share of those reserves as at December 31, 2003, based
on GLJ's forecast of escalating prices and costs:
RESERVES SUMMARY
GROSS OWNERSHIP
PROJECT INTEREST NET AFTER PRESENT VALUES OF ESTIMATED FUTURE
RESERVES RESERVES ROYALTY NET CASH FLOW BEFORE INCOME TAXES
(MMbbls) (MMbbls) (MMbbls) 0% 10% 15% 20%
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($ millions)
Proved 1,071 214 196 2,522 1,242 971 798
Probable 485 97 83 1,518 363 221 151
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Proved Plus Probable 1,556 311 279 4,040 1,605 1,192 949
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RESERVES RECONCILIATION
PROVED PLUS
PROVED PROBABLE
(MMbbls) (MMbbls)
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December 31, 2002 222.0 336.0
Production (1) (5.2) (5.2)
Revisions (2.8) (19.8)
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December 31, 2003 214.0 311.0
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(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 will provide
a reserve life of approximately 27 years based on anticipated bitumen production
rates of 155,000 barrels per day (our share is 31,000 barrels per day).
The following table outlines the potential undeveloped resources available on
the remainder of Lease 13 and on three nearby oil sands leases owned by Shell,
namely Leases 88, 89 and 90. In so far as we undertake 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.
POTENTIAL RESOURCES
TOTAL RESOURCES WESTERN'S SHARE
(MMbbls) (MMbbls)
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Remainder of Lease 13 and Lease 90 3,200 640
Leases 88 and 89 3,900 780
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Total 7,100 1,420
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CORPORATE RESULTS
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses were $6.5 million in 2003 or $1.29 per
barrel (2002 - $5.7 million). This year-over-year increase reflects additional
personnel as the Project entered the operating phase. As well, our early
adoption of the policy to expense stock options as a compensation expense in
2003 added $0.3 million to administrative expenses.
INSURANCE EXPENSES
Insurance expenses were $1.7 million in 2003 (2002 - $0.01 million). During the
fourth quarter of 2003, Western established US$500 million of Property and
Business Interruption Insurance coverage and Liability Insurance coverage of
US$100 million. The annual premium for these policies is approximately $9.0
million. At December 31, 2003, we had incurred $7.7 million in respect of these
policies, of which $1.4 million had been expensed in the year and $6.3 million
remained in prepaid expenses. The remainder of the insurance expense for 2003
represents director and officer liability insurance and other general office
insurance.
WESTERN OIL SANDS - MD&A 6
INTEREST EXPENSE
During 2003 we incurred $60.5 million in interest charges on our debt
obligations (2002 - $48.1 million) and $1.4 million on the capital lease
obligations. These obligations included US$450 million in Senior Secured Notes,
a $100 million Senior Credit Facility and a $240 million Revolving Credit
Facility. 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. 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) 2003 2002
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INTEREST EXPENSE
Interest Expense on Long-term Debt (1) $ 60,522 $ 48,126
Less: Capitalized Interest (23,479) (48,126)
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Net Interest Expense on Long-term Debt 37,043 --
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Interest on Obligations under Capital Lease 1,386 --
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Net Interest Expense $ 38,429 $ --
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LONG-TERM DEBT FINANCING
US$450 Million Senior Secured Notes (2) $ 581,580 $ 710,820
Revolving and Senior Credit Facilities (1) 279,000 65,000
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Total Long-term Debt $ 860,580 $ 775,820
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Average Long-term Debt Level $ 818,200 $ 527,651
Average Cost of Long-term Debt 7.40% 9.12%
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(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 7(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.
DEPRECIATION, DEPLETION & AMORTIZATION
In 2003, we recorded $27.5 million as depreciation, depletion and amortization
expense. 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.
Depletion and amortization have only been recorded since June 1, 2003, the date
commercial operations commenced.
DEPRECIATION, DEPLETION & AMORTIZATION
(thousands) $/bbl
- --------------------------------------------------------------------------------
Depreciation and Depletion $ 19,994 $ 3.96
Amortization 7,537 1.49
- --------------------------------------------------------------------------------
Total Depreciation, Depletion and Amortization $ 27,531 $ 5.45
================================================================================
FOREIGN EXCHANGE
While the oil and gas industry benefited in 2003 from sustained high commodity
prices, this was tempered by a strengthening Canadian dollar that moved from
US$0.63 to US$0.77 during the year. For Western, the foreign exchange impact on
revenues was somewhat offset by lower interest costs on our US dollar
denominated Senior Secured Notes and a reduced liability (as measured in
Canadian dollars) associated with this debt. In 2003 we recorded an unrealized
foreign exchange gain of $129.3 million relating to the conversion of the US
denominated Senior Secured Notes into Canadian dollars. 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 totaling $1.5 billion that have been accumulated
over the past three years mainly through our 20 per cent share of construction
costs for the Muskeg River Mine and Extraction Plant and the Scotford Upgrader.
These tax pools will be used to offset future taxable income and extend the time
horizon until we must pay cash taxes.
For the year ended December 31, 2003 we recognized a future income tax asset of
$6.3 million compared to a future income tax liability at December 31, 2002 of
$0.5 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.
WESTERN OIL SANDS - MD&A 7
During 2003 we expensed $3.1 million (2002 - $2.9 million) with respect to the
Large Corporations Tax. This was offset by a future income tax recovery of $4.3
million arising from the potential future benefit of the loss carry forwards.
TAX POOLS
December 31 (thousands) 2003 2002
- --------------------------------------------------------------------------------------------
Canadian Exploration Expense $ 123,178 $ 45,214
Canadian Development Expense 15,993 15,993
Canadian Exploration and Development Overhead Expense 2,677 2,704
Cumulative Eligible Capital 4,114 4,039
Capital Cost Allowance 25,661 25,632
Accelerated Capital Cost Allowance 1,180,940 1,031,616
- --------------------------------------------------------------------------------------------
Total Depreciable Tax Pools $ 1,352,563 $ 1,125,198
Loss Carry Forwards 129,340 45,274
Financing and Share Issue Costs 25,239 34,875
- --------------------------------------------------------------------------------------------
Total Tax Pools $ 1,507,142 $ 1,205,347
- --------------------------------------------------------------------------------------------
NET EARNINGS
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 EBITDA:
December 31 (thousands) 2003 2002 2001
- --------------------------------------------------------------------------------------------
NET EARNINGS (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS $ 15,003 $(10,286) $ (7,015)
Add (Deduct):
Depreciation, Depletion and Amortization 27,531 192 170
Accretion on Asset Retirement Obligation 471 -- --
Stock-based Compensation 278 -- --
Write-off of Deferred Charges -- 22,759 --
Foreign Exchange Gain (35,280) -- --
Future Income Tax Recovery (4,330) (22,551) --
Charge for Convertible Notes 2,130 1,283 --
- --------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS, BEFORE
CHANGES IN NON-CASH WORKING CAPITAL $ 5,803 $ (8,603) $ (6,845)
Add (Deduct):
Interest 38,429 -- --
Stock Based Compensation (278) -- --
Realized Foreign Exchange Loss 304 -- --
Large Corporations Tax 3,079 2,905 1,535
- --------------------------------------------------------------------------------------------
EBITDA $ 47,337 $ (5,698) $ (5,310)
- --------------------------------------------------------------------------------------------
PLEASE REFER TO PAGE 38 FOR A DISCUSSION OF NON-GAAP FINANCIAL MEASURES.
Our net earnings attributable to common shareholders totaled $15.0 million
($0.30 per share) in 2003 including the seven months of commercial operations.
This compares to a net loss attributable to common shareholders of $10.3 million
($0.21 per share) in 2002 prior to operational start-up. Earnings for the 2003
period reflect $35.3 million ($29.1 million net of tax) of unrealized foreign
exchange gains on our US$450 million Senior Secured Notes and a future income
tax recovery of $4.3 million. Earnings before interest, taxes, depreciation,
depletion and amortization, and foreign exchange gains were $47.3 million, again
including only seven months of commercial operations. Cash flow from operations
for 2003 before changes in non-cash working capital was $5.8 million ($0.12 per
share) after $38.4 million in interest charges and $3.1 million in Canadian
Large Corporations Tax. We anticipate that in 2004, with a full year of
commercial operations, EBITDA and cash flow from operations will improve as
production volumes stabilize and reach design capacity, synthetic crude sales
increase and operating costs improve.
WESTERN OIL SANDS - MD&A 8
QUARTERLY INFORMATION
The following table summarizes key financial information on a quarterly basis
for the last two fiscal years.
QUARTERLY INFORMATION
(millions, except per share amounts) Q1 Q2 Q3 Q4 Total
- ------------------------------------------------------------------------------------------------
2003
Revenue $ -- $ 24.9 $ 122.5 $ 133.7 $ 281.1
Capital Expenditures, Net 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)(4) (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
- ------------------------------------------------------------------------------------------------
2002
Revenue $ -- $ -- $ -- $ -- $ --
Capital Expenditures, Net 110.0 133.2 145.3 139.0 527.5
Long-term Debt 418.5 683.4 713.6 775.8 775.8
Cash Flow from Operations (1) (1.7) (1.9) (1.8) (3.2) (8.6)
Cash Flow per Share (2)(5) (0.03) (0.04) (0.04) (0.07) (0.18)
Earnings (Loss) Attributable
to Common Shareholders (1.8) (24.7) (1.8) 18.0 (10.3)
Earnings (Loss) per Share,
Basic and Diluted 0.04 (0.51) (0.04) 0.38 (0.21)
- ------------------------------------------------------------------------------------------------
(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.
(4) INCLUDES UNREALIZED FOREIGN EXCHANGE GAINS ON US$450 MILLION SENIOR SECURED
NOTES (Q2 - $7.0 MILLION, Q3 - $2.0 MILLION, Q4 - $26.3 MILLION).
(5) PLEASE REFER TO PAGE 38 FOR A DISCUSSION OF NON-GAAP FINANCIAL MEASURES.
FINANCIAL POSITION
Over the past three years, 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 achieved start-up, our primary
objective is to ensure sufficient working capital exists to fund our operations
and looking forward, to ensure we have sufficient resources to enable Western to
participate in expansion projects or other investment opportunities that may
arise.
DEBT FINANCING
In 2003, we maintained our US$450 million of Senior Secured Notes along with a
$100 million senior credit facility held with a syndicate of chartered banks;
$75 million of which was to be 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. At December 31, 2003, $91.0 million (2002 - $45.0 million) had
been drawn under this facility, with letters of credit issued in the amount of
$7.1 million (2002 - $15.4 million).
The main change in debt financing in 2003 was establishing a long-term working
capital facility to sustain us through operations. To this end, a $50 million
Revolving Facility established in November of 2002 was increased in tranches
over the year. In January, the facility expanded to $75 million with the
addition of another bank to the syndicate, followed by a further increase in May
to $110 million with the same banking syndicate. In October, a new $240 million
Revolving Credit Facility was established, refinancing the Revolving Facility
and providing for the repayment of the $88 million in Convertible Notes. At
year-end, $188 million was drawn and outstanding against the new Revolving
Credit Facility compared with $20 million drawn on the Revolving Facility at
December 31, 2002.
WESTERN OIL SANDS - MD&A 9
EQUITY FINANCING
In February 2003, we issued 2,050,000 Common Shares at a price of $24.50 per
share for gross proceeds of approximately $50.2 million. The Common Shares were
offered to the public on a bought-deal basis through a syndicate of Canadian
underwriters. This offering was required as a direct result of not having
received any of the insurance proceeds from our $200 million Cost Overrun
Insurance Policy. Net proceeds from the issue were used to fund remaining costs
for the Project and related expenses, for general corporate purposes and to
reduce some of our short-term borrowings.
EQUITY CAPITAL
At December 31 2003
Issued and Outstanding:
Common Shares 49,956,271
Class D Preferred Shares, Series A 666,667
- --------------------------------------------------------------------------------
50,622,938
Outstanding:
Class A Warrants 494,224
Stock Options 1,344,700
- --------------------------------------------------------------------------------
Fully Diluted Number of Shares 52,461,862
- --------------------------------------------------------------------------------
The share performance graph (shown below) 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 Composite Total Return Index and the TSX Oil and Gas Producers Total
Return Index assuming the reinvestment of dividends, where applicable, for the
comparable period. Western has significantly outperformed both indices since the
Company's inception.
CAPITAL EXPENDITURES
Construction activities have been conducted under a Joint Venture agreement
whereby we participate in the operations of the Project to our 20 per cent
working interest and are responsible for our respective share of the costs. Our
net capital expenditures totaled $148.5 million in 2003 and included: $122.6
million of project related expenditures; $22.9 million of direct capitalized
finance costs; and $3.0 million in other assets. Included in the project related
expenditures were $41.0 million for our share of construction costs and
sustaining capital for the Project; $29.9 million of capital repairs for the
January fire and freeze damages, net of insurance recoveries; $49.5 million of
net capitalized pre-operating costs for the Project; and $2.2 million of diluent
purchases.
As a result of fluctuations in the exchange rate of US to Canadian dollars
between January 1, 2003 and May 30, 2003, we capitalized an unrealized foreign
exchange gain on our US denominated Notes of $94.0 million. As of December 31,
2003, a net cumulative unrealized foreign exchange gain of $92.0 million had
been capitalized as finance costs during the pre-commercial operations period.
We capitalized a further $2.6 million in 2003 related to our share of the costs
for construction of the Hydrogen Manufacturing Unit ("HMU"), down from $15.7
million in 2002. The HMU costs are being financed through a capital lease.
CAPITAL ASSETS
SINCE
(MILLIONS) 2003 2002 2001 2000 1999 INCEPTION
- --------------------------------------------------------------------------------------------------------------------------
Project Expenditures (2) $ 122.6 $ 464.6 $ 422.1 $ 184.7 $ 9.4 $ 1,203.4
Capitalized Finance Costs 22.9 53.0 9.5 6.4 -- 91.8
Entry Fee -- (0.4) 1.2 -- 34.2 35.0
Shell Interest (1) -- 2.7 -- -- -- 2.7
Other Assets 3.0 7.6 0.8 1.0 3.1 15.5
- --------------------------------------------------------------------------------------------------------------------------
Net Cash Expenditures (2) 148.5 527.5 433.6 192.1 46.7 1,348.4
Non-Cash Capitalized Costs:
Shell Fees and Interest (1) -- -- 6.4 7.3 40.0 53.7
HMU 2.6 15.7 17.8 17.3 -- 53.4
Other 2.5 -- -- -- -- 2.5
Unrealized Foreign Exchange (Gain) Loss (94.0) 2.0 -- -- -- (92.0)
Asset Retirement Obligation 6.7 -- -- -- -- 6.7
Other Assets -- -- -- -- 1.1 1.1
- --------------------------------------------------------------------------------------------------------------------------
Total $ 66.3 $ 545.2 $ 457.8 $ 216.7 $ 87.8 $ 1,373.8
- --------------------------------------------------------------------------------------------------------------------------
(1) SHELL FEES AND ACCRUED INTEREST LIABILITY WERE PAID IN FULL IN APRIL 2002
FROM THE PROCEEDS OF THE SENIOR SECURED NOTES OFFERING.
(2) NET OF $9.7 MILLION OF INSURANCE RECOVERIES RELATED TO THE FIRE AND FREEZE
DAMAGE REPAIRS.
ANALYSIS OF CASH RESOURCES
WESTERN OIL SANDS - MD&A 10
Our cash balances decreased by $10.6 million during 2003, from $14.4 million at
December 31, 2002 to $3.8 million at December 31, 2003. Cash inflows included:
$126 million of long-term debt issued during the year (net of repayments and
refinancings); $49.5 million of net equity raised; $9.7 million of insurance
proceeds; and net operating cash flow of $5.8 million. Cash outflows included:
gross capital expenditures of $158.2 million; a working capital increase of
$38.3 million; debt issue costs and deferred charges of $1.0 million; a charge
for Convertible Notes of $3.6 million; and repayment of other long-term
liabilities of $0.5 million throughout the year.
For the most part, since June 1, 2003, cash flow from operations has funded our
operational activities with debt and equity capital used to fund project
expenditures and related working capital during construction. Capital
expenditures are expected to be lower in 2004 as we are now in operations.
Western anticipates spending approximately $46 million on capital activities
throughout 2004. This includes: $10 million for de-bottlenecking activities; $14
million for AOSP project capital; $9 million for sustaining capital; $9 million
for the Muskeg River Mine Expansion; and the remaining $4 million for other
corporate purposes.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
We have assumed various contractual obligation and commitments in the normal
course of our operations. Summarized below are significant financial obligations
that are known as of February 18, 2004, 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.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
PAYMENTS DUE BY PERIOD
<1 YEAR 1-3 YEARS 4-5 YEARS AFTER 5 YEARS TOTAL
- -----------------------------------------------------------------------------------------------------
US$450 Million Senior Secured Notes $ -- $ -- $ -- $ 581,580 $ 581,580
Senior Credit Facility -- 91,000 -- -- 91,000
Revolving Credit Facility (1) -- -- -- 188,000 188,000
Obligations Under Capital Lease 1,340 1,340 1,340 48,930 52,950
Obligations Under Operating Lease 2,380 8,900 13,140 26,340 50,760
Feedstock and Transportation 71,581 154,017 98,282 305,600 629,480
Electrical and Thermal Energy 21,102 41,801 42,180 307,709 412,792
- -----------------------------------------------------------------------------------------------------
Total Contractual Obligations $ 96,403 $ 297,058 $ 154,942 $1,458,159 $2,006,562
- -----------------------------------------------------------------------------------------------------
(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 15 AND 16, 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
limit of the policy, being $200 million, and will also be seeking interest and
other damages. The arbitration panel has now been constituted and we anticipate
proceedings will commence shortly. 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 totaling $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 the year, 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 $9.7 million has been received by Western as of December 31, 2003 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 for our share) in respect of loss of profits due to
production delays from the fire.
No amounts, other than those collected at December 31, 2003, 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.
OUTLOOK
Our immediate focus is on continuous improvement as we look to stabilize
production volumes by increasing plant availability. In 2004 we anticipate that
production volumes will increase towards sustained design capacity rates and
unit operating costs will improve over levels achieved in 2003. We expect to
provide further guidance on unit operating costs and annual production volumes
during the year, as ramp-up continues. The long-term target range for unit
operating costs is $12.00 to $14.00 per barrel at Alberta gas price levels
experienced in 2003 ($10.00 to $12.00 per barrel based on $4.00 per thousand
cubic feet natural gas prices). Unit cash costs will be above this target in
2004 primarily due to the production ramp-up curve and additional non-recurring
costs during ramp-up. Gas costs are a significant variable cost representing
approximately 20 per cent of total operating cost. There has historically been a
linkage between oil and gas prices that could
WESTERN OIL SANDS - MD&A 11
provide a partial natural hedge. Our capital expenditure program in 2004 will be
approximately $46 million including: $10 million for de-bottlenecking
activities; $14 million for AOSP project capital; $9 million for sustaining
capital; $9 million for the Muskeg River Mine Expansion; and the remaining $4
million for other corporate purposes. Excess free cash flow will be applied to
reduce our credit facilities.
We are evaluating opportunities to further expand our production base through
de-bottlenecking and development of the remaining oil sands leases that we have
access to under the Joint Venture agreement with our Joint Venture partners.
De-bottlenecking activities are being initiated in 2004 and are expected to
further increase production to 180,000 barrels per day over the next two years.
The Joint Venture is developing, or has plans to develop, reserves from a total
remaining resource base on Leases 13, 88, 89 and 90 estimated at 8.7 billion
barrels (1.7 billion barrels for our share). We have commenced work on
permitting the expansion of our existing operations at the Muskeg River Mine
(MRM). Once approvals for the MRM Expansion are received, we will move ahead
with the project development phase, which will include feasibility studies and
continued community dialogue. Western anticipates that the MRM Expansion may
increase the production capacity of our existing facilities by up to 50 per
cent. We recently received preliminary approval from a joint panel of the AEUB
and the Federal Government for the Jackpine Mine - Phase 1 development of the
eastern portion of Lease 13. The application is subject to 19 conditions and
must now be approved by the Cabinets of both the Provincial and Federal
governments. Once approvals are received, we will move ahead with the project
development phase, which includes feasibility studies and continued community
dialogue. This expansion project has the potential to add 200,000 barrels per
day (40,000 barrels per day net to us) of bitumen production. A potential
expansion to include Phase 2 of the Jackpine Mine Expansion could contribute a
further 100,000 barrels per day (20,000 barrels per day net to Western). The
timing and details of any expansion will be subject to the outcome of future
evaluations of economics, market needs, regulatory requirements and sustainable
development considerations. We are also considering the acquisition of
additional oil sands leases that are or may become available in the Athabasca
oil sands area.
SUSTAINABILITY
We 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.
We at Western believe that our commitment to sustainable development and
corporate responsibility is critical to sound operations and forms the
foundation upon which we will build our future.
ENVIRONMENT
Environmental performance was impressive with a sulphur recovery rate exceeding
the 98 per cent requirement, and only one Class 2 incident3 for the year. We
have worked hard in the design of the Project to ensure environmental effects
can be managed, and so that 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. The raw water intake area is the most
recent example of achieving successful progressive reclamation. By next summer,
the site will be introducing a variety of native grasses and shrubs as well as
aspen and spruce trees.
The AOSP is implementing a comprehensive greenhouse gas (GHG) management plan.
The plan will focus 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.
SAFETY
Significant achievements were recorded in 2003 in the critical area of safety.
For the Project as a whole, no employee experienced serious injury, including
during the most significant incident of the year, the fire and hydrocarbon
release at the Muskeg River Mine, as we recorded:
o A Lost Time Injury frequency 4 of 0.03 per 200,000 hours worked compared
with the oil sands mining and extraction industry average 5 of 0.08.
o A total Recordable Injury frequency 4 of 0.90 per 200,000 hours worked
compared with the the oil sands mining and extraction industry average 5 of
1.12.
COMMUNITIES
The Project continues to build on the commitments made during early consultation
for the AOSP, including maximizing local benefits. In 2003, local procurement
figures were $229 million to Wood Buffalo contractors, including close to $25
million to Aboriginal companies. As well, jobs created by the AOSP are filled by
our neighbours whenever possible. This has resulted in 60 per cent local hire
rate for the Muskeg River Mine. In the mining area we are closer to 90 per cent
local hires.
Over the life of the Project, the Regional Municipality of Wood Buffalo has also
benefited through community investments of over $1.5 million by the Joint
Venture. This includes donations towards capital funding to build the new
Technology Centre at Keyano College, and contributions toward the purchase of
two medical outreach vehicles for outlying aboriginal communities.
WESTERN OIL SANDS - MD&A 12
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 the key areas of exposure
for us 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, that asset being our investment in oil
sands through the Project. As such, all capital expenditures are directly or
indirectly related to oil sands construction and development with the majority
of our operating cash flow being derived from oil sands operations.
We are subject to the operational risks inherent in the oil sands business. Any
unplanned operational outage or slowdown can impact production levels, costs and
financial results. Factors that could influence the likelihood of this include,
but are not limited to, 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 2003 we established US$500 million of
Property and Business Interruption Insurance as well as US$100 million of
Liability Insurance to protect our ownership interest against losses or damages
to the owners' facilities, to preserve our operating income and to protect
against our risk of loss to third parties.
The Project depends 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 HMU and Dow Chemicals Canada
Inc., or Dow; and
o Electricity and steam are provided to the Upgrader from the Upgrader
cogeneration facility.
All of these third party arrangements are critical 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 sensitivities of our cash flow and net earnings
per share to certain relevant operating factors once the Project achieves stable
production rates. 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$27.00 per barrel, a foreign exchange rate of US$0.75 per
Canadian dollar and a constant Alberta gas cost of Cdn$5.01 per thousand cubic
feet.
WESTERN OIL SANDS - MD&A 13
SENSITIVITY ANALYSIS
BASIC BASIC
CASH FLOW CASH FLOW EARNINGS EARNINGS
VARIABLE VARIATION ($ millions) PER SHARE ($ millions) PER SHARE
- ---------------------------------------------------------------------------------------------------------------------
Production 1,000 bbls/day $ 4.44 $ 0.09 $ 4.82 $ 0.10
Oil Prices US$1.00 $ 15.40 $ 0.30 $ 9.85 $ 0.19
Non-Gas Operating Costs $1.00/bbl $ 11.32 $ 0.22 $ 7.24 $ 0.14
Gas Prices (2) $0.10/Mcf $ 0.56 $ 0.01 $ 0.36 $ 0.01
Foreign Exchange (1) US/Cdn .01 $ 2.40 $ 0.05 $ 3.52 $ 0.07
- ---------------------------------------------------------------------------------------------------------------------
(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 $3.06 MILLION BASED ON DECEMBER 31, 2003 US DOLLAR
DENOMINATED DEBT LEVELS.
(2) EACH $1.00 PER THOUSAND CUBIC FEET CHANGE IN GAS PRICE RESULTS IN A CHANGE
OF $0.41 PER BARREL IN OPERATING COST.
Our financial results will be dependent upon 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:
HEDGING SUMMARY
UNREALIZED INCREASE
NOTIONAL HEDGE SWAP (DECREASE) TO FUTURE
INSTRUMENT VOLUME PERIOD PRICE REVENUE (thousands)
- ---------------------------------------------------------------------------------------------------------------
WTI Swaps 20,000 bbls/d Jan 1, 2004 to Dec 31, 2004 US$27.37 (Cdn$25,955)
WTI Swaps 16,000 bbls/d Jan 1, 2005 to Mar 31, 2005 US$26.17 (Cdn$3,221)
WTI Swaps 7,000 bbls/d Apr 1, 2005 to Dec 31, 2005 US$26.87 (Cdn$850)
- ---------------------------------------------------------------------------------------------------------------
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, covers
certain costs, expenses and losses of revenue through the construction period
arising from causes beyond our control and including: (i) costs and expenses or
loss of revenues arising from a delay in achieving a guaranteed production
level; (ii) costs and expenses incurred in connection with the modification,
repair or replacement of equipment or material, which are directly related to
achieving guaranteed production levels; (iii) escalation in Project costs beyond
the budgeted Project costs, which are 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 provides coverage
for increased costs for Western's share of the Project of up to $200 million to
the extent the increased costs are 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
WESTERN OIL SANDS - MD&A 14
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, and foreign exchange
gains ("EBITDA") 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 West Texas Intermediate ("WTI")
benchmark. The additional information should not be considered in isolation or
as a substitute for measures of operating performance prepared in accordance
with Canadian Generally Accepted Accounting Principles ("GAAP").
Non-GAAP financial measures do not have any standardized meaning prescribed by
Canadian GAAP and are therefore unlikely to be comparable to similar measures
presented by other issuers. Management believes that, in addition to Net
Earnings (Loss) per Share and Net Earnings (Loss) Attributable to Common
Shareholders (both Canadian GAAP measures), cash flow from operations per share
and EBITDA 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, EBITDA 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.
WESTERN OIL SANDS - MD&A 15
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.
FUTURE INCOME TAX
We have recognized future income tax assets and liabilities at December 31,
2003. 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.
CHANGE IN ACCOUNTING POLICIES
ASSET RETIREMENT OBLIGATION
Effective January 1, 2003 Western early adopted 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. Over the estimated life of the
asset and liability Western recognizes depletion on the asset and accretion on
the liability.
STOCK-BASED COMPENSATION PLAN
We have a stock-based compensation plan, which is described in Note 13.
Effective January 1, 2002, we adopted CICA 3870 "Stock-based Compensation and
Other Stock-based Payments". CICA 3870 is applied to all stock-based payments to
non-employees and to employee awards that are direct awards of stock, stock
appreciation rights and similar awards to be settled in cash. CICA 3870 is
applied to all grants of stock options on or after January 1, 2002.
During the fourth quarter, effective for January 1, 2003, we began prospectively
recognizing compensation expense for options granted under the plan in
accordance with the fair value method. Under the transitional provisions in CICA
3870, we are required only to apply the fair value based method, and record
compensation expense and Contributed Surplus, to awards granted, modified or
settled on or after the beginning of the fiscal year, in which we adopt the fair
value method for those awards. Accordingly, only awards issued from January 1,
2003 require compensation expense to be recognized in accordance with CICA 3870.
Compensation expense for options granted during 2003 is determined based on the
fair values at the time of grant and is recognized over the estimated vesting
periods of the respective options. For options granted prior to January 1, 2003,
we continue to disclose the pro forma net earnings (loss) impact of the related
compensation expense. Pro forma compensation-related earnings impacts are
determined on the same basis as the 2003 options.
Consideration received on the exercise of stock options granted is credited to
share capital, and if related to any stock options that were granted during the
year ended December 31, 2003, then an amount equal to the compensation expense
recognized to that date is reclassified from Contributed Surplus to Common
Shares.
1 IEA International Energy Outlook
2 Application of counter-current decantation technology to bitumen froth
cleaning circuit at the extraction plant.
3 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.
4 Calculated as the number of incidents multipled by 200,000 (100 person
years) divided by the number of combined exposure hours of all direct
contractors and employees.
5 Oil sands mining and extraction industry average based on the average of
Shell, Syncrude and Suncor.