M A N A G E M E N T ' S D I S C U S S I O N A N D A N A L Y S I S
The following discussion of financial condition and results of operations was
prepared as of March 28, 2006 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 and prospective investors in
the Company's securities not to place undue reliance on forward-looking
information as by its nature, it is based on current expectations that involve
a number of assumptions, inherent risks and uncertainties, which could cause
actual results to differ materially from those anticipated by Western. For a
description of the risks and uncertainties facing Western, see "Outlook for
2006".
For additional information relating to the risks and uncertainties facing
Western, refer to Western's Annual Information Form for the year ended
December 31, 2005, which is available on SEDAR at www.sedar.com.
O V E R V I E W
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 a 60 per cent interest, and Chevron Canada Limited
("Chevron"), which holds the remaining 20 per cent. The AOSP consists of two
key facilities: the Muskeg River Mine located 70 kilometres north of Fort
McMurray, 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. The Mine and Upgrader are connected
by a 493-kilometre pipeline.
At this time, Western's 20 per cent investment in the AOSP is our most
material and only operating asset. We generate revenue from the sale of our 20
per cent portion of the synthetic crude oil and other products produced at the
Scotford upgrader. Approximately one-third of the volumes produced are a
mixture of light, medium and heavy vacuum gas oil ("LMHVGO") that is sold to
Shell under a long-term contract for use in their adjacent refinery. In
addition, our processes produce two grades of synthetic crude oil: Premium
Albian Synthetic ("PAS") and Albian Heavy Synthetic ("AHS"). Our share of
these products is marketed and sold by Western to various refineries
throughout North America.
Sustained higher commodity prices, together with greater than design
production levels during 2005, combined to achieve record production, revenue,
net income and cash flow from operations for Western. During the year, our
capital expenditure program was financed entirely out of cash flow. Excess
cash was applied to reduce our bank borrowings. Western applied $175 million
to the repayment of bank credit facilities during the year, which resulted in
a significant strengthening of our balance sheet. Our improving credit
profile, combined with the implementation of a new strategic oil commodity
risk management program, has put Western in a strong financial position to
fund its share of the expansion efforts announced by the Joint Venture that
will occur over the next several years.
During 2005, Western achieved successive quarterly production records
from the second quarter through to the fourth quarter. In the fourth quarter
of 2005, production averaged approximately 35,600 barrels per day
(approximately 178,000 barrels per day at the Project level). Operational
difficulties at the Upgrader in the fourth quarter of 2004 extended into the
first quarter of 2005 and impacted first quarter 2005 performance. The
quarterly production rates established record annual average production of
approximately 32,000 barrels per day in 2005, representing an 18 per cent
increase over production volumes reported in 2004. These production rates set
the stage for continued operational stability and growing profitability for
the AOSP's existing assets.
Reliability and availability of our existing AOSP facilities, together
with on-time, on-budget execution of our AOSP expansion plans, is our primary
focus. The objective is to take Western's production beyond 100,000 barrels
per day over the next eight to ten years. This growth strategy also includes
optimizing the value of our existing world-class assets through technological
enhancements. Furthermore, as Western matures and evolves as an organization,
our growth strategy includes opportunistically growing our business and
leveraging our strengths by taking our core competencies and skills and
applying them to new business opportunities. In this regard, one of Western's
key objectives is to identify and capture large, long-life projects with
significant hydrocarbon resource potential to create additional value for our
shareholders.
O P E R A T I N G R E S U L T S
Western commenced commercial operations on June 1, 2003, which was defined by
Management as attaining 50 per cent of the Project's productive design
capacity of 155,000 barrels per day, with all aspects of the facilities fully
operational. Since that time, 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.
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Highlights 2005 2004 2003
- -----------------------------------------------------------------------------------------------------------------
Operating Data (bbls/d)
Bitumen Production 31,994 27,108 23,596
Synthetic Crude Sales 42,534 36,210 32,207
Operating Expense per Processed Barrel ($/bbl) 22.06 21.17 20.71
=================================================================================================================
Financial Data ($ thousands, except as indicated)
Gross Revenue 910,330 636,911 281,093
Realized Crude Oil Sales Price - Oil Sands ($/bbl) (1) (2) 49.91 34.60 32.81
Cash Flow from Operations (3) 244,231 23,044 5,803
Cash Flow per Share - Basic ($/Share) (1) (4) 1.52 0.15 0.04
Net Earnings Attributable to Common Shareholders (6) 149,449 19,452 15,003
Net Earnings per Share ($/Share)
Basic 0.93 0.12 0.10
Diluted 0.92 0.12 0.10
EBITDAX (1) (5) 307,008 87,587 47,615
Net Capital Expenditures (7) 46,833 39,968 148,473
Total Assets 1,590,520 1,470,870 1,458,424
Long-Term Debt 565,655 662,620 860,580
Long-Term Financial Liabilities (8) 706,880 716,094 914,773
Weighted Average Shares Outstanding - Basic (Shares) 160,169,887 156,926,514 151,032,996
=================================================================================================================
(1) Please refer to page 44 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 25 for calculation.
(3) Cash flow from operations is expressed before changes in non-cash working
capital.
(4) Cash flow per share is calculated as cash flow from operations divided by
weighted average common shares outstanding, basic.
(5) Earnings before interest, taxes, depreciation, depletion, amortization,
stock-based compensation, accretion on asset retirement obligation,
foreign exchange and risk management as calculated on page34.
(6) Western has not paid cash dividends in any of the above referenced fiscal
years.
(7) Net capital expenditures are capital expenditures net of any insurance
proceeds received during the period.
(8) Long-term financial liabilities includes long-term debt, option premium
liability and lease obligations. Prior years are restated to include
lease obligations.
F I N A N C I A L P E R F O R M A N C E
Revenue
Western achieved record gross crude oil sales revenue in fiscal 2005 totalling
$910.3 million (2004 - $636.9 million), including $777.9 million (2004 -
$458.5 million) from proprietary production at an average realized price of
$49.91 per barrel (2004 - $34.60 per barrel). Gross revenue rose 43 per cent
primarily as a result of an 18 per cent increase in production during the
year, combined with a 44 per cent increase in blended price realizations.
Gross revenue includes the effects of risk management activities that reduced
revenue by $110.4 million (2004 - $131.4 million), and reduced the average
realized price by $7.11 per barrel during 2005 (2004 - $9.92 per barrel).
Western's crude oil sales were subject to an overall quality differential
of $12.27 per barrel (2004 - $8.44 per barrel) off of the Edmonton PAR
benchmark crude oil price of $69.29 per barrel in 2005. Forced operational
outages at the Upgrader in the first quarter of 2005 resulted in a larger
percentage of heavy crude in our overall sales mix and, since these streams
receive a lower price, overall sales price realizations decreased. Sales price
realizations during 2005 were also negatively impacted by a widening of the
heavy oil differential to West Texas Intermediate ("WTI") compared to 2004.
The heavy oil differential to WTI widened to an average 39 per cent during
2005 compared to an average of 34 per cent in 2004, and has historically
represented approximately 30 per cent of stated posted WTI prices. As the
graph on page 24 indicates, Western's sales price realizations are largely
correlated to movements in WTI. Over the last two years, the only quarters
where this relationship was not maintained was during the fourth quarter of
2004 and first quarter of 2005, where forced operational outages occurred,
resulting in Western's sales mix skewed to a greater proportion of heavy crude
oil.
The AOSP is actively identifying optimization initiatives to reduce the
Project's exposure to heavy oil price differentials. We have observed that the
heavy oil differential to WTI tends to increase as WTI itself appreciates. If
this relationship continues, we would expect heavy oil differentials to remain
wide in periods of robust commodity prices. Western expects its sales price
realizations to improve in 2006 largely due to the absence of any fixed-price
hedges, which ended in December 2005, allowing Western to fully participate in
actual crude oil prices during the upcoming year. In total, Western's fixed
price hedging program, which commenced during 2003, reduced revenue by
approximately $250 million. These hedges were executed in late 2002 and over
the course of fiscal 2003 during a significantly lower crude oil price regime.
The hedging program (which locked-in a fixed WTI price on Western's share of
production from the AOSP ranging from 20,000 barrels per day down to 7,000
barrels per day at its completion in the last quarter of 2005) provided a base
line level of cash flow to meet future debt servicing and working capital
commitments and protected the Company from a precipitous drop in oil prices.
As detailed in the "Financial Risks" section, Western completed a
separate strategic crude oil risk management program during the third quarter
of 2005 covering a portion of our production from 2007 through to the end of
2009. The put/call "collar" structure employed establishes a floor price for
up to two-thirds of our expected production, yet allows for participation in
increasing oil prices during this period and, thereby, does not limit the
upside potential related to commodity price appreciation to the same degree as
the fixed-price swap contracts used previously.
Western generated net revenue of $591.4 million in 2005 compared to
$321.0 million in 2004, representing an 84 per cent increase. Net revenue
reflects the costs of purchased feedstocks and transportation costs downstream
of Edmonton. Feedstocks are crude oil products introduced at the Upgrader.
Some feedstocks are introduced into the hydrocracking/hydrotreating process
and others are used as blendstock to create various qualities of synthetic
crude oil products. The cost of these feedstocks depends on world oil markets
and the spread between heavy and light crude oil prices.
- -----------------------------------------------------------------------------
Net Revenue
($ thousands, except as indicated) 2005 2004
- -----------------------------------------------------------------------------
Revenue
Oil Sands (1) 777,876 458,502
Marketing and Transportation 132,454 178,409
=============================================================================
Total Revenue 910,330 636,911
Purchased Feedstocks and Transportation
Oil Sands 185,693 137,810
Marketing and Transportation 133,241 178,116
=============================================================================
Total Purchased Feedstocks and Transportation 318,934 315,926
Net Revenue
Oil Sands (1) 592,183 320,692
Marketing and Transportation (787) 293
=============================================================================
Total Net Revenue 591,396 320,985
Synthetic Crude Sales (bbls/d) 42,534 36,210
Crude Oil Sales Price ($/bbl) (2) 49.91 34.60
=============================================================================
(1) Oil sands revenue and net revenue are presented net of Western's hedging
activities.
(2) Realized crude oil sales price ($/bbl) is calculated as oil sands revenue
less any transportation costs divided by synthetic crude sales volume.
For the year ended 2005, $3.0 million (2004 - nil) had been incurred for
transportation costs related to oil sands.
O P E R A T I N G C O S T S
We believe that, to a certain extent, our operating costs are a function of
longer-term WTI prices. In 2005, WTI averaged US$56.56 per barrel, which put
upward pressure on certain cost components, including natural gas. Operating
costs for oil sands operations typically decline over time as the
technological and engineering challenges are addressed and resolved and as
efficiency and effectiveness programs are completed. These efficiencies are
being realized at the AOSP, and we expect to see a continued reduction in unit
operating costs over the coming years; however, this may be offset by
continued increases in the cost of natural gas and of basic materials and
supplies caused by major demand pull in critical supply markets and variations
in the ore body with respect to bitumen grade and strip ratio (ore to waste).
Given our state-of-the-art technology, and what we assess as a superior ore
body, we believe Western can be one of the lowest-cost producers of synthetic
crude oil in the Canadian oil sands.
Western's share of Project operating costs totalled $250.4 million in
2005 (2004 - $213.0 million). Included in this total are the costs associated
with removing overburden at the Mine and transporting bitumen from the Mine to
the Upgrader. On a per processed barrel of bitumen basis, unit operating costs
were $22.06 per barrel based on average production of 31,994 barrels per day
in 2005 compared to $21.17 per barrel based on average production of 27,108
barrels per day in 2004.
Higher unit operating costs in 2005 were largely due to increasing
natural gas costs for fuel, utilities and hydrogen supply as well as higher
input costs for materials and supplies in an escalating commodity price
environment. Natural gas costs per unit increased 19 per cent over 2004 as a
result of higher underlying gas prices. We also observed higher prices for
supplies and materials and contract services as a result of the heated
commodity environment, as these suppliers were themselves experiencing higher
demand for their goods and services leading to higher costs. Unit operating
costs in 2005 were also impacted by repair costs incurred in the first
quarter, stemming from the forced operational outages that commenced in the
fourth quarter of 2004 and extended into the first quarter of 2005. Unit
operating costs per processed barrel of bitumen were $25.44 per barrel in the
first quarter of 2005. Over the next three successive quarters, where the
Project achieved record production levels, unit operating costs averaged
$21.22 per processed barrel of bitumen, of which $5.10 per barrel relates to
natural gas.
Operating costs are, and will continue to be, a key metric among
companies active in the mineable oil sands industry. Companies that control
costs will drive better financial results. Different oil sands producers have
different cost structures and accounting treatments that require careful
analysis to make meaningful comparisons. Western, for example, includes the
cost of transporting processed bitumen from Fort McMurray to Edmonton as part
of overall operating costs, whereas other industry players net these
transportation costs from oil sands revenue. Western also includes in its
operating costs the cost to remove the overburden in its mining operations,
while some other oil sands producers capitalize such costs. Nevertheless, all
companies active in the energy industry are coming to terms with the higher
commodity price environment and associated increased costs for materials,
supplies and natural gas. Even though the entire industry cost structure has
shifted upwards, Western will continue to evaluate all methods to control and
reduce its cost structure. As the majority of the AOSP's operating costs are
fixed, to the extent the Project can maintain continuous reliable operations,
total unit operating costs will decrease as the costs are spread out over a
greater production base.
- ------------------------------------------------------------------------------
Operating Costs
($ thousands, except as indicated) 2005 2004
- ------------------------------------------------------------------------------
Operating Expenses for Bitumen Sold
Operating Expense - Income Statement 250,389 212,993
Operating Expense - (Inventoried)/Expensed in
Purchased Feedstocks 11,704 (3,058)
==============================================================================
Total Operating Expenses for Bitumen Sold 262,093 209,935
- ------------------------------------------------------------------------------
Sales (barrels per day)
Total Synthetic Crude Sales 42,534 36,210
Purchased Upgrader Blendstocks 9,979 9,112
==============================================================================
Synthetic Crude Sales Excluding Blendstocks 32,555 27,098
- ------------------------------------------------------------------------------
Operating Expenses per Processed Barrel ($/bbl) (1) 22.06 21.17
==============================================================================
(1) Operating expenses per processed barrel ($/bbl) is calculated as total
operating expenses for bitumen sold divided by synthetic crude sales
excluding blendstocks. This calculation recognizes that, intrinsic in the
Project's operations, bitumen production from the Mine receives an
approximate three per cent uplift as a result of the
hydrotreating/hydroconversion process, which is included in synthetic
crude sales excluding blendstocks.
O P E R A T I N G N E T B A C K S
Despite the forced operational outages experienced in the fourth quarter of
2004 that extended into the first quarter of 2005, Western achieved a robust
netback per barrel excluding commodity hedge impacts, compared to previous
quarters. Heavy oil differentials widened towards the end of the year and,
combined with the continued strength in the US/Cdn exchange rate, put pressure
on our fourth quarter results. The heavy oil differential widened in part due
to the seasonal reduction in demand by refineries as they undertake year-end
maintenance programs. We expect to achieve materially higher netbacks in 2006
due to the expiration of our fixed-priced swap hedging program on December 31,
2005, assuming that commodity prices maintain current levels. Hedging losses
of $110.4 million in 2005 materially decreased Western's netbacks.
Royalties
Royalties amounted to $4.0 million or $0.34 per barrel of bitumen in 2005
compared to $3.0 million or $0.30 per barrel of bitumen in 2004. Higher gross
royalties reflect record production levels in 2005, together with a higher
deemed bitumen price, the latter of which serves as the basis for the royalty
calculation. Initially, royalties are calculated at one per cent of the gross
revenue from the bitumen produced (based on its deemed value prior to
upgrading) until recovery of all capital costs associated with the Muskeg
River Mine and Extraction Plant, together with a return on capital equal to
the Government of Canada's federal long-term bond rate. After full capital
cost recovery, the royalty is calculated as the greater of one per cent of the
gross revenue on the bitumen produced or 25 per cent of the net revenue on the
bitumen produced. Western fully expects to participate in the expansions of
the AOSP. As such, Western anticipates that additional capital incurred to
construct the expansions will be added to the capital base for royalty
purposes. Western believes certain capital relating to the extraction of
bitumen will be "ring-fenced" for royalty purposes, which, in turn, will
extend our royalty horizon. Assuming a long-term WTI price of US$55.00 to
US$60.00 and a US/Cdn exchange rate of $0.85, we estimate our royalty horizon
on the Project to be approximately 2010, after which we will be paying
royalties at the higher rates. The royalty horizon may be accelerated or
postponed depending on future prices of crude oil, foreign exchange rates and
the timing and inclusion of capital expenditures.
R E S E R V E S, R E S O U R C E S A N D L A N D
Under the terms of the Joint Venture Agreement for the AOSP, Western and its
Joint Venture Participants have in place a Participation and Area of Mutual
Interest Agreement ("AMI"). The AMI stipulates that the Project Owners have
rights to participate in any additional leases that are acquired by any one of
the Joint Venture Participants in the Athabasca region.
Within the Project we have the following: proved and probable reserves
that are associated with the existing operations at the Muskeg River Mine;
resources on lands within the Joint Venture that have been evaluated; and
finally, undeveloped lands which have been acquired by all three Owners during
the past year that are included under the terms of the AMI and are subject to
evaluation for possible future development.
Reserves
GLJ Petroleum Consultants Ltd. ("GLJ") has independently estimated that the
proved and probable reserves on the west side of Lease 13 are 1.6 billion
barrels (310 million barrels net to Western). These proved and probable
reserves translate into a reserve life index of approximately 27 years based
on an anticipated undiluted bitumen production rate of 155,000 barrels per day
(31,000 barrels per day net to Western). Substantial reserve additions will be
made as the AOSP moves through the gating process for the upcoming phases of
expansion. Resources from our future expansions will be booked as reserves
when the expansion phases are permitted, funding is approved and certain
stipulations pursuant to the Joint Venture Agreement are satisfied. The table
below summarizes the Project's reserves and our share of those proved and
probable reserves as at December 31, 2005 on a synthetic crude oil basis
utilizing GLJ's forecast of escalating prices and costs. Synthetic crude oil
is dry bitumen, uplifted by three per cent for hydrocracking/hydrotreating.
The following information relating to our reserves and present values of
estimated future net cash flow constitutes forward-looking statements as it is
based upon assumptions relating to, among others, volumes of oil in place,
recoverability of bitumen, production rates, royalty rates, operating and
development costs, capital expenditures, commodity prices and foreign exchange
rates. For a description of the risks and uncertainties facing Western that
could impact on the volume and value of the reserves reported below, see
"Outlook for 2006".
- --------------------------------------------------------------------------------------------------------------------------
Reserves Summary Gross Working
- --------------------------------------------------------------------------------------------------------------------------
Present Value of Estimated Future
Project Interest Net After Net Cash Flow before Income Taxes
Reserves Reserves Royalty 0% 10% 15% 20%
- --------------------------------------------------------------------------------------------------------------------------
(MMbbls) (MMbbls) (MMbbls) ($ millions)
Proved 974 195 179 3,650 2,014 1,611 1,337
Probable 577 115 104 2,799 671 386 248
==========================================================================================================================
Proved Plus Probable 1,551 310 283 6,449 2,685 1,997 1,585
==========================================================================================================================
Reserves Reconciliation (Working Interest)
Proved Plus
(MMbbls) Proved Probable
- --------------------------------------------------------------------------------------------------------------------------
December 31, 2004 204 317
Production (12) (12)
Revisions 3 5
==========================================================================================================================
December 31, 2005 195 310
==========================================================================================================================
Resources
The AOSP has several leases that have been formally evaluated for resource
potential. These are Leases 88, 89, 90, 9 and 17 and the remainder of Lease
13. Western engaged Norwest Corporation ("Norwest") to conduct this
assessment. They provided high, best and low estimates of discovered resources
for each area, with the exception of Lease 17 which only includes a high
estimate. The best case estimate for the discovered resources on a total AOSP
basis exceeds 8.2 billion barrels in place or 1.6 billion barrels net to
Western. Except in the case of Lease 17 where data is limited, Norwest's
report is based on several critical assumptions in order to record
resources-in-place, namely, minimum bitumen by weight of seven per cent to
total weight, minimum mining thickness of three metres and maximum total
volume to bitumen in place ("TV:BIP") of 12:1. The details of the specific
leases are summarized in the table below.
- --------------------------------------------------------------------------------------------------------------------------
Estimate of Discovered Resources (1) (2) High Best Low
(MMbbls in place) (P90) (P50) (P10)
- --------------------------------------------------------------------------------------------------------------------------
Remainder of Lease 13 5,251 5,028 3,194
Lease 90 269 253 162
Leases 88 and 89 2,382 2,038 856
Lease 9 and 17 (3) 2,110 899 431
- --------------------------------------------------------------------------------------------------------------------------
Total 10,012 8,218 4,643
- --------------------------------------------------------------------------------------------------------------------------
(1 The table above represents total Project interest in the leases which are
currently held by Shell. Under the AMI, Western has the right to
participate in these leases to a 20 per cent level.
(2) "Discovered Resources" are those quantities of oil and gas estimated on a
given date to be remaining in, plus those quantities already produced
from, known accumulations. Discovered resources are divided into economic
and uneconomic categories, with the estimated future recoverable portion
classified as reserves and contingent resources, respectively.
(Source:Canadian Oil and Gas Evaluation Handbook, Volume 1, Section
5.2.2.)
(3) Norwest only inferred resources to Lease 17 (high estimate only)
reflecting a probability of only 10 per cent that the resource equals or
exceeds the estimated amount given the limited amount of data available
on this lease. Major assumptions used in the classification of inferred
resources for Lease 17 were average in-place bitumen content of 10 per
cent to total weight and ore thickness of approximately 15 metres over
less than half the lease area. Due to the level of uncertainty on this
lease, it should not be assumed that all or any part of an inferred
resource will be upgraded as a result of continued exploration.
Undeveloped Land
During 2005, Shell acquired additional mineable oil sands acreage including
leases 15, 309, 310, 351, 352, 631 and 632. These leases were acquired through
public land auctions held by the Government of Alberta. Pursuant to the AMI,
Western has rights to participate to a 20 per cent interest in the development
of these leases.
A second addition to the undeveloped land base are five heavy oil leases
recently purchased by Chevron. It is believed these leases would be amenable
to extract bitumen through in-situ recovery methods. Western has the right to
participate to a 20 per cent undivided interest in these leases. Our right may
be exercised upon Chevron providing us with formal notice of the purchase,
followed by our response within 60 days of that notice regarding our intent to
participate, together with the applicable payment.
A further addition to this already extensive land position is Lease 353,
which Western itself acquired during 2005, representing 8,225 acres. This
lease is also considered in-situ in nature. Western holds a 60 per cent
interest in this lease as both Shell and Chevron have elected to participate
to a 20 per cent interest. Western significantly increased its internal
organizational capabilities in 2004 and 2005 by adding senior technical staff
to develop our in-situ strategy.
Combining all of the leases under the AMI, the acreage position in the
Athabasca region now approaches 284,000 acres (60,000 acres net to Western),
more than doubling the land base compared to 2004. Of this total,
approximately 71 per cent represents mineable leases, with the remaining 29
per cent considered in-situ. The leases recently acquired by all Joint Venture
partners have not yet been evaluated for resource potential; however, several
are located adjacent to leases where resource evaluations have been conducted.
An extensive core-hole drilling program will be conducted over the next
several years on all of the newly acquired leases to evaluate the resource
potential. The leases recently acquired by Shell could potentially be
developed as an extension to the AOSP's continuous construction expansion
strategy.
The exploration and development of this significant land base, both
mineable and in-situ, could involve a substantial and material capital
commitment on the part of Western to maintain our rights. Assessments
regarding Western's involvement are always made in the context of maintaining
the integrity of our financial position and creating shareholder value.
C O R P O R A T E R E S U L T S
Research and Business Development
A small portion of Western's capital budget is directed to new business
development activities. These activities include: research and development
efforts with the objective of identifying ways to add value to our existing
assets; the addition of some internal technical capabilities in order to
evaluate opportunities as they arise either through our Joint Venture partners
or independently; and finally, as part of Western's long-range strategy, plans
include expanding our organizational capabilities to evaluate business
opportunities, domestically or internationally, by taking our core
competencies and skills and applying them to new ventures that represent
long-life projects with significant hydrocarbon resource potential. Western
incurred $10.7 million for research and business development expenses in 2005,
of which $5.0 million relates specifically to AOSP-related research projects.
In 2004, Western recorded $4.7 million for research and business development,
which related entirely to the impairment of a previously capitalized research
project. Amounts are higher compared to the prior year period as Western
continues to add significant technical and professional staff to source and
investigate business development activities.
General and Administrative Expenses
General and administrative expenses ("G&A") were $11.3 million in 2005 or
$0.97 per barrel compared to $8.1 million or $0.82 per barrel in 2004. The
increase is largely a function of Western analyzing certain business
development activities that result in higher levels of professional and legal
fees, travel and other corporate expenses that arise in conducting these
evaluations. It also reflects additional professional costs incurred during
2005 due to increased public company compliance requirements compared to 2004.
Insurance Expenses
Insurance expenses were $8.0 million in 2005 compared to $9.4 million in 2004.
Western maintains insurance policies covering property damage, business
interruption, commercial general liability and directors and officers
liability, in addition to various corporate policies. Insurance expense in
2005 is lower than the previous year due to a reduction in the premiums
associated with our policies and the strengthening of the Cdn/US exchange rate
as these premiums are paid in US dollars. There were no material modifications
in coverage compared to the prior year.
We are expecting insurance expenses to increase in 2006 as a result of
higher limits on such policies as business interruption, together with
increased premiums charged by insurance carriers on our corporate policies,
given worldwide events in the insurance marketplace.
Interest Expense
During 2005, total interest charges were $58.2 million, $3.0 million lower
than 2004. The 2005 expense of $58.2 million is comprised of $54.3 million
related to interest charges on our debt obligations (2004 - $59.1 million),
$2.6 million (2004 - $2.0 million) on our capital lease obligations and $1.3
million (2004 - $nil) on our option premium liability. The option premium
liability relates to Western's new strategic crude oil risk management program
implemented in the third quarter of 2005 and the decision to defer the
premiums associated with the put and call options purchased and sold,
respectively. Imbedded in the prices of the deferred options is a financing
charge that is reported as interest expense.
Western's debt obligations include US$450 million Senior Secured Notes
and a $340 million Revolving Credit Facility. The average percentage cost of
our debt increased over last year due to Western aggressively repaying debt
under its Revolving Credit Facility. As this debt is priced at a lower
interest rate, the average overall interest rate will increase since the
Senior Notes represent a larger percentage of the outstanding debt. The Notes
bear interest at 8.375 per cent and are not callable before their maturity
date of May 1, 2012. Western's ability to meet fixed debt servicing costs
continues to improve which can be measured by the interest coverage ratio.
This ratio has improved nearly seven-fold over the last two years, when
initially Western's leverage was significantly higher than at the end of 2005.
Interest expense on a per barrel basis has also decreased as debt is repaid
and production achieves sustained rates meeting or exceeding design
specifications.
The table on page 32 summarizes our interest expense and average cost of
debt for the past two fiscal years.
- -------------------------------------------------------------------------------
Interest and Long-Term Debt Financing
($ thousands, except as indicated) 2005 2004
- -------------------------------------------------------------------------------
Interest Expense
Interest Expense on Long-Term Debt 54,324 59,118 (2)
Interest on Obligations under Capital Lease 2,562 2,036
Interest on Option Premium Liability 1,279 -
===============================================================================
Total Interest Expense 58,165 61,154
===============================================================================
Long-Term Debt Financing
US$450 Million Senior Secured Notes (1) 524,655 541,620
Revolving and Senior Credit Facilities 41,000 216,000 (2)
===============================================================================
Total Long-Term Debt 565,655 757,620
===============================================================================
Average Long-Term Debt Level 661,638 809,100
Average Cost of Long-Term Debt (3) 8.21% 7.31%
===============================================================================
(1) Under Canadian GAAP, the Senior Secured Notes are recorded in Canadian
dollars at exchange rates in effect at each balance sheet date.
Unrealized foreign exchange gains or losses are then included on the
Consolidated Statement of Operations.
(2) For comparative purposes, amounts include the $95 million principal
outstanding under the $100 million Senior Credit Facility, which is
classified for accounting purposes as short-term liabilities pursuant to
its maturity on April 23, 2005.
(3) Calculated by dividing the interest expense on long-term debt by the
average long-term debt balance outstanding during the year.
Depreciation, Depletion and Amortization
In 2005, Western recorded $50.7 million as depreciation, depletion and
amortization expense compared to $44.5 million in 2004. Depletion is
calculated on a unit of production basis for our share of Project capital
costs, while previously deferred financing charges are amortized on a
straight-line basis over the remaining life of the debt facilities. The
increase for 2005 is primarily a result of an 18 per cent increase in
production in 2005 versus 2004.
- ---------------------------------------------------------------------------------------------------------------
Depreciation, Depletion &Amortization
Year ended December 31 2005 2004
- ---------------------------------------------------------------------------------------------------------------
($ thousands) $/bbl ($ thousands) $/bbl
- ---------------------------------------------------------------------------------------------------------------
Depreciation and Depletion 48,206 4.13 41,933 4.23
Amortization 2,532 0.22 2,582 0.26
===============================================================================================================
Total Depreciation, Depletion and Amortization 50,738 4.35 44,515 4.49
===============================================================================================================
Foreign Exchange
In 2005, WTI averaged US$56.56 per barrel compared to US$41.40 per barrel in
2004, representing a 37 per cent increase. This significant appreciation in
the commodity price was offset somewhat by a strengthening in the Canadian
dollar relative to the US dollar. For Western, the negative impact of the
foreign exchange rate increase on revenue was somewhat offset by lower
interest costs expressed in Canadian dollars on our US dollar denominated
Senior Secured Notes and a reduced liability (as measured in Canadian dollars)
associated with this debt. In 2005, Western recorded an unrealized foreign
exchange gain of $17.0 million compared to a gain of $40.0 million in 2004
relating to the conversion of the Senior Secured Notes to Canadian dollars. As
reference points, the noon-day closing foreign exchange rate on December 31,
2005 was $0.8577 US/Cdn compared to $0.8308 US/Cdn on December 31, 2004. In
terms of average noon-day rates for the respective periods, fiscal 2005 was
$0.8254 US/Cdn compared to $0.7683 US/Cdn for fiscal 2004.
Income Taxes
Western has sizeable tax pools totalling $1.4 billion that were accumulated in
conjunction with our 20 per cent share of the construction costs for the
Muskeg River Mine and Extraction Plant and the Scotford Upgrader. These tax
pools will be used to offset future taxable income and extend the time horizon
before we pay cash taxes.
For the year ended December 31, 2005, Western recorded a future income
tax liability of $56.4 million compared to a future income tax asset of $14.5
million at December 31, 2004. Western recognized approximately $71.0 million
of future income tax expense during the year as we had record profitability in
2005. During 2005, we expensed $3.0 million (2004 - $1.7 million) with respect
to the Large Corporations Tax. No other current taxes are payable and
Western's cash tax horizon is estimated to be 2010 given a long-term WTI price
of US$55.00 to US$60.00 and a US/Cdn foreign exchange rate of $0.85. Western's
forecasted cash tax horizon is predicated on the successful execution of the
AOSP expansion initiatives that would see gross AOSP production exceed 500,000
barrels per day.
Commencing in the latter part of 2005, discussions were held between the
AOSP and the Canada Revenue Agency ("CRA") regarding the proper
characterization of certain expenditures included in the Canadian exploration
expenses in those years. These discussions may result in a change to the
treatment of certain expenditures renounced pursuant to Western's flow-through
share offerings in prior years. Refer to the section titled "Flow-Through
Shares" and Western's financial statements (Note19).
- --------------------------------------------------------------------------------------
Tax Pools
December 31 ($ thousands) 2005 2004
- --------------------------------------------------------------------------------------
Canadian Exploration Expense 89,140 141,327
Canadian Development Expense 23,657 33,795
Canadian Exploration and Development Overhead Expense - -
Cumulative Eligible Capital 7,925 7,479
Capital Cost Allowance 126,001 89,194
Accelerated Capital Cost Allowance 1,090,155 1,087,056
======================================================================================
Total Depreciable Tax Pools 1,336,878 1,358,851
Loss Carry Forwards 14,000 163,740
Financing and Share Issue Costs 9,596 15,130
======================================================================================
Total Tax Pools 1,360,474 1,537,721
======================================================================================
Net Earnings
Net earnings increased seven-fold, reaching $149.4 million ($0.93 per share)
in 2005, compared to $19.5 million ($0.12 per share) in 2004. Earnings for the
year reflect $17.0 million ($14.1 million net of tax) of unrealized foreign
exchange gains on our US$450 million Senior Secured Notes, a $13.5 million
($9.1 million net of tax) unrealized gain on risk management activities and a
future income tax expense of $71.0 million. Earnings before interest, taxes,
depreciation, depletion and amortization, stock-based compensation, accretion
on asset retirement obligation, foreign exchange gains and risk management
gains were $307.0 million. Cash flow from operations, before changes in
non-cash working capital, was $244.2 million ($1.52 per share) in 2005
compared to $23.0 million ($0.15 per share) in 2004. Excluding the negative
impact of fixed-price crude swaps, earnings and cash flow from operations
would have been $259.8 million and $354.6 million, respectively. Robust
commodity prices, together with sustained reliable operations over the course
of the year, resulted in a new annual record for EBITDAX for Western.
Excluding the negative impact of the fixed-price crude swaps, EBITDAX would
have equalled $417.4 million. Western's fixed price hedging program expired at
the end of fiscal 2005 and, therefore, Western will participate to a greater
extent in actual commodity prices than it experienced in 2004 and 2005 should
prices remain at these levels.
The table below provides the reconciliation between net earnings attributable
to common shareholders, cash flow from operations (before changes in non-cash
working capital) and EBITDAX.
- --------------------------------------------------------------------------------------------------------------
Reconciliation:Net Earnings to EBITDAX
December 31 ($ thousands) 2005 2004 2003
- --------------------------------------------------------------------------------------------------------------
(restated)
Net Earnings Attributable to Common Shareholders 149,449 19,452 15,003
Add (Deduct):
Depreciation, Depletion and Amortization 50,738 44,515 27,531
Accretion on Asset Retirement Obligation 562 471 471
Stock-Based Compensation 3,149 967 278
Impairment of Long-lived Assets - 4,733 -
Unrealized Foreign Exchange Gain (17,803) (39,960) (35,280)
Unrealized Risk Management Gain (13,450) - -
Future Income Tax Expense (Recovery) 70,956 (7,104) (4,330)
Interest Expense on Option Premium Liability 1,278 - -
Charge for Convertible Notes - - 2,130
Cash Settlement on Asset Retirement Obligations (52) - -
Cash Settlement on Performance Share Units (596) (30) -
==============================================================================================================
Cash Flow from Operations, before Changes in
Non-Cash Working Capital 244,231 23,044 5,803
Add (Deduct):
Interest (excluding interest on Option Premium Liability) 56,887 61,154 38,429
Realized Foreign Exchange Loss 2,242 1,610 304
Large Corporations Tax 3,000 1,749 3,079
Cash Settlement on Asset Retirement Obligations 52 - -
Cash Settlement on Performance Share Units 596 30 -
==============================================================================================================
EBITDAX 307,008 87,587 47,615
==============================================================================================================
Please refer to page 44 for a discussion of non-GAAP financial measures.
Quarterly Information
The following table summarizes key financial information on a quarterly basis
for the last two fiscal years.
- -----------------------------------------------------------------------------------------------------------------------------
Quarterly Information
($ millions, except per share amounts) Q1 Q2 Q3 Q4 Total
- -----------------------------------------------------------------------------------------------------------------------------
2005
Net Revenue 91.7 148.2 185.7 165.8 591.4
Capital Expenditures, Net 17.5 (12.9) 16.0 26.2 46.8
Long-Term Debt 773.3 755.5 597.5 565.7 565.7
Cash Flow from Operations (1) 10.8 68.0 95.0 70.4 244.2
Cash Flow per Share (2) (5) (6) 0.07 0.42 0.59 0.44 1.52
Earnings (Loss) Attributable to Common Shareholders (3) (4) (1.9) 28.7 79.3 43.3 149.4
Earnings (Loss) per Share - Basic (3) (6) (0.01) 0.18 0.50 0.27 0.93
- - Diluted (3) (6) (0.01) 0.18 0.49 0.27 0.92
=============================================================================================================================
2004
Net Revenue 82.7 93.3 104.1 40.9 321.0
Capital Expenditures, Net 5.5 7.3 13.5 13.8 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) (6) 0.06 0.12 0.21 (0.24) 0.15
Earnings (Loss) Attributable to Common Shareholders (5.7) (9.2) 42.4 (8.0) 19.5
Earnings (Loss) per Share - Basic (6) (0.04) (0.06) 0.27 (0.05) 0.12
- - Diluted (6) (0.04) (0.06) 0.26 (0.05) 0.12
=============================================================================================================================
(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. 2004 amounts restated
to reflect 3:1 share split effected in May 2005.
(3) Includes unrealized foreign exchange gains (losses) on US$450 million
Senior Secured Notes and Option Premium Liability: (Q1 (loss) - $2.7
million, Q2 (loss) - $7.2 million, Q3 - $30.2 million, Q4(loss) - $2.5
million).
(4) Includes unrealized risk management gains (losses) on strategic crude oil
program (Q1 - nil; Q2 - nil; Q3 - $1.7 million; Q4 - $11.8 million).
(5) Please refer to page 44 for a discussion of non-GAAP financial measures.
(6) Per share amounts pre-May 2005 have been restated to reflect 3:1 share
split effective May 30, 2005. Total amounts may not add due to rounding.
L I Q U I D I T Y A N D F I N A N C I A L P O S I T I O N
Western's liquidity and financial position has strengthened significantly
since its inception. In particular, 2005 represented a record year in terms of
production, earnings and cash flow. Cash flow from operations was used to fund
all of our capital expenditures during 2005. Excess cash flow of $197 million
was primarily applied to repay bank credit facilities. As a result, Western's
overall debt to capitalization ratio has improved substantially. At year-end
2005, this ratio was 50 per cent, down from its high of 66 per cent at the end
of 2003. The implementation of a strategic crude oil risk management program
announced in the third quarter of 2005, covering fiscal years 2007 through to
2009, will provide certainty of cash flow during this time period to provide
the funding of a majority of our expansion capital needs in light of upcoming
capital expenditures associated with the first of multiple phases of expansion
of the AOSP. Incremental debt may be required to fund future expansion phases
and other new business development initiatives as they arise.
Debt Financing
In 2005, we maintained our US$450 million of Senior Secured Notes as they are
non-callable with a maturity of May 1, 2012. We were also successful in making
two amendments to our bank credit facilities. First, in March 2005, we amended
the $240 million Revolving Credit Facility (the "$240 million Revolver") to
consolidate its commitments and the $100 million Senior Credit Facility,
whereby all terms and covenants of the $240 million Revolver apply to the new
combined facility. This consolidation feature was specifically structured as
part of the $240 million Revolver at its inception. Second, this new $340
million Revolving Credit Facility ("Revolving Credit Facility") was again
amended in October 2005, with respect to pricing, to reflect Western's
improved financial profile. The amendments reduced the pricing to nil to 225
basis points over the bank prime lending rate, bankers acceptances or US LIBOR
notes, as applicable, which formerly ranged from 100 to 200 basis points. At
December 31, 2005, $41 million (2004 - $216 million) had been drawn on this
facility, with $258 million in unused capacity. Additionally, as at December
31, 2005, letters of credit issued in the amount of $8.9 million (2004 - $8.1
million) were outstanding under the Revolving Credit Facility.
The size of the Revolving Credit Facility is a function of the value of
the reserves attributable to Western. Therefore, based on the reserve
evaluation as at December 31, 2005, Western has full access to the $340
million limit under the Revolving Credit Facility. As Western and its Joint
Venture Participants commit to expansions and the associated reserves are
attributed proratably to each partner, Western may have the ability to
increase its debt capacity beyond the current limits.
Equity Financing
Cash flow from operations was more than sufficient to fund the modest capital
expenditures and working capital commitments during 2005. We will continue to
assess all forms of financing vehicles, both in the debt and equity capital
markets, to ensure Western's capital structure is highly efficient in any
given circumstance.
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
Company'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.
- -------------------------------------------------------------------------------
Equity Capital
At December 31 2005
- -------------------------------------------------------------------------------
Issued and Outstanding:
Common Shares 160,518,041
Outstanding:
Stock Options 3,527,932
- -------------------------------------------------------------------------------
Fully Diluted Number of Shares 164,045,973
- -------------------------------------------------------------------------------
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. Western also incurs capital expenditures of its own accord as a result
of new business development initiatives. Net capital expenditures totalled
$46.8 million in 2005 compared to $40.0 million in 2004. The majority of the
gross increase in capital expenditures relates primarily to increased business
development activity which rose to $13.3 million in 2005 compared to $3.8
million in 2004.
- -------------------------------------------------------------------------------
Capital Expenditures
December 31 ($ millions) 2005 2004
- -------------------------------------------------------------------------------
Project-Related Capital
Profitability Capital 31.2 16.1
Growth Initiatives 9.0 7.1
Long-lead Items 5.6 -
Sustaining Capital 5.8 15.8
===============================================================================
Total Project-Related Capital 51.6 39.0
Business Development and General Corporate Expenditures 13.3 3.8
Capitalized Insurance Costs 4.4 3.6
Insurance Proceeds (22.5) (6.4)
===============================================================================
Net Capital Expenditures 46.8 40.0
===============================================================================
Analysis of Cash Resources
Cash balances totalled $5.6 million at the end of 2005, slightly higher than
the $3.7 million at December 31, 2004. Cash inflows included net operating
cash flow of $244.2 million, insurance proceeds of $22.5 million and equity
proceeds of $2.7 million from the exercise of stock options. Cash outflows
included repayments of long-term debt and obligations under capital leases of
$176.3 million, capital expenditures of $69.4 million, a working capital
decrease of $21.7 million and an increase in deferred charges of $0.2 million.
Record cash flow was generated in 2005 and cash flow in excess of capital
expenditures was applied to reduce outstanding bank facilities. Western's
strategy is to continue to apply excess cash flow to bank facilities to the
extent of outstanding balances. In 2006, our capital expenditure program is
projected to increase to $250 million, representing a combination of current
base Project capital, capital associated with the first AOSP expansion, as
well as capital allocated to identifying new business opportunities where we
can utilize our expertise to deliver further shareholder value. To the extent
possible, we will strive to maintain a minimal cash balance.
Contractual Obligations and Commitments
Western has assumed various contractual obligations and commitments in the
normal course of our operations. Summarized below are significant financial
obligations that are known as of February 16, 2006, and represent future cash
payments that are required under existing contractual agreements. We have
entered into these agreements either directly or as a partner in the Joint
Venture. Feedstocks are included in the table below to comply with continuous
disclosure obligations in Canada; however, Western could sell these products
back to the market and eliminate any negative impact in the event of
operational curtailments.
Contractual Obligations and Commitments (1)
Payments Due by Period
- -------------------------------------------------------------------------------------------------------------------------
Less Than After
($) 1 Year 1 - 3 Years 4 - 5 Years 5 Years Total
- -------------------------------------------------------------------------------------------------------------------------
US$450 Million Senior Secured Notes - - - 524,655 524,655
Revolving Credit Facility (2) - - - 41,000 41,000
Obligations under Capital Lease 1,340 2,680 2,680 43,566 50,266
Option Premium Liability - 95,642 - - 95,642
Feedstocks 106,423 128,758 18,242 64,138 317,561
Pipelines and Utilities 39,715 68,337 69,890 556,036 733,978
Mobile Equipment Lease 3,647 11,941 26,740 - 42,328
- -------------------------------------------------------------------------------------------------------------------------
Total Contractual Obligations 151,125 307,358 117,552 1,229,395 1,805,430
- -------------------------------------------------------------------------------------------------------------------------
(1) In addition, we have an obligation to fund Western's share of the
Project's Pension Fund and have made commitments related to our risk
management program: see Notes 17 and 18, respectively, of the
Consolidated Financial Statements.
(2) The Revolving Credit Facility is a three-year bank facility maturing
initially on October 31, 2008, extendible annually at the lenders'
discretion. Management considers this to be part of our long-term capital
structure.
Insurance Claims
At the beginning of the year, Western had two large claims outstanding: at the
Joint Venture level, a $500 million ($100 million net to Western) loss of
profits claim stemming from the fire at the Mine on January 6, 2003, commonly
referred to as Section III, and a stand-alone Western claim of $200 million
pursuant to our Cost Overrun and Project Delay Policy commonly referred to as
Section IV. In the second quarter of 2005, the Joint Venture was successful in
settlement proceedings with the named insurers on Section III in the amount of
$220 million ($44 million net to Western). To date, Western, has received
$19.4 million of its share of this settlement amount as certain insurers on
Section III are also named insurers on Section IV, which have withheld
insurance proceeds payable to Western. We hope to receive the outstanding
amounts upon conclusion of Section IV arbitration proceedings. Costs and
premiums associated with Section III were capitalized as Western was
pre-commercial operations at that time and, as such, amounts received pursuant
to this settlement were reported as a reduction in capital assets.
Arbitration proceedings under the terms of Section IV of Western's cost
overrun and Project delay insurance policy have been initiated to resolve the
disputes with insurers surrounding the claims for payment pursuant to this
policy. In order to preserve Western's rights regarding this policy, Western
has filed insurance claims for the full limit of the policy, namely $200
million, and we will also be seeking interest and punitive and aggravated
damages. A number of procedural motions have been heard to date and further
motions are expected to occur prior to the commencement of the main
arbitration hearing. Some of the decisions relating to the preliminary motions
have been appealed in the past and one is currently in appeal, resulting in
delays to the commencement of the main arbitration hearing, which is now
expected to occur in 2007. We continue to work toward a satisfactory
conclusion to these proceedings.
Similar to Section III, there are also amounts being withheld by certain
insurers relating to the January 6, 2003 physical property damage claim,
commonly referred to as Section I. To date, Western has received $16.1 million
on this claim, with $19.4 million outstanding. The principal amount of
Western's outstanding insurance claims is $244 million. Other than amounts
collected up to December 31, 2005, no outstanding amounts are recorded in our
financial statements nor are they included in any of our financing strategies.
Flow-Through Shares
In connection with the issuance of flow-through shares in 2001 and 2002,
Western renounced Canadian exploration expenses in the aggregate amount of
$29.2 million and $19.5 million, respectively. Under the mechanics of
renouncing qualifying expenditures pursuant to flow-through shares, individual
shareholders can reduce their income subject to personal income taxes.
Commencing in the latter part of the year, discussions were held between the
AOSP and the CRA regarding the proper characterization of certain expenditures
included in the Canadian exploration expenses in those years. If the CRA
successfully asserts a change in the characterization of these expenditures,
any resulting reduction in the renunciations could impact Western's
obligations under the indemnity provisions in the subscription agreements and
in turn, will impact Western's reported results. The subscription agreements
for such flow-through shares stipulate that Western has indemnified
subscribers for an amount equal to the tax payable and any associated interest
by the subscribers if such renunciations are reduced under the Income Tax Act
(Canada).
Fourth Quarter 2005
Western achieved a third consecutive quarter of record production in the
fourth quarter of 2005, averaging 35,572 barrels per day. Earnings and cash
flow for the fourth quarter were robust when compared to previous quarters.
Record fourth quarter production, however, did not translate into
corresponding record earnings or cash flow due to several factors. First,
similar to the fourth quarter of 2004, the heavy oil differential to WTI
increased in the last quarter of the year to approximately 42 per cent. This
adversely impacted overall sales price realizations as a portion of our sales
stream received a larger discount compared to the prior quarter, where the
average differential to WTI was approximately 32 per cent. Second, the average
WTI price for the fourth quarter was $60.02 per barrel compared to $63.19 per
barrel for the third quarter of 2005. As underlying crude oil prices decline,
our cash flow and profitability decrease accordingly, as our operations are
sensitive to fluctuations in crude oil prices. Third, the continued strength
in the US/Cdn exchange rate adversely impacted financial results. The average
exchange rate for the fourth quarter was US/Cdn$0.8524 compared to
US/Cdn$0.8325 for the third quarter of 2005. To the extent this exchange rate
strengthens, Western receives fewer Canadian dollars on its US dollar sales.
Due to these factors, our sales price realizations totalled $50.65 per barrel
in the fourth quarter compared to $58.79 per barrel for the third quarter. As
far as operating costs are concerned, natural gas prices increased 57 per cent
in the fourth quarter despite the decline in WTI prices. NYMEX closing
settlement prices averaged US$12.91/Mcf for the fourth quarter compared to
US$8.21/Mcf for the third quarter, resulting in relatively higher operating
costs than what would normally be expected in a decreasing WTI environment.
O U T L O O K F O R 2 0 0 6
We caution readers and prospective investors of the Company's securities to
not place undue reliance on forward-looking information as by its nature, it
is based on current expectations regarding future events that involve a number
of assumptions, inherent risks and uncertainties, which could cause actual
results to differ materially from those anticipated by Western. These risks
include, but are not limited to, risks of commodity prices in the marketplace
for crude oil and natural gas; risks associated with the extraction, treatment
and upgrading of mineable oil sands deposits; risks surrounding the level and
timing of capital expenditures required to fulfill the Project's growth
strategy; risks of financing these growth initiatives at commercially
attractive levels; risks of being unable to participate in expansion and
corresponding loss of voting rights in the AOSP; risks relating to the
execution of the Project's optimization strategy; risks involving the
uncertainty of estimates involved in the reserve and resource estimation
process and ore body configuration/geometry, uncertainty in the assessment of
asset retirement obligations, uncertainty in the estimation of future income
taxes, and uncertainty in treatment of capital for royalty purposes; risks
surrounding health, safety and environmental matters; risk of foreign exchange
rate fluctuations; risks and uncertainties associated with securing the
necessary regulatory approvals for expansion initiatives; risks surrounding
major interruptions in operational performance together with any associated
insurance proceedings thereto; and risks associated with identifying,
negotiating and completing our other business development activities, both
those that relate to oil sands activities and those that do not, either
domestically or abroad.
In 2006, we look forward to achieving continued operational improvements
as we continue to seek ways to optimize performance at the AOSP. First quarter
results will be impacted by unplanned production interruptions resulting from
a tear in the main conveyor belt at the Mine that transports bitumen ore from
the primary crushers to the extraction plant. Operations resumed full
production design rates in late March on completion of the belt replacement.
2006 operations will also be impacted by the first full planned turnaround of
the entire Project during the second quarter of this year. Much care and
planning has been directed to this effort to ensure an expeditious return to
full production in mid-2006. Western continues to maintain production guidance
of 145,000 to 150,000 barrels per day (29,000 to 30,000 barrels per day, net
to Western).
Western's capital expenditure program for 2006 is estimated at
approximately $250 million, which is comprised of $71 million for AOSP base
Project improvement capital, $137 million for AOSP growth expenditures and $42
million for Western-led corporate development initiatives. Of this latter
amount, the majority of the budgeted capital relates to oil sands related
initiatives and downstream opportunities.
Western does not have any physical barrels subject to hedging contracts
for fiscal 2006 and is well-placed to take full advantage of the continued
strength in commodity prices during the year should this occur. Financial
results for 2006 are expected to be more highly correlated to underlying
movements in crude oil prices due to the absence of financial risk management
instruments. In addition, we will continue to monitor our 2007 to 2009 risk
management positions.
In 2005, Shell acquired other mineable leases in the Athabasca region and
Western has an option to earn a working interest in these additional leases
upon satisfying certain provisions of the Joint Venture Agreement. Taking into
account these additional leases, together with the right to participate in the
Chevron heavy oil leases along with Western's operated in-situ lease,
translates into a land position, net to Western, which has more than doubled
over the past year. An extensive core-hole drilling program is planned to
evaluate these new leases over the next several years, in addition to
previously held leases, to determine the resource potential available for
future development.
The AOSP is our core asset and primary focus. The expansion plans that
are underway will bring Western's production from the Project to 100,000 to
120,000 barrels per day over the next eight to ten years. In addition,
Western's long-term growth strategy includes maintaining under evaluation four
to six potentially significant project opportunities, each of which is
designed to create long-term shareholder value. These projects include
research and development efforts to add value to our existing assets,
downstream initiatives to reduce our exposure to heavy oil differentials, and
identifying and evaluating opportunities in resource development of oil sands
and other ventures with significant long-life hydrocarbon resource potential.
R I S K A N D S U C C E S S F A C T O R S R E L A T I N G T O
O W E S T E R N
Western faces a number of risks that we need to manage in conducting our
business affairs. The following discussion identifies some of our key areas of
exposure and, where applicable, sets forth measures undertaken to reduce or
mitigate these exposures. A complete discussion of risk factors that may
impact our business is provided in our Annual Information Form.
Financial Risks
The table below details the sensitivities of our cash flow and net earnings
per share to certain relevant operating factors of the Project for 2006.
- ----------------------------------------------------------------------------------------------------------------------------------
SENSITIVITY ANALYSIS
Basic Basic Basic
Cash Flow Cash Flow Earnings Earnings
Variable Sensitivity Case Variation ($ millions) per Share ($) ($ millions) per Share ($)
- ----------------------------------------------------------------------------------------------------------------------------------
Production 30,000 1,000 bbls/day 19.49 0.12 11.90 0.07
Oil Price (US$WTI/bbl) 56.00 US$1.00/bbl 10.25 0.06 6.87 0.04
Non-Gas Operating Costs 21.75 $1.00/bbl 10.97 0.07 7.36 0.05
Natural Gas Price (Cdn$/mcf) (1) 10.02 $0.10/Mcf 0.60 0.00 0.40 0.00
Foreign Exchange (2) 0.86 US/Cdn 0.01 5.93 0.04 0.12 0.04
==================================================================================================================================
(1) Each $1.00 per thousand cubic feet change in gas price results in a
change of $0.44 per barrel in operating costs.
(2) Excludes unrealized foreign exchange gains or losses on long-term
monetary items. The impact of the Canadian dollar strengthening by
US$0.01 would increase net earnings by $2.7 million, based on December
31, 2004 US dollar denominated debt levels.
Our financial results will depend on, amongst other factors, 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 and could have an impact on
future financial results. Any prolonged period of low oil prices could result
in a decision by the Joint Venture Owners to suspend or reduce production. Any
such suspension or reduction of production would result in a corresponding
decrease in our future revenues and earnings and could expose Western to
significant additional expense as a result of certain long-term contracts. In
addition, because natural gas comprises a substantial part of variable
operating costs, any prolonged period of high natural gas prices could
negatively impact our future financial results.
Our debt level and restrictive covenants will have an important impact on
our future operations. Our ability to make scheduled payments or to refinance
our debt obligations will depend upon our financial and operating performance,
which, in turn, will depend on prevailing industry and general economic
conditions beyond our control. There can be no assurance that our operating
performance, cash flow and capital resources will be sufficient to repay our
debt and other obligations in the future.
To mitigate our exposure to these financial risks and provide a stable
financial footing as we enter the first phase of the AOSP expansion, we
recently completed a strategic crude oil risk management program. This program
was the culmination of extensive internal analysis and review and the
recommended approach was approved by our Board of Directors. The overriding
objective of the risk management program was to ensure the ability to fund
significant capital expenditures in the event of a precipitous drop in the
crude oil price. The program itself was a series of put and call options.
Western purchased puts at various levels and financed in part the cost of
these puts by selling call options on lower volumes over the same time period.
The net cost of the program was US$3.74 per put barrel. All options bought and
sold were executed on a deferred basis. Hence, Western made no upfront cash
payment for these options but will do so as each monthly option expires.
Western deferred the options in order to properly match the underlying cash
flow, but, more importantly, the implicit interest rate within the deferred
options pricing was lower than Western's incremental borrowing rate. An
interest expense associated with this program is a result of this deferral
strategy. The program is summarized as follows:
- --------------------------------------------------------------------------------------------------
Risk Management Activities Period (calendar year)
- --------------------------------------------------------------------------------------------------
2007 2008 2009
- --------------------------------------------------------------------------------------------------
Put Options Purchased (bbls/d) 20,000 20,000 20,000
Call Options Sold (bbls/d) 10,000 15,000 15,000
Average Put Strike Price (US$/bbl) 52.50 54.25 50.50
Average Call Strike Price (US$/bbl) 92.50 94.25 90.50
==================================================================================================
($ thousands) 2005 2004
- --------------------------------------------------------------------------------------------------
Risk Management Asset - Beginning of Period - -
Net Premium 84,976 -
Increase in Fair Value 13,450 -
==================================================================================================
Risk Management Asset - End of Period 98,426 -
==================================================================================================
We must finance our share of the Project's operating costs in light of a
volatile commodity price environment and ramp-up challenges. Should
insufficient cash flow be generated from operations, additional financing may
be required to fund capital projects and future expansion projects. If there
is a business interruption, we may need additional financing to fund our
activities until Business Interruption Insurance proceeds are received.
Operational and Business Risks
We are currently a single asset company. This asset is our investment in oil
sands through the AOSP. 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.
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, uncertainties within the
ore body, 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 an owner 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 2005, we placed
US$800 million of Property and Business Interruption Insurance, up from the
US$500 million that was placed last year 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 Owners 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
("HMU") and Dow Chemicals Canada Inc. ("Dow"); and
o Electricity and steam are provided to the Upgrader from the Upgrader
cogeneration facility.
All of these third-party arrangements are critical to the successful
operation of the Project. Disruptions related to these facilities could have
an adverse impact on future financial results.
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 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 may adversely affect the
Project - whether in construction or in operations.
Western has announced its business strategy of investigating, at any one
time, several separate projects that could significantly enhance shareholder
value. Some of these projects may be located outside of Canada. These
potential investments may involve such risks as uncertain political, economic,
legal, regulatory and tax environments.
Environmental Risks
Canada is a signatory to the United Nations Framework Convention on Climate
Change and has ratified the Kyoto Protocol established thereunder to set
legally binding targets to reduce nationwide emissions of carbon dioxide,
methane, nitrous oxide and other so-called greenhouse gases ("GHG"). The
Project will be a significant producer of some GHGs covered by the treaty. The
Government of Canada has put forward a Climate Change Plan for Canada which
suggests further legislation will set GHG 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 is accountable for performance set by the
Joint Venture Owners.
N O N - G A A P F I N A N C I A L M E A S U R E S
Western includes cash flow from operations per share, netback per barrel and
earnings before interest, taxes, depreciation, depletion and amortization,
stock-based compensation, accretion on asset retirement obligation, foreign
exchange gains and risk management gains ("EBITDAX") as investors may use this
information to better analyze our operating performance. We also include
certain per barrel information, such as realized crude oil sales price and
operating costs, to provide per unit numbers that can be compared against
industry benchmarks, such as the Edmonton PAR benchmark. The additional
information should not be considered in isolation or as a substitute for
measures of operating performance prepared in accordance with Canadian
Generally Accepted Accounting Principles ("GAAP"). Non-GAAP financial measures
do not have any standardized meaning prescribed by Canadian GAAP and are
therefore unlikely to be comparable to similar measures presented by other
issuers. Management believes that, in addition to Net Earnings (Loss) per
Share and Net Earnings (Loss) Attributable to Common Shareholders (both
Canadian GAAP measures), Cash Flow from Operations per Share and EBITDAX
provide a better basis for evaluating our operating performance, as they both
exclude fluctuations on the US dollar denominated Senior Secured Notes, risk
management gains (losses) and certain other non-cash items, such as
depreciation, depletion and amortization, and future income tax recoveries. In
addition, EBITDAX provides a useful indicator of our ability to fund our
financing costs and any future capital requirements.
M A N A G E M E N T C O N T R O L S A N D P R O C E D U R E S
As of December 31, 2005, an evaluation was carried out, under the supervision
of and with the participation of management, including the President and Chief
Executive Officer and Chief Financial Officer, of the effectiveness of our
disclosure controls and procedures as defined under Multilateral Instrument
52-109. Based on that evaluation, the President and Chief Executive Officer
and Chief Financial Officer concluded that the design and operation of these
disclosure controls and procedures were effective.
C R I T I C A L A C C O U N T I N G E S T I M A T E S
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.
Property, Plant and Equipment ("PP&E")
Western capitalizes costs specifically related to the acquisition,
exploration, development and construction of the Project and other
initiatives. This includes interest, which is capitalized during the
construction and start-up phase for each project. Depletion on crude oil
properties is provided over the life of proved and probable reserves on a unit
of production basis, commenced when the facilities are substantially complete
and after commercial production has begun. Other PP&E assets are depreciated
on a straight-line basis over their useful lives, except for lease acquisition
costs and certain Mine assets, which are amortized and depreciated over the
life of proved and probable reserves. Reserve estimates can have a significant
impact on earnings, as they are a key component to the calculation of
depletion. A downward revision in the reserve estimate would result in
increased depletion and a reduction of earnings.
PP&E assets are reviewed for impairment whenever events or conditions
indicate that their net carrying amount may not be recoverable from estimated
future cash flows. If an impairment is identified, the assets are written down
to the estimated fair market value. The calculation of these future cash flows
is dependent on a number of estimates, which include reserves, timing of
production, crude oil price, operating cost estimates and foreign exchange
rates. As a result, future cash flows are subject to significant management
judgment.
Asset Retirement Obligation
Western recognizes an asset and a liability for asset retirement obligations
in the period in which they are incurred by estimating the fair value of the
obligation. We determine the fair value by first estimating the expected
timing and amount of cash flow, using third-party costs that will be required
for future dismantlement and site restoration, and then calculating the
present value of these future expenditures using a credit-adjusted risk-free
rate appropriate for Western. Any change in timing or amount of the cash flow
subsequent to initial recognition results in a change in the asset and
liability, which then impacts the depletion on the asset and the accretion
charged on the liability. Estimating the timing and amount of third-party cash
flow to settle this obligation is inherently difficult and is based on
Management's current experience.
Derivative Financial Instruments
Financial instruments that do not qualify as hedges, or have not been
designated as hedges under Accounting Guideline 13, are recorded using the
mark-to-market method of accounting whereby instruments are recorded in the
Consolidated Balance Sheet as either an asset or a liability with changes in
fair value recognized in net earnings. The fair values of such financial
instruments are based on an estimate of the amounts that would have been
received or paid to settle these instruments prior to maturity. Financial
instruments that do qualify as hedges under Accounting Guideline 13, and are
designated as hedges, are not recognized on the Consolidated Balance Sheet and
gains and losses on the hedge are deferred and recognized in revenues in the
period the hedge sale transaction occurs.
Income Tax
Western follows the liability method of accounting for income taxes whereby
future income taxes are recognized based on the differences between the
carrying values of assets and liabilities reported in the Consolidated
Financial Statements and their respective tax basis. Future income tax assets
and liabilities are recognized at the tax rates at which Management expects
the temporary differences to reverse. Management bases this expectation on
future earnings, which require estimates for reserves, timing of production,
crude oil price, operating cost estimates and foreign exchange rates. As a
result, future earnings are subject to significant Management judgment and
changes.
Arrangements Containing a Lease
Through its 20 per cent ownership interest in AOSP, Western is party to a
number of long-term third-party arrangements to provide for pipeline
transportation of bitumen and upgraded products, and to provide electrical and
thermal energy. With the issuance of the Emerging Issues Committee Abstract
150 (") the Corporation is required to determine whether any arrangements
agreed to, committed to or modified after January 1, 2005 contain a lease that
is within the scope of CICA Section 3065 "Leases". To date, none of these
long-term third-party contracts were agreed to, committed to or modified after
January 1, 2005 and therefore, the Corporation is not required to consider
whether they contain a lease that is within the scope of CICA Section 3065.
However, the AOSP or Western may request modification of these agreements in
the future to meet certain requirements related to the AOSP growth plans. Any
modifications may result in certain of these long-term third-party
arrangements being treated as capital leases, thereby increasing both
Western's assets and liabilities on our Consolidated Balance Sheet.