EXHIBIT 99.1
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Q2
WESTERN OIL SANDS 2006 INTERIM REPORT
FOR THE SIX-MONTH PERIOD
ENDED JUNE 30, 2006
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WESTERN OIL SANDS
INTERIM REPORT FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 2006
MESSAGE TO SHAREHOLDERS
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Western Oil Sands Inc. ("Western") announced its operating and financial
results for the second quarter of 2006. Western generated net revenue of $95.6
million, an EBITDAX loss of $8.2 million, negative cash flow from operations of
$20.9 million ($0.13 per share) and a net loss of $22.8 million ($0.14 per
share). By comparison, in the second quarter of 2005, Western recorded net
revenue of $148.2 million, EBITDAX of $84.1 million, cash flow from operations
of $68.0 million ($0.42 per share) and net earnings of $28.7 million ($0.18 per
share).
Excluding the impact of risk management and foreign exchange losses each
net of tax, the net loss for the second quarter of 2006 would have equated to
$13.1 million compared to net earnings of $41.6 million for the prior year
period. Relative to the second quarter of 2005, financial results during the
second quarter of 2006 were significantly impacted by the loss of production
and the one-time expenses associated with the first major planned turnaround at
the Muskeg River Mine and the Scotford Upgrader, partially offset by a 33 per
cent increase in West Texas Intermediate ("WTI") prices, no volumes subject to
hedge contracts and a 36 per cent narrowing of the heavy crude oil price
differentials from 41 per cent to 26 per cent of WTI prices. In the second
quarter of 2006, our net loss included a $27.3 million ($24.0 million net of
tax) unrealized foreign exchange gain and an unrealized risk management
(mark-to-market) loss
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 1
of $44.5 million ($33.7 million net of tax) compared to an unrealized foreign
exchange loss of $7.2 million ($6.0 million net of tax) with no unrealized
mark-to-market adjustments for the second quarter of 2005.
HIGHLIGHTS
o During the second quarter of 2006, the Athabasca Oil Sands Project
("AOSP") undertook its first major turnaround, commencing in May with full
production resuming in mid-July. Following the initial cleaning and
inspection of the equipment, it was determined that additional maintenance
and repair work at the Scotford Upgrader was required in order to remove
large amounts of coke from the reactor vessels at the Upgrader and
complete other work to enhance long-term performance. Consequently, the
turnaround schedule was extended beyond the previously announced
eight-week duration. As a result of this full turnaround, production
during the quarter averaged 15,540 barrels per day net to Western compared
to 32,757 barrels per day net to Western in the second quarter of 2005
(non-turnaround quarter). Significantly lower production during the second
quarter of 2006, combined with the associated expenses incurred as a
result of the turnaround, resulted in operating costs of $62.50 per
processed barrel. When the AOSP operated at full production during the
month of April, operating costs per processed barrel, excluding turnaround
costs were $21.75. As a result of the turnaround, quarter-over-quarter
comparisons in terms of production and operating costs per barrel are not
meaningful.
o As announced on May 30, 2006, Western's wholly-owned subsidiary,
WesternZagros Limited, entered into an Exploration and Production Sharing
Agreement (EPSA) with the Kurdistan Regional Government, Sulaymaniyah
Administration to explore for conventional oil and gas in the Federal
Region of Kurdistan in northern Iraq. This opportunity is particularly
attractive to Western because it requires a modest capital investment over
the initial period of the EPSA, while offering the potential of large
long-life reserves with a low cost structure. This agreement will become
effective when it is passed into law which is expected to occur in the
coming months. Under the terms of the EPSA, WesternZagros will undertake
an exploration program over a 3,700 square kilometre block that will
involve geophysical and geological studies followed by an exploratory
drilling program. The minimum contractual commitment under the terms of
the EPSA is US$45 million over the first four years. Should exploration
prove successful, additional exploration and development expenditures are
anticipated.
o Subsequent to the end of the second quarter, in early July, Western
announced that over the past year, the AOSP initiated a detailed review of
the proposed Expansion 1. Although not yet complete, there are very
significant upward pressures on capital costs of the project. One of the
key factors facing the AOSP's Expansion 1 project, and many other large
construction projects around the world, is the intense demand for
construction labour, materials and supplies which have resulted in
significant increases in capital costs. This demand is further intensified
in Alberta by the proposed development of multiple oil sands projects. The
AOSP is currently involved in a number of internal and external project
reviews to capture best practice in all aspects of the design, schedule
and construction strategies. These reviews will continue, including how to
address the twin challenges of cost and supply. A final investment
decision by the Joint Venture Owners is anticipated in the fourth quarter
of 2006. The AOSP Expansion 1 includes pre-building infrastructure such as
utility plants, camps, site pipelines etc. to support multiple upstream
expansion projects which the Project believes will create efficiencies and
economies of scale over the long term. It is also anticipated that capital
expenditures for Expansion 1 will improve the reliability and availability
of base operations as the expanded operations will create redundancy in
critical vessels thereby limiting the downtime associated with production
interruptions.
o Western's undeveloped land position in the Athabasca region has increased
significantly to approximately 60,000 acres net to Western in the past 18
months as a result of numerous new lease acquisitions in which Western
owns or will have the right to participate. Western has completed a
preliminary analysis on these undeveloped lands including both mineable
and in-situ. Based on this analysis, it is Western's view that there are
sufficient bitumen resources in place to support multiple expansions
beyond the planned expansions at the AOSP. Production from the base
operation and the first three expansions is anticipated to exceed 100,000
barrels per day net to Western. With the resource potential associated
with these newly acquired leases, it is Western's view that an incremental
50,000 to 100,000 barrels per day of production could be added, bringing
Western's share of production into the range of 150,000 to 200,000 barrels
per day.
2 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion of financial condition and results of operations was
prepared as of July 26, 2006 and should be read in conjunction with the Interim
Unaudited Consolidated Financial Statements for the periods ended June 30, 2006
and 2005 and the Audited Consolidated Financial Statements at December 31, 2005
included in the Annual Report. 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 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; size and scope of expansions; 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. Risks associated with our international initiatives
include, but are not limited to, political and economic conditions in the
countries in which we intend to operate, risks associated with acts of
insurgency or terrorism, changes in market conditions, political risks,
including changes in law or government policy, the risks associated with
negotiating with foreign governments and risks generally associated with
international activity.
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.
Highlights
Three Months Ended June 30 Six Months Ended June 30
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2006 2005 2006 2005
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OPERATING DATA (bbls/d)
Bitumen Production 15,540 32,757 20,714 29,647
Synthetic Crude Sales 22,614 44,503 29,861 39,523
Operating Expense per Processed Barrel ($/bbl) 62.50 19.38 40.24 22.03
FINANCIAL DATA ($ thousands, except as indicated)
Net Revenue 95,633 148,167 234,881 239,910
Realized Crude Oil Sales Price ($/bbl) (1) (2) 66.48 48.93 59.56 44.52
EBITDAX (1) (3) (8,199) 84,063 53,901 111,479
Turnaround Costs 34,899 - 34,899 -
Cash Flow from Operations (4) (20,833) 68,019 26,887 78,789
Cash Flow per Share - Basic ($/Share) (1) (5) (0.13) 0.42 0.17 0.49
Net Earnings (Loss) (6) (22,787) 28,650 (44,362) 26,706
Net Earnings (Loss) Per Share - Basic ($/Share) (0.14) 0.18 (0.28) 0.17
Net Capital Expenditures (7) 55,828 (12,900) 91,159 4,654
Long-term Financial Liabilities (8) 661,499 810,214 661,499 810,214
Weighted Average Shares Outstanding - Basic (Shares) 161,070,149 160,120,507 160,848,345 160,039,942
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(1) Please refer to page 11 for a discussion of Non-GAAPfinancial 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 hedging
activities, divided by the corresponding volume. Please refer to page 4 for
calculation.
(3) Earnings before interest, taxes, depreciation, depletion, amortization,
stock based compensation, accretion on asset retirement obligation, risk
management and foreign exchange as calculated on page 9.
(4) Cash flow from operations is expressed before changes in non-cash working
capital.
(5) Cash flow per share is calculated as cash flow from operations divided by
weighted average common shares outstanding, basic.
(6) Western has not paid dividends in any of the above referenced periods.
(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.
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 3
OPERATING RESULTS
PRODUCTION
During the second quarter of 2006, production from the Mine was impacted by the
first full Project turnaround since operations commenced in 2003. The
turnaround began in early May and continued over the course of the quarter with
full production resuming in mid-July. Full production rates of 36,587 barrels
per day net to Western were achieved during the month of April whereas the
impact of the turnaround reduced production for the quarter to 15,540 barrels
per day net to Western. Quarter-over-quarter production comparisons are not
meaningful as a result of the impact of the turnaround. This first full plant
turnaround extended beyond the original schedule as additional maintenance work
was required to remove increased levels of coke in certain reactor vessels at
the Upgrader. It is anticipated that major turnarounds will occur every three
years.
REVENUE
Net Revenue Three Months Ended June 30 Six Months Ended June 30
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($ thousands, except as indicated) 2006 2005 2006 2005
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Revenue
Oil Sands (1) 137,095 198,929 322,450 319,238
Marketing and Transportation 28,632 45,289 51,037 91,112
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Total Revenue 165,727 244,218 373,487 410,350
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Purchased Feedstocks and Transportation
Oil Sands 41,904 51,098 88,109 78,663
Marketing and Transportation 28,190 44,953 50,497 91,777
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Total Purchased Feedstocks and Transportation 70,094 96,051 138,606 170,440
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Net Revenue
Oil Sands (1) 95,191 147,831 234,341 240,575
Marketing and Transportation 442 336 540 (665)
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Total Net Revenue 95,633 148,167 234,881 239,910
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Synthetic Crude Sales (bbls/d) 22,614 44,503 29,861 39,523
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Realized Crude Oil Sales Price ($/bbl) (2) 66.48 48.93 59.56 44.52
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(1) Oil Sands Revenue and Net Revenue are presented net of Western's hedging
activities.
(2) Realized Crude Oil Sales Price ($/bbl) is calculated as Oil Sands Revenue
less any transportation costs divided by synthetic crude sales volume. For
the three and six months ended June 30, 2006, $0.3 million (Q2-2005 - nil)
and $0.5 million (Q2-2005 (6 mos) - nil), respectively, has been incurred
for transportation costs related to Oil Sands.
4 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
Western recorded crude oil sales revenue of $165.7 million in the second
quarter of 2006, including $137.1 million from proprietary production compared
to $244.2 million in the second quarter of 2005, $198.9 million of which was
from proprietary production. This decrease is the result of the turnaround
which occurred during the second quarter, partially offset by higher sales
price realizations during the quarter. During the full turnaround, production
was interrupted for 45 days which significantly impacted second quarter
operating and financial results. Western received a realized sales price of
$66.48 per barrel on this limited production. This 36 per cent increase in
realized prices over the prior year period is the result of a 33 per cent
increase in West Texas Intermediate ("WTI") prices over the comparable period
in 2005, together with no physical barrels subject to out-of-the-money fixed
price swap contracts and a narrowing of the heavy oil differential of over
$3.00 per barrel. The heavy oil differential equated to 26 per cent of WTI
(US$18.66 per barrel) in the second quarter of 2006 compared to 41 per cent of
WTI (US$21.90 per barrel) for the prior year period.
Oil sands sales volumes, including bitumen and purchased feedstocks,
averaged 22,614 barrels per day in the second quarter of 2006 compared to
44,503 barrels per day in the second quarter of 2005. Reduced sales volumes are
a function of the turnaround as there were limited operations during the second
quarter.
Sales price realizations for the second quarter of 2006 related
predominantly to sales activities in April due to little or no activity in May
and June as a result of the turnaround. Sales price realizations were $66.48
per barrel in the second quarter, an increase from $48.93 per barrel recorded
in the second quarter of 2005 and $55.31 per barrel recorded in the first
quarter of 2006. Higher sales price realizations largely resulted from
increases in WTI which averaged US$70.16 for April compared to US$53.17 for the
second quarter of 2005 and US$63.48 for the first quarter of 2006. Contributing
to the improved realizations was the decrease in the heavy oil differential in
April which continued to the end of the quarter. The heavy oil differential
narrowed over US$8.00 in April 2006 compared to the average of the first
quarter of 2006. This narrowing was a function of seasonal asphalt requirements
as refiners build heavy oil inventories to meet demand and pipeline reversals
which opened new markets for Canadian heavy crude oil. Included in Western's
sales mix are heavy crude oil products which attract a lower sales price,
thereby affecting our overall sales price realizations. With heavy oil products
in the overall sales mix, absolute commodity prices and heavy oil market
differentials affect average synthetic crude oil price realizations. Western's
fixed price swap program ceased at the end of 2005 and this also contributed to
dramatically higher sales price realizations compared to the second quarter of
2006.
Western generated net revenue of $95.6 million in the second quarter of
2006, after considering the impact of purchased feedstocks and transportation
costs downstream of Edmonton. By comparison, Western recorded net revenue of
$148.2 million in the second quarter of 2005. This decrease stems from the
turnaround conducted throughout most of the second quarter of 2006. Feedstocks
are crude products introduced at the Upgrader. Some feedstocks are introduced
into the hydrocracking/hydrotreating process and others are used to create
various blends 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.
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 5
OPERATING COSTS
Operating costs in the second quarter of 2006 were impacted significantly by
the full turnaround. The majority of operating costs are fixed in nature,
therefore, during a complete turnaround, fixed costs such as labour and
electricity, are incurred regardless of production volumes. As the production
base was significantly lower in the second quarter of 2006 compared to the
prior year period, unit operating costs are not comparable period to period.
Western's operating costs are also significantly influenced by our policy to
expense all turnaround costs in the period they are incurred. Western's share
of the turnaround expense for the second quarter was $34.9 million and we
anticipate minor turnaround costs in the third quarter associated with the
completion of this process. Total turnaround costs are higher than previously
estimated due to the additional work involved with removing higher amounts of
coke inside certain reactor vessels at the Upgrader. Consequently, operating
costs for the second quarter of 2006 were $62.50 per processed barrel.
Operating costs of $21.75 per processed barrel were achieved during April
in which normal operating conditions existed. Despite the pressures on
operating costs associated with robust commodity prices and increased demand
for goods and services, we anticipate a return to operating costs on a per unit
basis experienced in April once normal operations resume.
Three Months Ended June 30 Six Months Ended June 30
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($ thousands, except as indicated) 2006 2005 2006 2005
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Operating Expenses For Bitumen Sold
Operating Expense - Income Statement 54,588 55,347 118,518 114,490
Operating Expense - Inventoried 5,114 3,286 3,483 4,074
Turnaround Costs - Income Statement 34,899 - 34,899 -
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Total Operating Expenses For Bitumen Sold 94,601 58,633 156,900 118,564
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Sales (barrels per day)
Total Synthetic Crude Sales 22,614 44,503 29,861 39,523
Purchased Upgrader Blend Stocks (5,980) (11,247) (8,321) (9,788)
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Synthetic Crude Sales Excluding Blend Stocks 16,634 33,256 21,540 29,735
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Operating Expenses Per Processed Barrel ($/bbl) (1) 62.50 19.38 40.24 22.03
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Operating Expenses Per Processed Barrel
Excluding Turnaround Costs ($/bbl) (2) 39.44 19.38 31.29 22.03
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(1) Operating Expenses Per Processed Barrel ($/bbl) is calculated as Total
Operating Expenses For Bitumen Sold divided by Synthetic Crude Sales
Excluding Blend Stocks.
(2) Operating expenses per processed barrel excluding the effects of the
turnaround taken by total operating expenses for bitumen sold, less
turnaround expenses divided by synthetic crude sales excluding blend
stocks.
The above table calculates operating expenses per processed barrel on the basis
of the operating costs that are associated with the synthetic crude sales,
excluding purchased blend stocks, for the relevant period. The 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.
6 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
ROYALTIES
Royalties of $0.7 million in the second quarter of 2006 were lower than the
comparable period in 2005 as a result of lower production volumes due to the
first full plant turnaround during the second quarter of 2006. Compared to the
first quarter of 2006, royalties increased slightly as a result of higher
deemed bitumen prices partially offset by reduced production volumes associated
with the turnaround.
CORPORATE RESULTS
RESEARCH AND BUSINESS DEVELOPMENT EXPENSE
Western incurred $7.7 million in research and development expenses in the
second quarter of 2006 compared to $3.4 million in the second quarter of 2005.
Of the $7.7 million incurred during the second quarter, $4.1 million relates
specifically to AOSP-related research and development projects. The increase is
a result of additional efforts in research and business development as Western
continues to pursue opportunities which may enhance the value of the AOSP in
addition to Western-led initiatives.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expenses ("G&A") were $3.2 million for the second
quarter of 2006 compared to $2.5million for the second quarter of 2005 due to
an increased number of employees within Western, together with higher
professional costs associated with increased levels of business development
activities.
INSURANCE EXPENSE
Insurance expenses were $2.7 million for the second quarter of 2006 compared to
$1.9 million in the second quarter of 2005. This increase is due to additional
premiums associated with increased levels of coverage, partially offset by the
strengthening of the Canadian dollar over the comparable periods as the
premiums are paid in US dollars but reported for financial statement purposes
in Canadian dollars.
INTEREST EXPENSE
Interest expense totaled $12.5 million in the second quarter of 2006 compared
to $15.7 million in the second quarter of 2005. Interest expense in the second
quarter of 2006 is comprised of $10.9 million related to interest charges on
debt obligations (Q2-2005 - $15.0 million), $0.7 million (Q2-2005 - $0.6
million) on capital lease obligations and $0.9 million (Q2-2005 - nil) on the
option premium liability. The option premium liability relates to Western's
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 which is reported as interest expense.
The 20 per cent decrease in total interest expense compared to the second
quarter of 2005 is largely the result of the Canadian dollar strengthening
against the US dollar during this period compared to the prior year period,
thereby reducing interest charges on our US denominated Notes which are
reported in Canadian dollars, and the significant reduction in the Revolving
Credit Facility over the comparable period. Interest expense decreased slightly
in the second quarter of 2006 compared to the first quarter of 2006 due to a
further strengthening of the Canadian dollar versus the US dollar, largely
offset by the larger amounts of debt drawn on the Revolving Credit Facility to
fund turnaround efforts.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization ("DD&A") totaled $6.8 million in the
second quarter of 2006 compared to $13.0 million in the second quarter of 2005.
This decrease is the result of lower bitumen production volumes associated with
the full planned plant turnaround since DD&A is based on a unit of production.
FOREIGN EXCHANGE
During the second quarter of 2006, Western reported a foreign exchange gain of
$25.8 million compared to a loss of $7.0 million in the second quarter of 2005.
As reference points, the noon-day closing foreign exchange rate on June 30,
2006 was $0.8969 US/Cdn compared to $0.8568 US/Cdn on March 31, 2006 and
$0.8159 US/Cdn on June 30, 2005. The average rate for the second quarter of
2006 was $0.8912 US/Cdn compared to $0.8039 US/Cdn for the prior year period
and $0.8659 US/Cdn for the first quarter of 2006.
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 7
RISK MANAGEMENT ACTIVITIES
Western's initial fixed price hedging program expired on December 31, 2005.
Western has no risk management financial instruments associated with fiscal
2006 and, as such, crude oil price realizations in the second quarter of 2006
were not impacted by risk management activities. Realizations in the second
quarter of 2005 were negatively impacted by $5.14 per barrel due to risk
management activities.
Three Months Ended June 30 Six Months Ended June 30
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(Unaudited) 2006 2005 2006 2005
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Decrease in Revenue ($ thousands) - 20,803 - 57,597
Decrease in Revenue ($/bbl) - 5.14 - 8.05
============================================================================================================
In the third quarter of 2005, Western implemented strategic crude oil
hedges in order to provide greater cash flow certainty during those years where
significant AOSP expansion capital expenditures are expected. Western employed
a collar strategy whereby a series of put and call options were purchased and
sold with a number of major financial institutions. The program established a
weighted average floor price of US$52.42 on 20,000 barrels per day and a
ceiling price of US$92.41 on an average 13,333 barrels per day for the period
January 2007 through to December2009.
Western is not utilizing hedge accounting treatment under Canadian GAAP
for this program and, as a result, certain mark-to-market adjustments will
likely result in increased volatility in our reported net income. These
adjustments are created from the changes in the fair market value of the
financial instruments employed over the time period in question. For the period
ended June 30, 2006, Western's risk management assets decreased significantly
in value from the amount recorded as at March 31, 2006 resulting in a
mark-to-market loss of $44.5 million ($33.7 million net of tax) primarily due
to the significant strengthening in WTI prices during the quarter. This loss
does not impact stated cash flow from operations. In fact, the amount recorded
as a risk management asset at the end of the first quarter of 2006 has now
reverted to a risk management liability given the continued strength in
underlying commodity prices. While the mark-to-market entry for accounting
purposes has been negative, the price of WTI has remained within the collar
established under the strategy. The current forward curve of WTI during the
duration of Western's risk management program would also be within this collar.
Consequently, should these forward prices of crude oil materialize, the goal of
Western's risk management program would be achieved - namely, relatively minor
premiums incurred to enhance cash flow certainty during construction of the
AOSP Expansion 1. Western continues to monitor the portfolio of financial
instruments to determine if modifications are necessary.
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
(Unaudited) ($ thousands) 2006 2005 2006 2005
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Risk Management Asset - Beginning of Period 30,702 - 98,426 -
Net Premium - - - -
Decrease in Fair Value (44,478) - (112,202) -
- ------------------------------------------------------------------------------------------------------------
Risk Management Liability - End of Period (13,776) - (13,776) -
Less: Current Portion (1) (1,644) - (1,644) -
- ------------------------------------------------------------------------------------------------------------
Risk Management Liability - Long-term Portion (12,132) - (12,132) -
============================================================================================================
(1)Current portion represents the fair value of the risk management program
that expires within the next 12 months.
INCOME TAXES
For the second quarter of 2006, Western's income tax recovery was $25.5 million
compared to an income tax expense of $18.5 million for the prior year period.
This recovery is largely due to the net loss incurred during the quarter as a
result of the turnaround, together with risk management losses. The recovery is
also a function of reduced federal and provincial income tax rates as announced
by each level of government during the second quarter of 2006.
NET EARNINGS (LOSS)
During the second quarter of 2006, Western reported a net loss of $22.8 million
($0.14 per share) compared to net earnings of $28.7 million ($0.18 per share)
in the second quarter of 2005. The net loss in the second quarter of 2006
includes the impact of $44.5 million ($33.7 million net of tax) in unrealized
risk management losses, in addition to $27.3 million ($24.0 million net of tax)
in unrealized foreign exchange gains on our US dollar denominated debt and
option premium liability. Excluding the impact of risk management and foreign
exchange losses each net of tax, the net loss for the second quarter of 2006
would have equated to $13.1 million compared to net earnings of $41.6 million
for the prior year period.
8 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
The following table provides the reconciliation between Net Earnings
(Loss), Cash Flow from Operations (before changes in non-cash working capital)
and EBITDAX:
RECONCILIATION: NET EARNINGS (LOSS) TO EBITDAX
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
($ thousands) 2006 2005 2006 2005
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NET EARNINGS (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS (22,787) 28,650 (44,362) 26,706
Add (Deduct):
Depreciation, Depletion and Amortization 6,820 13,037 17,366 23,535
Accretion on Asset Retirement Obligation 156 143 311 284
Stock-based Compensation 1,893 1,082 3,684 1,723
Unrealized Foreign Exchange Loss (Gain) (27,310) 7,200 (26,674) 9,900
Unrealized Risk Management Loss 44,478 - 112,202 -
Future Income Tax Expense (Recovery) (24,948) 17,928 (35,331) 17,280
Interest Expense on Option Premium Liability 934 - 1,886 -
Cash Settlement on Performance Share Units (28) - (2,104) (596)
Cash Settlement on Asset Retirement Obligation (91) (21) (91) (43)
- ------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS, BEFORE CHANGES IN
NON-CASH WORKING CAPITAL (20,883) 68,019 26,887 78,789
Add:
Interest (excluding interest on Option Premium Liability) 11,598 15,660 23,675 30,746
Realized Foreign Exchange Loss (Gain) 1,551 (231) 1,285 3
Large Corporations Tax (584) 594 (141) 1,302
Cash Settlement on Performance Share Units 28 - 2,104 596
Cash Settlement on Asset Retirement Obligation 91 21 91 43
EBITDAX (8,199) 84,063 53,901 111,479
============================================================================================================
An EBITDAX (Earnings before Interest, Taxes, Depreciation, Depletion,
Amortization, Stock-based Compensation, Accretion on Asset Retirement
Obligation, Foreign Exchange and Risk Management) loss of $8.2 million was
recorded for the second quarter of 2006 compared to a positive $84.1 million
for the comparable prior year period. This substantial decrease is largely due
to the impact of the full plant turnaround during the second quarter of 2006,
partially offset by improved sales price realizations on reduced production
volumes. Second quarter 2006 EBITDAX decreased $70.3 million over the first
quarter of 2006 also due to the full plant turnaround during the second
quarter.
Cash flow from operations before changes in non-cash working capital
("cash flow from operations") was a net outflow of $20.9 million compared to a
net inflow of $68 million in the second quarter of 2005. Compared to the prior
period, second quarter results were impacted by the full plant turnaround.
FINANCIAL POSITION
BANK DEBT
During the second quarter of 2006, Western increased its balance drawn under
the Revolving Credit Facility to $31million to fund the turnaround expenses
incurred during the quarter. Western anticipates this balance will be reduced
or repaid once production resumes, giving Western access to the full $340
million of the Revolving Credit Facility. The size of the facility is a
function of Western's share of the before tax present value proved reserves
associated with the Project. To the extent that Western is able to book
additional reserves associated with the first expansion of the AOSP, Western
would be permitted to increase its Revolving Credit Facility, subject to
amending the size of this facility with the existing bank syndicate.
CAPITAL EXPENDITURES
Western's capital expenditures totaled $55.8 million in the second quarter of
2006 compared to $9.3 million for the comparable period in 2005. Capital
expenditures in the second quarter of 2006 included $13.3 million for base
operations, $7.1 million for sustaining capital, $30.0 million for expansion
related capital, $4.0 million for new business development and $1.4 for other
corporate purposes.
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 9
ANALYSIS OF CASH RESOURCES
Cash balances totaled $6.0 million at June 30, 2006 compared to $15.7 million
at March 31, 2006. Cash inflows included: $31.0 million increase in bank lines
and a $36.3 million increase in non-cash working capital items. Cash outflows
included: $20.9 million negative cash flow from operations, $55.8 million of
capital expenditures and $0.3million in repayment of obligations under capital
lease and deferred charges.
The decrease in non-cash working capital during the second quarter of 2006
was the result of a $22.0 million decrease in accounts receivable, a $6.2
million decrease in inventory, a $6.0 million increase in accounts payable and
a $2.1 million decrease in prepaid expenses. The increase in accounts payable
is a function of costs associated with the turnaround during the second quarter
offset by lower accrued interest on Western's long-term notes at June 30, 2006,
as only two months of accrued interest are included compared to five months
accrued at March 31, 2006. The decrease in accounts receivable is the result of
lower sales volumes associated with the full plant turnaround during the second
quarter. Inventory is lower as a result of a greater proportion of lower priced
volumes than high priced volumes compared to the end of the first quarter of
2006.
INSURANCE CLAIMS
There were no new developments during the second quarter of 2006 with respect
to Western's ongoing arbitration proceedings concerning the Cost Overrun and
Project Delay insurance policy, known as Section IV. Western anticipates that
formal arbitration hearings will commence in 2007.
FLOW-THROUGH SHARES
There were no new developments during the second quarter of 2006 with respect
to Western's issuance of flow-through shares in 2001 and 2002 and the possible
re-characterization of qualifying expenditures by Canada Revenue Agency.
Western will provide further updates once information is made available.
KURDISTAN UPDATE
As announced on May 30, 2006, Western's wholly-owned subsidiary, WesternZagros
Limited, entered into an Exploration and Production Sharing Agreement (EPSA)
with the Kurdistan Regional Government in northern Iraq. This opportunity may
potentially give Western access to an additional world-class asset with large,
long-life, reserves with a significantly lower cost structure than our current
oil sands asset. Our initial exploration capital commitment of US$45 million is
to be expended prior to the expiry of four years from the effective date of the
contract. Further expenditures will depend on exploration success and the
timing of executing a development program. Our exploration area covered by the
EPSA spans approximately 3,700 square kilometres or 914,000 acres.
Western's team of professionals, dedicated specifically to this
initiative, has taken preliminary steps to fulfill the obligations under the
EPSA. Measured progress has been made to date on many levels, including
seismic, engineering and logistics. Western anticipates that progress will
continue as planned, culminating in an initial three well drill program over
three different potential structures within our contract area. Western has
chosen to account for its operations in Kurdistan using the full-cost
accounting methodology.
On the personnel front, Western is pleased to announce the appointment of
Mr. Jack Blackshear to the key position of Resident Manager, Kurdistan. Mr.
Blackshear brings with him significant international drilling and operational
experience through his distinguished career with some of the world's premier
integrated energy companies.
OUTLOOK
The AOSP anticipates production levels returning to the historical norms
achieved prior to the full plant turnaround and maintaining these levels
through the remainder of the year. Despite the extended turnaround schedule, by
many measures the process was a success and the education gathered will be
invaluable as future turnarounds are conducted. During the turnaround, the
Project implemented certain production optimization initiatives which should
enhance the reliability and availability of the Project. As announced on June
12, 2006, Western revised its production guidance to 26,000 to 27,000 barrels
per day for 2006 and we continue to hold this estimate.
The Joint Venture Owners are proceeding steadily towards a final
investment decision on the first 100,000 barrel per day AOSP expansion which is
expected to occur in the fourth quarter of 2006. Deliberate and careful
analyses of the costs associated with this expansion in the midst of heated
construction market are a primary focus with cost
10 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
and schedule control a top priority. As announced on July 5, 2006, subsequent
to the end of the quarter, capital costs associated with the first expansion
are under significant pressure. Preliminary revised estimates indicate a
potential increase in capital costs of a fully integrated expansion of
approximately 50 per cent higher than those anticipated last year. The AOSP
Expansion 1 includes pre-building infrastructure such as utility plants, camps,
site pipelines etc. to support multiple expansion projects which the Project
believes will create efficiencies and economies of scale over the long term.
Several construction gating procedures must still be completed prior to a final
determination of capital costs. Western will have 90 days from the receipt of
the expansion notice to make the final investment decision.
Western expects to continue participating in future mine expansions and
development together with the other Joint Venture Owners. Beyond the AOSP
Expansion 1, Western is also independently evaluating alternative downstream
solutions with the goal of improving product yields and sales price
realizations. To meet these stated goals, Western is committed to a long-term
strategy which involves commercially attractive integrated downstream solutions
for upgrading bitumen into light synthetic crude oil products for future mining
and in-situ production volumes.
Western's undeveloped land position in the Athabasca region has increased
significantly in the past 18 months to approximately 60,000 acres net to
Western as a result of numerous new lease acquisitions in which Western owns or
will have the right to participate. Western has completed a preliminary
analysis on these undeveloped lands including both mineable and in-situ. Based
on this analysis, it is Western's view that there are sufficient bitumen
resources in place to support multiple expansions beyond the planned expansions
at the AOSP. Production from the base operation and the first three expansions
is anticipated to exceed 100,000 barrels per day net to Western. With the
resource potential associated with these newly acquired mineable leases, it is
Western's view that an incremental 50,000 to 100,000 barrels per day of
production could be added, bringing Western's share of production into the
range of 150,000 to 200,000 barrels per day.
Western is also currently reviewing the resource potential attributable to
leases outside of the current operation and the AOSP Expansion 1. As part of
Western's annual filing process, it is anticipated that we will disclose the
contingent or potentially recoverable resources, both on a volumetric and
economic basis, on these leases - namely, Lease 13 (remainder after current
Mine and Expansion 1), 88, 89, 90, 9 and 17. Western is also taking early steps
to quantify the resource potential attributable to leases recently acquired by
our Joint Venture Participants, in addition to Lease353 which was acquired by
Western. The resource potential will be disclosed when the analysis is provided
by the experts engaged in these assessments.
BUSINESS AND FINANCIAL RISKS
Western is subject to a number of business and financial risks that are typical
given the nature of Western's operations. These risks are described in
Western's previous public disclosures, including the 2005 Annual Report and the
Annual Information Form, which are available on the Company's website.
NON-GAAPFINANCIAL MEASURES
Western includes cash flow from operations per share, cash flow from operations
excluding hedging activities, earnings before interest, taxes, depreciation,
depletion and amortization, stock-based compensation, accretion on asset
retirement obligation, foreign exchange gains and gains and losses on risk
management activities ("EBITDAX"), EBITDAX excluding hedging activities and net
earnings excluding hedging activities as investors may use this information to
better analyze our operating performance. We also include certain per barrel
information, such as realized crude oil sales price, to provide per unit
numbers that can be compared against industry benchmarks, such as the Edmonton
PAR benchmark. The additional information should not be considered in isolation
or as a substitute for measures of operating performance prepared in accordance
with Canadian Generally Accepted Accounting Principles ("GAAP"). Non-GAAP
financial measures do not have any standardized meaning prescribed by Canadian
GAAP and are therefore unlikely to be comparable to similar measures presented
by other issuers. Management believes that, in addition to Net Earnings (Loss)
per Share and Net Earnings (Loss) Attributable to Common Shareholders (both
Canadian GAAP measures), cash flow from operations per share and EBITDAX
provide a better basis for evaluating our operating performance, as they both
exclude fluctuations on the US dollar denominated Senior Secured Notes and
certain other non-cash items, such as depreciation, depletion and amortization,
and future income tax recoveries. In addition, EBITDAX provides a useful
indicator of our ability to fund our financing costs and any future capital
requirements.
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 11
CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------------- --------------------
AS AT JUNE 30 As at December 31
- ------------------------------------------------------------------------------------- --------------------
(Unaudited) ($ thousands) 2006 2005
- ------------------------------------------------------------------------------------- --------------------
ASSETS
Current Assets
Cash 6,038 5,590
Accounts Receivable 39,738 87,398
Inventory 25,763 21,083
Prepaid Expense 6,548 9,355
--------- ---------
78,087 123,426
--------- ---------
Property, Plant and Equipment (note 2) 1,428,355 1,352,605
Risk Management (note 13) - 98,426
Deferred Charges 14,783 16,063
--------- ---------
1,443,138 1,467,094
--------- ---------
1,521,225 1,590,520
========= =========
LIABILITIES
Current Liabilities
Accounts Payable and Accrued Liabilities 128,327 101,303
Current Portion of Lease Obligations (note 4) 2,277 3,396
Current Portion of Risk Management (note 13) 1,644 -
Current Portion of Option Premium Liability (note 5) 11,717 -
--------- ---------
143,965 104,699
Long-term Liabilities
Long-term Debt (note 3) 532,750 565,655
Lease Obligations (note 4) 56,933 55,809
Risk Management (note 13) 12,132 -
Option Premium Liability (note 5) 71,816 85,416
Asset Retirement Obligation (note 6) 9,314 9,094
Future Income Tax (note 11) 21,114 56,445
--------- ---------
704,059 772,419
--------- ---------
848,024 877,118
--------- ---------
SHAREHOLDERS' EQUITY
Share Capital (note 8) 551,742 548,747
Contributed Surplus (note 10) 4,640 3,474
Retained Earnings 116,819 161,181
--------- ---------
673,201 713,402
--------- ---------
1,521,225 1,590,520
========= =========
Commitments and Contingencies (note 12)
See Accompanying Notes to the Consolidated Financial Statements
12 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
- --------------------------------------------------------------------------------- -------------------------
Three Months Ended June 30 Six Months Ended June 30
-------------------------- -------------------------
(Unaudited) ($ thousands, except amounts per share) 2006 2005 2006 2005
- --------------------------------------------------------------------- ------- ------- --------
Revenues (note 13) 165,727 244,218 373,487 410,350
Less Purchased Feedstocks and Transportation 70,094 96,051 138,606 170,440
------- ------ ------- -------
95,633 148,167 234,881 239,910
------- ------ ------- -------
Expenses
Operating 89,487 55,347 153,417 114,490
Research and Business Development 7,720 3,448 13,742 4,135
Royalties 718 886 1,358 1,547
General and Administrative 3,210 2,540 7,102 4,479
Insurance 2,697 1,883 5,361 3,780
Interest (note 7) 12,532 15,660 25,561 30,746
Stock-based Compensation (note 10) 1,893 1,082 3,684 1,723
Accretion on Asset Retirement Obligation (note 6) 156 143 311 284
Depreciation, Depletion and Amortization 6,820 13,037 17,366 23,535
------- ------ ------- -------
125,233 94,026 227,902 184,719
------- ------ ------- -------
Earnings (Loss) Before Other (Income) Expense and
Income Taxes (29,600) 54,141 6,979 55,191
Other (Income) Expense
Foreign Exchange (Gain) Loss (25,759) 6,969 (25,389) 9,903
Unrealized Loss on Risk Management (note 13) 44,478 - 112,202 -
------- ------ ------- -------
Earnings (Loss) Before Income Taxes (48,319) 47,172 (79,834) 45,288
Income Tax (Recovery) Expense (note 11) (25,532) 18,522 (35,472) 18,582
------- ------ ------- -------
Net Earnings (Loss) (22,787) 28,650 (44,362) 26,706
Retained Earnings at Beginning of Period 139,606 9,788 161,181 11,732
------- ------ ------- -------
Retained Earnings at End of Period 116,819 38,438 116,819 38,438
======= ====== ======= ======
Net Earnings (Loss) Per Share (note 9)
Basic (0.14) 0.18 (0.28) 0.17
Diluted (0.14) 0.18 (0.28) 0.16
======= ====== ======= ======
See Accompanying Notes to the Consolidated Financial Statements
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 13
CONSOLIDATED STATEMENTS OF CASH FLOWS
- ------------------------------------------------------------------------------------------------------------
Three Months Ended June 30 Six Months Ended June 30
- --------------------------------------------------------------------------------- ------------------------
(Unaudited) ($ thousands) 2006 2005 2006 2005
- --------------------------------------------------------------------- ------ ------- -------
CASH PROVIDED BY (USED IN)
CASH FROM OPERATING ACTIVITIES
Net Earnings (Loss) (22,787) 28,650 (44,362) 26,706
Non-cash Items
Stock-based Compensation (note 10) 1,893 1,082 3,684 1,723
Accretion on Asset Retirement Obligation (note 6) 156 143 311 284
Depreciation, Depletion and Amortization 6,820 13,037 17,366 23,535
Interest Expense on Option Premium Liability (note 5) 934 - 1,886 -
Unrealized Loss on Risk Management (note 13) 44,478 - 112,202 -
Unrealized Foreign Exchange (Gain) Loss (note 3 and 5) (27,310) 7,200 (26,674) 9,900
Future Income Tax (Recovery) Expense (note 11) (24,948) 17,928 (35,331) 17,280
Cash Items
Cash Settlement of Asset Retirement Obligation (note 6) (91) (21) (91) (43)
Cash Settlement of Performance Share Unit Plan (note 10) (28) - (2,104) (596)
------ ------- ------ -------
(20,883) 68,019 26,887 78,789
Decrease (Increase) in Non-cash Working Capital (note 14) 17,070 (37,945) 30,438 (43,388)
------ ------- ------ -------
(3,813) 30,074 57,325 35,401
------ ------- ------ -------
CASH FROM (USED IN) FINANCING ACTIVITIES
Issue of Share Capital (note 8) - 244 2,581 1,045
Issue (Repayment) of Long-term Debt, Net 31,000 (25,000) (10,000) (12,000)
Repayment of Obligations Under Capital Lease (336) (335) (672) (670)
------ ------- ------ -------
30,664 (25,091) (8,091) (11,625)
------ ------- ------ -------
CASH INVESTED
Capital Expenditures (55,828) (9,308) (91,159) (26,862)
Insurance Proceeds - 22,208 - 22,208
Decrease (Increase) in Non-cash Working Capital (note 14) 19,269 (19,159) 42,373 (18,434)
------ ------- ------ -------
(36,559) (6,259) (48,786) (23,088)
------ ------- ------ -------
(DECREASE) INCREASE IN CASH (9,708) (1,276) 448 688
CASH AT BEGINNING OF PERIOD 15,746 5,679 5,590 3,715
------ ------- ------ -------
CASH AT END OF PERIOD 6,038 4,403 6,038 4,403
====== ======= ====== =======
See Accompanying Notes to the Consolidated Financial Statements
14 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) (Tabular amounts in $ thousands, except for share amounts)
The interim consolidated financial statements include the accounts of Western
Oil Sands Inc. and its subsidiaries (the "Corporation"), and are presented in
accordance with Canadian Generally Accepted Accounting Principles. The interim
consolidated financial statements have been prepared using the same accounting
policies and methods of computation as the consolidated financial statements
for the year ended December 31, 2005. The disclosures provided below are
incremental to those included in the annual consolidated financial statements.
The interim consolidated financial statements should be read in conjunction
with the consolidated financial statements and the notes thereto in the
Corporation's annual report for the year ended December 31, 2005.
1. ACCOUNTING POLICY
Property, plant and equipment ("PP&E") assets are recorded at cost less
accumulated provisions for depreciation, depletion and amortization. Prior to
the commencement of commercial operations, interest costs of debt attributable
to major development projects are capitalized.
OIL SANDS MINING
Capitalized costs include costs specifically related to the acquisition,
exploration, development and construction of the Athabasca Oil Sands Project
("AOSP") and other projects, including asset retirement obligations. Oil Sands
Mining assets are reviewed for impairment annually or whenever events or
conditions indicate that their net carrying amount may not be recoverable from
estimated future cash flows. If an impairment is determined, the assets are
written down to the fair value.
Depletion on oil sands mining properties is provided over the life of
proved and probable reserves on a unit of production basis, commencing when the
facilities are substantially complete and after commercial production has
begun.
CONVENTIONAL CRUDE OIL AND IN-SITU OIL SANDS
The Corporation accounts for its conventional crude oil and in-situ properties
and equipment in accordance with the Canadian Institute of Chartered
Accountants' guideline on full cost accounting in the oil and gas industry.
Under this method, all costs associated with the acquisition of, exploration
for and the development of conventional crude oil and in-situ reserves,
including asset retirement obligations are capitalized and accumulated within
cost centres on a country-by-country basis. Such costs include land
acquisition, geological and geophysical activity, drilling and testing of
productive and non-productive wells, carrying costs directly related to
unproved properties, major development projects and administrative costs
directly related to exploration and development activities.
Once the Corporation commences commercial production from the cost
centres, capitalized costs accumulated within each cost centre are depleted on
the unit-of-production method based on the estimated proved reserves of that
country using estimated future prices and costs. Proceeds from the disposal of
properties are normally deducted from the full cost pool without recognition of
a gain or loss unless that deduction would result in a change to the depletion
rate by 20 percent or more, in which case, a gain or loss is recorded.
In determining the depletion base, the Corporation includes estimated
future costs to be incurred in developing proved reserves and excludes the cost
of unproved properties and major development projects. Costs of major
development projects and costs of acquiring and evaluating significant unproved
properties are excluded, on a cost centre basis, from costs subject to
depletion until it is determined whether or not proved reserves are
attributable to the properties, or impairment has occurred. To date, no
depletion related to the Corporation's conventional crude oil and in-situ
properties has been recorded as commercial operations have not commenced.
The Corporation reviews the carrying amount of its conventional crude oil
and in-situ properties relative to their recoverable amount (the "ceiling
test") for each cost centre at each annual balance sheet date, or more
frequently if circumstances or events indicate impairment has occurred. The
recoverable amount is calculated as the sum of:
o the undiscounted future cash flow from proved reserves using expected
future prices and costs;
o the cost of unproved properties; and
o the costs of major development projects less impairment.
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 15
If the carrying amount of the properties exceeds their recoverable amount,
an impairment loss is recognized in depletion equal to the amount by which the
carrying amount of the properties exceeds their fair value. Fair value is
calculated as the sum of:
o the future cash flows from proved and probable reserves using expected
future prices and costs, discounted at a risk-free interest rate; and
o the cost, less impairment, of unproved reserves and major development
projects that do not have probable reserves attributable to them.
CORPORATE AND OTHER
Corporate and Other PP&E assets are depreciated on a straight-line basis over
their useful lives.
2. PROPERTY, PLANT AND EQUIPMENT
June 30, 2006 Cost Accum. DD&A* Net
- --------------------------------------------------------------------------------------------
Athabasca Oil Sands Project
Producing Assets 1,387,499 (120,296) 1,267,203
Capital Leases 52,705 (4,900) 47,805
Expansions 87,385 - 87,385
- --------------------------------------------------------------------------------------------
1,527,589 (125,196) 1,402,393
- --------------------------------------------------------------------------------------------
Kurdistan Exploration Project 13,615 - 13,615
- --------------------------------------------------------------------------------------------
Corporate and Other 13,902 (1,555) 12,347
- --------------------------------------------------------------------------------------------
1,555,106 (126,751) 1,428,355
============================================================================================
December 31, 2005 Cost Accum. DD&A* Net
- --------------------------------------------------------------------------------------------
Athabasca Oil Sands Project
Producing Assets 1,350,436 (105,010) 1,245,426
Capital Leases 52,705 (4,294) 48,411
Expansions 38,235 - 38,235
- --------------------------------------------------------------------------------------------
1,441,376 (109,304) 1,332,072
- --------------------------------------------------------------------------------------------
Kurdistan Exploration Project 8,962 - 8,962
- --------------------------------------------------------------------------------------------
Corporate and Other 12,933 (1,362) 11,571
- --------------------------------------------------------------------------------------------
1,463,271 (110,666) 1,352,605
============================================================================================
* Accumulated Depreciation, Depletion and Amortization
At June 30, 2006, the Producing Assets in the AOSP include asset retirement
costs, net of amortization of $7.1 million ($7.2 million - 2005). Costs not
currently subject to depreciation, depletion and amortization include $87.4
million relating to the AOSP and $5.7 million relating to Corporate and Other,
as the projects associated with these costs were not substantially complete and
there has been no commercial production associated with these projects. All
costs included in the Kurdistan Exploration Project are excluded from depletion
as they represent costs related to unproved properties incurred in a cost
centre that are considered to be in the pre-production stage. Currently, there
are no proved reserves in this cost centre. All costs, net of any associated
revenues, in this cost centre have been capitalized.
3. LONG-TERM DEBT
June 30, December 31,
2006 2005
- -------------------------------------------------------------------------------------------
US $450 million Senior Secured Notes 501,750 524,655
Revolving Credit Facility 31,000 41,000
- -------------------------------------------------------------------------------------------
532,750 565,655
===========================================================================================
16 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
The Corporation's US dollar denominated Senior Secured Notes (the "Notes") are
translated into Canadian dollars at the period end exchange rate. The
unrealized foreign exchange gain arising on the Notes for the three and six
month periods ended June 30, 2006 was $23.4 million and $22.9 million,
respectively (June 30, 2005 - $7.2 million and $9.9 million unrealized foreign
exchange loss). As at June 30, 2006, a total of $207.1 million of unrealized
foreign exchange gains had been recognized from the inception of the Notes,
approximately $92 million of which has been capitalized as the unrealized gains
were recognized prior to commercial operations.
4. LEASE OBLIGATIONS
June 30, December 31,
2006 2005
- ------------------------------------------------------------------------------------------
Obligations Under Capital Lease 49,598 50,266
Operating Lease Guarantee Obligation 9,612 8,939
- ------------------------------------------------------------------------------------------
59,210 59,205
Less: Current Portion 2,277 3,396
- ------------------------------------------------------------------------------------------
56,933 55,809
==========================================================================================
The capital lease obligation relates to the Corporation's share of capital
costs for the hydrogen-manufacturing unit within the AOSP. Repayments of the
principal obligation are $1.3 million per year and are scheduled to remain at
that level until repaid.
Under the Operating Lease for Mobile Equipment, the Corporation is
committed to pay its 20 per cent share of an amount equal to 85 per cent of the
original cost of the equipment to the lessor at the end of the terms of the
lease. Accordingly, the Corporation recognized, as a liability, a portion of
this future payment as it relates to the service life of the equipment that has
passed. During the three and six month period ended June 30, 2006, the
Corporation paid $0.4 million and $0.6 million, in regard to this obligation
(June 30, 2005 - $0.1 million and $1.5 million, respectively).
5. OPTION PREMIUM LIABILITY
The Corporation deferred payment and receipt of the premiums associated with
the options described in Note 13(b) until the settlement of the option
contracts between 2007 and 2009. The total net premiums payable by the
Corporation are US$21.9 million for 2007, US$32.4 million for 2008 and US$27.8
million for 2009. On the dates that the option contracts were entered, a net
liability was recognized on the consolidated balance sheet at the estimated
present value of the net premiums payable. Subsequent to the inception dates of
the option contracts, interest expense is recognized, with a corresponding
increase to the liability, at annual rates ranging from 4.25% to 4.50%. During
the three and six month periods ended June 30, 2006, $0.9 million and $1.9
million of interest expense was recognized (June 30, 2005 - nil). The option
premium liability is denominated in US dollars and is translated into Canadian
dollars at the period end exchange rate. The unrealized foreign exchange gain
arising on the option premium liability for the three and six month periods
ended June 30, 2006 was $3.9 million and $3.8 million, respectively (June 30,
2005 - nil).
The following table presents the reconciliation of the net Option Premium
Liability:
Three Months Ended June 30 Six Months Ended June 30
-------------------------------------------------------
2006 2005 2006 2005
- ---------------------------------------------------------------------------------------------------------------
Option Premium Liability at Beginning of Period 86,464 - 85,416 -
Interest Expense 934 - 1,886 -
Unrealized Foreign Exchange Gain (3,865) - (3,769) -
- ---------------------------------------------------------------------------------------------------------------
Option Premium Liability at End of Period 83,533 - 83,533 -
Less: Current Portion 11,717 - 11,717 -
- ---------------------------------------------------------------------------------------------------------------
71,816 - 71,816 -
===============================================================================================================
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 17
6. ASSET RETIREMENT OBLIGATION
The Corporation, in association with its 20 per cent working interest in the
AOSP, is responsible for its share of future dismantlement and site restoration
costs in the mining, extracting and upgrading activities. The following table
presents the reconciliation of the Asset Retirement Obligation:
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Asset Retirement Obligations at Beginning of Period 9,249 8,310 9,094 8,191
Liabilities Settled (91) (21) (91) (43)
Accretion on Asset Retirement Obligation 156 143 311 284
- -------------------------------------------------------------------------------------------------------------
Asset Retirement Obligations at End of Period 9,314 8,432 9,314 8,432
=============================================================================================================
7. INTEREST EXPENSE
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Interest on Long-term Debt 10,888 15,017 22,219 29,556
Interest on Obligations Under Capital Lease 710 643 1,456 1,190
Interest on Option Premium Liability 934 - 1,886 -
- -------------------------------------------------------------------------------------------------------------
12,532 15,660 25,561 30,746
=============================================================================================================
Cash interest paid for the three and six month periods ended June 30, 2006 was
$22.8 million and $24.1 million, respectively (June 30, 2005 - $26.5 million
and $31.5 million). Cash interest received for the three and six month periods
ended June 30, 2006 was $0.1 million (June 30, 2005 - $0.1 million).
8. SHARE CAPITAL
ISSUED AND OUTSTANDING
Number of
Shares Amount
- -----------------------------------------------------------------------------------------------------------
COMMON SHARES
Balance at December 31, 2005 160,518,041 548,747
Issued for Cash 552,108 2,581
Exercise of Stock Options Previously Recognized - 414
- -----------------------------------------------------------------------------------------------------------
Total Share Capital at June 30, 2006 161,070,149 551,742
===========================================================================================================
OUTSTANDING
Stock Options 3,772,514
- ----------------------------------------------------------------------------------------------
DILUTED SHARES AT JUNE 30, 2006 164,842,663
==============================================================================================
9. NET EARNINGS PER SHARE
The basic and diluted weighted average number of common shares outstanding,
both current and prior period, reflect a three-for-one stock split of the
Corporation's common shares on May 30, 2005. The basic weighted average number
of common shares for the three and six month periods ended June 30, 2006 are
161,070,149 and 160,848,345, respectively (June 30, 2005 - 160,120,507 and
160,039,942). Due to a loss for the three and six month periods ended June 30,
2006, no incremental shares were included for the diluted earnings per share
weighted average number because the effect would be anti-dilutive. The diluted
weighted average number of shares for the three and six month periods ended
June 30, 2005 were 162,180,067 and 162,169,374, respectively.
18 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
10. STOCK-BASED COMPENSATION
(a) STOCK OPTION PLAN
Under the Corporation's stock-based compensation plan, 10,000 options were
granted during the three month period ended June 30, 2006 at an average
exercise price of $35.40 per share (June 30, 2005 - 162,000 options at an
average exercise price of $17.46 per share). The fair values of all options
granted during the period are estimated as at the grant date using the
Black-Scholes option-pricing model. The Corporation utilizes sources such as
Bloomberg L.P. in determination of certain assumptions. The weighted-average
fair values of the options and the assumptions used in their determination are
as follows:
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Granted 10,000 162,000 797,540 353,670
Weighted-average Fair Value $14.49 $7.57 $15.98 $7.18
Risk Free Interest Rate 4.49% 3.79% 4.30% 3.93%
Expected Life (in Years) 6.00 6.00 6.00 6.00
Expected Volatility 33% 30% 33-43% 26-30%
Dividend Per Share - - - -
=============================================================================================================
(b) PERFORMANCE SHARE UNIT PLAN
The following table presents the reconciliation of the number of Performance
Share Units:
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Outstanding at Beginning of Period 219,502 180,078 160,128 99,291
Granted 10,550 - 133,195 113,880
Exercised - - (63,111) (33,093)
Cancelled - - (160) -
- -------------------------------------------------------------------------------------------------------------
Outstanding at End of Period 230,052 180,078 230,052 180,078
=============================================================================================================
(c) DEFERRED SHARE UNIT PLAN
Under the Deferred Share Unit Plan ("DSUP"), for the three and six month
periods ended June 30, 2006, $0.1 million and $0.2 million (June 30, 2005 -
nil) in compensation expense was recorded in General and Administrative
Expenses, respectively. No Deferred Share Units ("DSU") were redeemed for cash
or shares of the Corporation for the three and six month periods ended June 30,
2006 and 2005. The Corporation had 8,923 DSUs outstanding at June 30, 2006
(June 30, 2005 - nil).
(d) STOCK-BASED COMPENSATION
For the three and six month periods ended June 30, 2006, the Corporation
recognized $1.9 million and $3.7 million, respectively, (June 30, 2005 - $1.1
million and $1.7 million) in compensation expense related to stock-based
compensation issued subsequent to January 1, 2003. For the three month period
ended June 30, 2006, the compensation expense is comprised of $1.2 million
(June 30, 2005 - $0.4 million) in respect to the Corporation's stock option
plan and $0.7 million (June 30, 2005 - $0.7 million) in respect to the
Corporation's Performance Share Unit Plan. For the six month period ended June
30, 2006, the compensation expense is comprised of $2.0 million (June 30, 2005
- - $0.6 million) in respect to the Corporation's stock option plan and $1.7
million (June 30, 2005 - $1.1 million) in respect to the Corporation's
Performance Share Unit Plan.
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 19
Under CICA 3870, no compensation expense is required to be recognized for
stock options granted before January1, 2003. Had compensation expense been
determined based on the fair value method for awards granted on or after
December 31, 2001 but before January 1, 2003, the Corporation's net earnings
and net earnings per share would have been adjusted to the proforma amounts
indicated below:
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Net Earnings (Loss) - As Reported (22,787) 28,650 (44,362) 26,706
Compensation Expense 24 222 159 442
- -------------------------------------------------------------------------------------------------------------
Net Earnings (Loss) - Pro Forma (22,811) 28,428 (44,521) 26,264
=============================================================================================================
Basic Earnings (Loss) Per Share
As Reported (0.14) 0.18 (0.28) 0.17
Pro Forma (0.14) 0.18 (0.28) 0.16
Diluted Earnings (Loss) Per Share
As Reported (0.14) 0.18 (0.28) 0.16
Pro Forma (0.14) 0.18 (0.28) 0.16
=============================================================================================================
(e) CONTRIBUTED SURPLUS
The following table presents the reconciliation of Contributed Surplus:
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Contributed Surplus Beginning of Period 2,775 1,290 3,474 1,245
Stock-based Compensation Expense 1,893 1,082 3,684 1,723
Cash Settlement of Performance Share Unit Plan (28) - (2,104) (596)
Exercise of Stock Options Previously Recognized - - (414) -
- -------------------------------------------------------------------------------------------------------------
Contributed Surplus End of Period 4,640 2,372 4,640 2,372
=============================================================================================================
11. INCOME TAX
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Large Corporations Tax (Recovery) Expense (584) 594 (141) 1,302
Future Income Tax (Recovery) Expense (24,948) 17,928 (35,331) 17,280
- -------------------------------------------------------------------------------------------------------------
Income Tax (Recovery) Expense (25,532) 18,522 (35,472) 18,582
=============================================================================================================
The future income tax liability consists of:
June 30, December 31,
2006 2005
- -------------------------------------------------------------------------------------------------------------
Future Income Tax Assets
Unrealized Loss on Risk Management 29,942 -
Net Losses Carried Forward 2,917 4,707
Share Issue Costs 718 973
Impairment of Long-lived Assets 686 796
Future Income Tax Liabilities
Capital Assets in Excess of Tax Values (35,582) (39,924)
Unrealized Foreign Exchange Gain (16,691) (15,500)
Unrealized Gain on Risk Management - (4,374)
Debt Issue Costs (3,104) (3,123)
- -------------------------------------------------------------------------------------------------------------
Net Future Income Tax Liability (21,114) (56,445)
=============================================================================================================
20 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
The following table reconciles income taxes calculated at the Canadian
statutory rate of 34.50% (2005 - 37.62%) with actual income taxes:
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Net Earnings (Loss) Before Income Taxes (48,319) 41,172 (79,834) 45,288
Income Tax (Recovery) Expense at Statutory Rate (16,317) 17,746 (27,543) 17,037
Effect of Tax Rate Changes and Timing of Use (5,006) 603 (4,341) 1,036
Non-taxable Portion of Foreign Exchange (Gain) Loss (4,682) 1,498 (4,581) 2,060
Non-deductible Expenses 130 - 326 -
Resource Allowance 26 (3,108) 3 (4,042)
Stock-based Compensation 669 425 573 764
Provision to Actual 232 764 232 425
Large Corporations Tax (Recovery) Expense (584) 594 (141) 1,302
- -------------------------------------------------------------------------------------------------------------
Income Tax (Recovery) Expense (25,532) 18,522 (35,472) 18,582
=============================================================================================================
12. COMMITMENTS AND CONTINGENCIES
EXPLORATION AND PRODUCTION SHARING AGREEMENT
The Corporation, through its wholly-owned subsidiary, WesternZagros Limited,
entered into an Exploration and Production Sharing Agreement ("EPSA") dated May
4, 2006 with the Kurdistan Regional Government, Sulaymaniyah Administration to
explore for conventional oil and gas in the Federal Region of Kurdistan.
Management expects this agreement to be passed into law by the unified
government of the Federal Region of Kurdistan within the next few months, at
which time, the agreement will be effective. Under the terms of the EPSA,
WesternZagros has made a minimum contractual commitment of US$45 million for an
exploration program for a period of four years from the date the EPSA is passed
into law.
13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Corporation has entered into various commodity-pricing agreements designed
to mitigate the exposure to the volatility of crude oil prices in US dollars,
thereby providing greater certainty of future cash flow from the sale of the
Corporation's synthetic crude oil products. This risk management strategy is
intended to protect the Corporation's base and future capital programs and
ensure the funding of debt obligations. Certain of these commodity-pricing
agreements were accounted for as hedges, as they qualified for hedge accounting
under Accounting Guideline 13 and were designated as hedges, while other
commodity-pricing agreements are accounted for under fair value accounting as
they did not qualify or have not been designated as hedges for accounting
purposes.
(a) HEDGE ACCOUNTING
There were no crude swap positions in place during the three and six month
periods ended June 30, 2006 as the crude oil swaps were completed in 2005. For
the three and six month periods ended June 30, 2005, the Corporation's revenues
were reduced by $20.8 million and $57.6 million, respectively, from crude oil
price hedging losses.
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 21
(b) FAIR VALUE ACCOUNTING
The Corporation has put options at strike prices ranging from US$50.00 to
US$55.00 per barrel, averaging US$52.42 per barrel for the three year period
beginning January 1, 2007. The premiums for the purchased put options were
partially offset through the sale of call options at strike prices ranging from
US$90.00 to US$95.00 per barrel, averaging US$92.41 per barrel for the three
year period beginning January 1, 2007, resulting in a net premium liability.
Payment of the net premium liability is deferred until the settlement of the
option contracts between 2007 and 2009. As at June 30, 2006, the Corporation
had outstanding the following put and call options:
2007 2008 2009
- -----------------------------------------------------------------------------------------------------------
Barrels Per Day
Put Options Purchased 20,000 20,000 20,000
Call Options Sold 10,000 15,000 15,000
US$ Per Barrel
Average Put Strike Price US$52.50 US$54.25 US$50.50
Average Call Strike Price US$92.50 US$94.25 US$90.50
===========================================================================================================
The fair value of the option contracts was recognized on the consolidated
balance sheet on the dates they were entered into. During the three and six
month periods ended June 30, 2006, the Corporation recognized an unrealized
loss of $44.5 million and $112.2 million (June 30, 2005 - nil) on the Risk
Management Asset (Liability), marking it to the fair value at the end of the
period. The counterparties to these put and call options have investment grade
credit ratings, thereby partially mitigating the credit risk associated with
these financial instruments.
The following table presents the reconciliation of the Risk Management
Asset (Liability):
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Risk Management Asset at Beginning of Period 30,702 - 98,426 -
Unrealized Loss on Risk Management (44,478) - (112,202) -
- -------------------------------------------------------------------------------------------------------------
Risk Management Asset at End of Period (13,776) - (13,776) -
Less: Current Portion (1,644) - (1,644) -
- -------------------------------------------------------------------------------------------------------------
(12,132) - (12,132) -
=============================================================================================================
14. CHANGES IN NON-CASH WORKING CAPITAL
Three Months Ended June 30 Six Months Ended June 30
-----------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------
Source/(Use)
OPERATING ACTIVITIES
Accounts Receivable 21,975 (19,395) 47,660 (26,715)
Inventory 6,219 2,591 (4,680) (8,771)
Prepaid Expense 2,138 (2,201) 2,807 (2,856)
Accounts Payable and Accrued Liabilities (13,262) (18,940) (15,349) (5,046)
- -------------------------------------------------------------------------------------------------------------
17,070 (37,945) 30,438 (43,388)
=============================================================================================================
INVESTING ACTIVITIES
Accounts Receivable - (19,380) - (19,380)
Accounts Payable and Accrued Liabilities 19,269 221 42,373 946
- -------------------------------------------------------------------------------------------------------------
19,269 (19,159) 42,373 (18,434)
=============================================================================================================
22 SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS
CORPORATE INFORMATION
OFFICERS DIRECTORS HEAD OFFICE
JAMES C. HOUCK GUY J. TURCOTTE Suite 2400, Ernst & Young Tower
President and Chief Executive Officer Chairman of the Board, 440 - 2nd Avenue S.W.
Western Oil Sands Inc. Calgary, Alberta T2P 5E9
STEVE D. L. REYNISH Calgary, Alberta Phone: (403) 233-1700
Executive Vice President and Fax: (403) 234-9156
Chief Operating Officer GEOFFREY A. CUMMING
Lead Director WEBSITE
DAVID A. DYCK Vice Chairman,
Senior Vice President, Finance and Gardiner Group Capital Limited www.westernoilsands.com
Chief Financial Officer Toronto, Ontario
Deputy Chairman, AUDITORS
CHARLES W. BERARD Emerald Capital Limited
Corporate Secretary Auckland, New Zealand PricewaterhouseCoopers LLP
Calgary, Alberta
DAVID J. BOONE
SENIOR MANAGEMENT President and Director, LEGAL COUNSEL
Escavar Energy
JOHN FRANGOS Calgary, Alberta Macleod Dixon LLP
Corporate Development Calgary, Alberta
TULLIO CEDRASCHI Paul, Weiss, Rifkind, Wharton
M. SIMON HATFIELD President and Chief Executive Officer, & Garrison LLP
Vice President and Managing Director, CN Investment Division Washington, D.C., USA
Oil &Gas Montreal, Quebec
INDEPENDENT EVALUATORS
JACK D. JENKINS JAMES C. HOUCK
Vice President, Corporate Planning President and Chief Executive Officer, GLJ Petroleum Consultants Ltd.
& Human Resources Western Oil Sands Inc. Calgary, Alberta
Calgary, Alberta Norwest Corporation
GERRY LUFT Calgary, Alberta
Vice President, Downstream OYVIND HUSHOVD
Corporate Director REGISTRAR AND
RAY MORLEY Kristiansand, Norway TRANSFER AGENT
Vice President, Business Development
JOHN W. LILL Valiant Trust Company
Executive Vice President and Calgary, Alberta
Chief Operating Officer,
Dynatec Corporation STOCK EXCHANGE LISTING
Richmond Hill, Ontario
The Toronto Stock Exchange
RANDALL OLIPHANT Trading Symbol:WTO
Chairman and Chief Executive Officer,
Rockcliff Group Limited
Toronto, Ontario
ROBERT G. PUCHNIAK
Executive Vice President and
Chief Financial Officer,
James Richardson & Sons Limited
Winnipeg, Manitoba
MAC H. VAN WIELINGEN
Co-Chairman,
ARC Financial Corporation
Calgary, Alberta
SECOND QUARTER INTERIM REPORT 2006 WESTERN OIL SANDS 23