EXHIBIT 99.1
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Q3
WESTERN OIL SANDS 2006 INTERIM REPORT
FOR THE NINE-MONTH PERIOD
ENDED SEPTEMBER 30, 2006
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WESTERN OIL SANDS
INTERIM REPORT FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2006
MESSAGE TO SHAREHOLDERS
Western Oil Sands Inc. ("Western") is pleased to report record third quarter
2006 results and provide an operational update for the Athabasca Oil Sands
Project (the "Project" or the "AOSP"). During the third quarter of 2006,
Western generated record net revenue of $206.2 million, EBITDAX of $123.4
million, cash flow from operations of $110.5 million ($0.69 per share) and net
earnings of $84.5 million ($0.52 per share). By comparison, in the third
quarter of 2005, Western generated net revenue of $185.7 million, EBITDAX of
$111.0 million, cash flow from operations of $95.0 million ($0.59 per share)
and net earnings of $79.4 million ($0.50 per share).
Relative to the comparable quarter in 2005, financial results for the
third quarter of 2006 were positively impacted by a 12 per cent increase in
West Texas Intermediate ("WTI") prices, narrower heavy crude oil price
differentials, lower natural gas prices and no volumes subject to fixed priced
hedge contracts. Relative to the second quarter of 2006, results were
positively impacted by continued strength in WTI prices, higher production
levels due to the completion of the first full turnaround of the AOSP in July,
partially offset by marginally wider heavy crude oil differentials. In the
third quarter of 2006, a total of $33.1 million of unrealized foreign exchange
and risk management gains ($23.2 million net of tax) was included in net
earnings, compared to unrealized foreign exchange and risk management gains of
$31.9million ($26.2 million net of tax) for the third quarter of 2005.
HIGHLIGHTS
o Western exercised its option to participate to its 20 per cent interest in
Chevron Canada's ("Chevron") Ells River In-Situ Project on August 31, 2006. The
Ells River Project is located approximately 50 kilometers northwest of Fort
McMurray in the Athabasca oil sands region and currently comprises
approximately 75,000 acres of land (15,000 acres net to Western). Chevron
estimates there are 7.5 billion barrels of oil in place and potential for
in-situ oil recovery from these resources. An 80 to 100 well appraisal drilling
program is expected to commence in the 2006/2007 winter season, and will
continue in parallel with engineering, processing and other technical
evaluation work.
o Western appointed Mr. Graig Ritchie to the position of Vice President, Oil
Sands. Mr. Ritchie, who will have primary responsibility for Western's in-situ
and other corporate initiatives, has over 20 years of experience in oil sands
with EnCana Corporation and Imperial Oil Limited in production, engineering and
market development.
o Western acquired two additional leases which are prospective for in-situ
development in the Athabasca region during the third quarter, namely leases 442
and 472, which are contiguous to Western's existing lease 353. Taken together,
this brings the total acreage under leases which would be operated by Western
to over 21,000 acres.
o Western, together with the other Joint Venture Owners, successfully
completed the first full turnaround of the Mine and Upgrader in the third
quarter. In total, over 630,000 man hours were dedicated to this process, and
resulted in a quick ramp-up to production rates achieved prior to the
turnaround. Western's share of the turnaround expenses totaled approximately
$40 million, including $5.3 million which was incurred during the third
quarter.
o During the third quarter, Western's Board of Directors approved additional
pre-final investment decision capital commitments of approximately $315 million
for the AOSP Expansion 1. These commitments allowed the Project to proceed with
its planned schedule, fixing the price of key components, and involved
committing to major long lead time equipment as well as to incur other
pre-construction expenditures.
HIGHLIGHTS SUBSEQUENT TO THE END OF THE QUARTER
o On October 25, 2006, Western announced that its Board of Directors
approved the Company's participation in Expansion 1 of the AOSP, pending final
regulatory approval. This is the first of three planned 100,000 barrel per day
expansions to the AOSP. Expansion 1 is a fully integrated expansion of the
existing AOSP facilities and includes new oil sands mining operations on Lease
13, associated additional bitumen upgrading at the Scotford Upgrader, and the
construction of common upstream infrastructure that will be sized to support
future mining expansions. This decision marks a key step in growing Western's
production to 150,000 to 200,000 barrels per day within the next 15 years. The
capital cost estimate for Expansion 1 remains at approximately $11.2 billion
($2.2 billion net to Western), with contingency and Owners costs representing a
significant portion of this estimate.
o With approval of Expansion 1, Western also reported increased oil sands
reserve estimates using reserve definitions in accordance with National
Instrument 51-101. Western's qualified independent evaluator, GLJ Petroleum
Consultants ("GLJ"), has initially estimated that Western's working interest or
Company gross proved plus probable reserves from AOSP Expansion 1 are
approximately 252 million barrels of synthetic crude oil. This represents an
increase of more than 80 per cent over the reserve position assigned to the
Muskeg River Mine as at December 31, 2005 and reported in Western's Annual
Information Form, bringing the total estimated proved and probable reserves to
over 554 million barrels net of production as at the end of October 2006. Upon
regulatory approval of the Muskeg River Mine expansion, GLJ will also
reclassify 84 million barrels of probable reserves net to Western to proved
reserves. As a result of this reclassification, total proved reserves will
represent 483 million barrels or over 87 per cent of the total estimated 554
million barrels of proved and probable reserves.
Along with Western exercising its option to participate in Expansion 1, a
payment to Shell Canada Limited of approximately $15 million is required
associated with the incremental project reserves of recoverable bitumen as per
the terms of the Joint Venture Agreement.
o Following six years of service, Mr. Tullio Cedraschi announced his
resignation from Western's Board of Directors. We thank Mr. Cedraschi for his
service, counsel and outstanding leadership through Western's start-up to an
operating company. Western has started a search for a replacement director and
an appointment will be made in due course.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion of financial condition and results of operations was
prepared as of October 25, 2006 and should be read in conjunction with the
Interim Unaudited Consolidated Financial Statements for the periods ended
September 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 September 30 Nine Months Ended September 30
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2006 2005 2006 2005
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Operating Data (bbls/d)
Bitumen Production 32,836 33,034 24,799 30,789
Synthetic Crude Sales 43,746 43,240 34,540 40,776
Operating Expense per Processed Barrel ($/bbl) 22.38 20.58 32.38 21.50
Financial Data ($ thousands, except as indicated)
Net Revenue 206,247 185,689 441,128 425,599
Realized Crude Oil Sales Price ($/bbl) (1) (2) 67.42 58.79 62.92 49.62
EBITDAX (1) (3) 123,441 111,003 177,342 222,482
Cash Flow from Operations (4) 110,500 95,048 137,387 173,837
Cash Flow per Share - Basic ($/Share) (1) (5) 0.69 0.59 0.85 1.09
Net Earnings (6) 84,531 79,373 40,169 106,079
Net Earnings Per Share - Basic ($/Share) 0.52 0.50 0.25 0.66
Net Capital Expenditures (7) 96,402 15,960 187,561 20,614
Long-term Financial Liabilities (8) 670,925 736,918 670,925 736,918
Weighted Average Shares Outstanding - Basic (Shares) 161,084,823 160,229,593 160,928,037 160,103,854
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(1) Please refer to page 12 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 hedging
activities, divided by the corresponding volume. Please refer to page 4 for
the calculation of net revenue.
(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.
OPERATING RESULTS
Production
The AOSP completed its first full turnaround of the Mine and Upgrader early in
the third quarter of 2006 and, as a result, third quarter production averaged
32,836 barrels per day compared to 33,034 barrels per day in the third quarter
of 2005. The impact of the turnaround reduced production for the month of July
to 28,594 barrels per day. The AOSP successfully ramped-up production to rates
achieved prior to the turnaround and experienced little or no disruption as the
Project returned to full production. More than 630,000 man hours were dedicated
to the turnaround process covering a period of 56 days. Due to the discovery of
additional coking inside the residual hydrocrackers during the turnaround
process, the schedule was extended resulting in higher than expected turnaround
costs totaling $40.2 million net to Western, including $5.3 million incurred in
the third quarter. The Joint Venture studied the learnings from this major
turnaround and is investigating whether full Mine and Upgrader turnarounds will
be required on a three year cycle or if more optimal sequencing of units could
be achieved.
Revenue
Net Revenue Three Months Ended September 30 Nine Months Ended September 30
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($ thousands, except as indicated) 2006 2005 2006 2005
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Revenue
Oil Sands (1) 271,992 235,181 594,442 554,419
Marketing and Transportation 50,183 40,010 101,220 131,122
Total Revenue 322,175 275,191 695,662 685,541
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Purchased Feedstocks and Transportation
Oil Sands 65,750 49,512 153,859 128,175
Marketing and Transportation 50,178 39,990 100,675 131,767
Total Purchased Feedstocks and Transportation 115,928 89,502 254,534 259,942
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Net Revenue
Oil Sands (1) 206,242 185,669 440,583 426,244
Marketing and Transportation 5 20 545 (645)
Total Net Revenue 206,247 185,689 441,128 425,599
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Synthetic Crude Sales (bbls/d) 43,746 43,240 34,450 40,776
Realized Crude Oil Sales Price ($/bbl) (2) 67.42 58.79 62.92 49.62
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(1) Oil Sands Revenue and Net Revenue are presented net of Western's hedging
activities.
(2) Realized Crude Oil Sales Price ($/bbl) is calculated as Oil Sands Revenue
less any transportation costs divided by synthetic crude sales volume. For
three and nine months ended September 2006, $0.7 million and $1.2 million,
respectively, have been incurred for transportation costs related to Oil
Sands.
Western recorded crude oil sales revenue of $322.2 million in the third quarter
of 2006, including $272.0 million from proprietary production compared to
$275.2 million in the third quarter of 2005, which included $235.2 million from
proprietary production. This 17 per cent year-over-year increase in crude oil
sales revenue is mainly the result of a $8.63 per barrel, or 15 per cent,
increase in our realized crude oil sales price to $67.42 per barrel in the
third quarter of 2006 compared to $58.79 per barrel for the prior year period.
Oil sands sales volumes, including bitumen and purchased feedstocks,
averaged 43,746 barrels per day in the third quarter of 2006 which is
comparable to the 43,240 barrels per day recorded in the third quarter of 2005
as production and corresponding sales activity following the full turnaround
returned to historical norms.
An increased realized sales price in the third quarter of 2006 compared to
the prior year period is predominantly due to a 12 per cent increase in
underlying WTI prices which averaged $70.48 per barrel for the quarter compared
to $63.19 per barrel in the third quarter of 2005. Also contributing to higher
year-over-year realizations is the absence of lower-priced fixed price swap
contracts in 2006 and a narrowing of the heavy crude oil price differential,
partially offset by the strengthening of the Canadian dollar relative to the US
dollar. The heavy crude oil price differential narrowed by approximately
US$0.91 per barrel averaging US$19.42 per barrel for the third quarter of 2006
compared to US$20.32 per barrel for the prior year period or, in percentage
terms, 28 per cent in the third quarter of 2006 compared to 32 per cent for the
third quarter of 2005. As communicated in previous interim reports, this
general narrowing of the heavy crude oil differential in recent quarters is due
to increased access of Canadian heavy crude oil to markets in the United States
Midwest and Gulf Coast regions through recent crude oil pipeline reversals. The
differential is also narrower year-over-year due to a longer than normal
asphalt season which uses heavy crude oil as a feedstock for road construction.
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
which also contributed to dramatically higher sales price realizations compared
to the third quarter of 2005.
Compared to the second quarter of 2006, Western's sales price realizations
increased $0.94 per barrel primarily a result of a return to more optimal plant
operations which generally lightens the overall sales mix stemming from the
completion of the turnaround, combined with a marginal weakening of the
Canadian dollar relative to the US, partially offset by both marginally lower
WTI prices and marginally wider heavy crude oil price differentials.
After deducting the cost of purchased feedstocks and transportation costs
downstream of Edmonton, Western's net revenue totaled $206.2 million in the
third quarter of 2006 representing an 11 per cent increase over the $185.7
million recorded in the third quarter of 2005. Feedstocks are crude products
introduced at the Upgrader. Some 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.
Operating Costs
Western's unit cash operating costs increased slightly to $20.67 per processed
barrel, excluding turnaround expenses, in the third quarter of 2006 compared to
$20.58 per processed barrel for the third quarter of 2005. Operating costs,
including turnaround expenses, were $22.38 per barrel as the turnaround
extended into the beginning of July 2006. Western's share of the turnaround
expenses totaled $40.2 million, $5.3 million of which was incurred in the third
quarter of 2006. Excluding turnaround expenses, operating costs during the
third quarter of 2006 were positively impacted by a 23 per cent decrease in
NYMEX natural gas prices. Compared to the third quarter of 2005, this impact
was offset by higher maintenance costs associated with a high commodity price
environment, together with higher priced feedstocks in inventory at June 30,
2006 flowing through cost of sales in the third quarter of 2006. The Project is
committed to analyzing potential improvements in the operations to enhance
availability and reliability factors.
Three Months Ended September 30 Nine Months Ended September 30
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($ thousands, except as indicated) 2006 2005 2006 2005
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Operating Expenses For Bitumen Sold
Operating Expense - Income Statement 61,192 64,810 179,710 179,300
Operating Expense - Inventoried 2,136 (979) 5,619 3,095
Turnaround Costs - Income Statement 5,261 - 40,160 -
Total Operating Expenses For Bitumen Sold 68,589 63,831 225,489 182,564
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Sales (barrels per day)
Total Synthetic Crude Sales 43,746 43,240 34,540 40,766
Purchased Upgrader Blend Stocks 10,437 9,532 9,034 9,702
Synthetic Crude Sales Excluding Blend Stocks 33,309 33,708 25,506 31,074
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Operating Expenses Per Processed Barrel ($/bbl) (1) 22.38 20.58 32.38 21.50
Operating Expenses Per Processed Barrel
Excluding Turnaround Costs ($/bbl) (2) 20.67 20.58 26.62 21.50
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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 blendstocks, for the relevant period. This calculation
recognizes that, intrinsic in the Project's operations, bitumen production from
the Mine receives an approximate three per cent uplift as a result of the
hydrotreating/hydroconversion process, which is included in synthetic crude
sales excluding blendstocks.
Royalties
As a result of higher deemed bitumen prices offset slightly by lower
production, royalties totaled $1.5 million in the third quarter of 2006 which
is comparable to the $1.4 million in the third quarter of 2005. Royalties were
$0.8 million higher in the third quarter compared to the second quarter of 2006
due to the Project completing the turnaround in early July.
Western continues to pay a one per cent royalty on the gross deemed
bitumen revenues and, at current commodity prices, we do not anticipate
conversion to the 25 per cent of net bitumen revenues for the next several
years. This assessment is based on the premise that capital associated with
expansions to the base Project are included in the capital base from which the
deemed bitumen revenue is drawn.
CORPORATE RESULTS
Research and Business Development Expense
Western incurred $8.3 million in research and development expenses in the third
quarter of 2006 compared to $3.9 million in the third quarter of 2005. Of the
$8.3 million incurred during the third quarter, $5.4 million (or 65 per cent)
relates to AOSP-related research and development projects. This 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 other Western-led initiatives.
General and Administrative Expense
General and administrative expenses ("G&A") were $3.9 million for the third
quarter of 2006 compared to $2.7 million for the third quarter of 2005. This
increase is due to the addition of employees within Western and higher
professional fees associated with regulatory compliance and expansion related
initiatives.
Insurance Expense
Insurance expenses were $2.6 million for the third quarter of 2006 compared to
$1.9 million in the third 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 $13.6 million in the third quarter of 2006 which is
comparable to the amount recorded during the third quarter of 2005. Interest
expense in the third quarter of 2006 is comprised of $11.9 million related to
interest charges on debt obligations (Q3-2005 - $12.6 million), $0.7 million
(Q3-2005 - $0.6 million) on capital lease obligations and $0.9 million (Q3-2005
- - $0.3 million) 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.
Quarter-over-quarter interest expense is comparable as a result of Western
carrying a larger average balance in its Revolving Credit Facility during the
third quarter of 2006. This was offset by 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. Higher Revolving Credit Facility balances are a
direct result of the full turnaround and the ramp-up of capital associated with
pre-Final Investment Decision (FID) expenditures resulting in Western drawing
on this facility to satisfy working capital commitments. Western anticipates
higher interest cost as we move through the financing of Expansion 1 as the
Revolving Credit Facility, together with possible other forms of debt
financing, will be utilized to fund Western's 20 per cent share of the
expansion. Interest costs related to Western's funding of Expansion 1 will be
capitalized and amortized over the life of the Expansion once production
commences.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization ("DD&A") totaled $20.5 million for the
third quarter of 2006 compared to $13.1 million recorded in the third quarter
of 2005. Included in the $20.5 million is $6.6 million, representing Western's
share of certain AOSP capital initiatives designed to enhance the performance
and reliability of the upstream operations which the Joint Venture determined
to have no future economic benefit. As such, these initiatives have been
expensed. The Project continues to explore and incur capital expenditures
related to production enhancements of both the upstream and downstream
operations. These activities will be prioritized such that high-impact,
high-value initiatives will be implemented first, with the focus primarily
directed to our downstream assets. Production enhancements will continue on an
ongoing basis with the goal of achieving 200,000 barrels per day (40,000
barrels net to Western) from the base operation. Higher production, which
increases the amount recorded for DD&A, was offset by a larger reserve base as
at December 31, 2005 used for the purposes of DD&A rates in fiscal 2006.
Foreign Exchange
During the third quarter of 2006, Western reported a foreign exchange loss of
$0.4 million compared to a gain of $28.1 million in the third quarter of 2005.
As reference points, the noon-day closing foreign exchange rate on September
29, 2006 was $0.8966 US/Cdn compared to $0.8969 US/Cdn on June 30, 2006 and
$0.8613 US/Cdn on September 30, 2005. The average rate for the third quarter of
2006 was $0.8921 US/Cdn compared to $0.8325 US/Cdn for the prior year period
and $0.8912 US/Cdn for the second quarter of 2006.
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 third quarter of 2006
were not impacted by risk management activities. Realizations in the third
quarter of 2005 were negatively impacted by $6.99 per barrel due to risk
management activities.
Three Months Ended September 30 Nine Months Ended September 30
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(Unaudited) 2006 2005 2006 2005
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Decrease in Revenue ($ thousands) - 27,821 - 85,418
Decrease in Revenue ($/bbl) - 6.99 - 7.67
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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 December 2009.
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 September 30, 2006, Western's risk management assets increased
significantly in value from the amount recorded as at June 30, 2006 resulting
in a mark-to-market gain of $33.3 million ($23.3 million net of tax) primarily
due to the significant retracement of WTI in the last few weeks of the third
quarter. This gain does not impact stated cash flow from operations in the
third quarter of 2006. At the end of the second quarter of 2006, the initial
amount recorded as a risk management asset had reverted to a liability mainly
due to the significant increase in WTI to that point. However, with the
retracement in WTI experienced in the third quarter of 2006, the risk
management asset has reverted back to an asset on the balance sheet. Gains and
losses on the risk management asset/liability are volatile as a result of a
high correlation to the underlying commodity upon which the hedging is designed
to mitigate. While Western expects these wide variations in mark-to-market
gains and losses to continue, it is important to note that the price of WTI has
remained within the collar established under the strategy. The current forward
curve of WTI during the duration of Western's risk management program would
also be within this collar. Consequently, should these forward prices of crude
oil materialize, the goal of Western's risk management program would be
achieved - namely, relatively minor premiums incurred to enhance cash flow
certainty during construction of the AOSP Expansion1. Western continues to
monitor the portfolio of financial instruments to determine if modifications
are necessary in light of higher capital costs for Expansion 1, together with
Western's in-situ development program on Western's leases as well as Chevron's
Ells River In-Situ Project.
Three Months Ended September 30 Nine Months Ended September 30
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(Unaudited) ($ thousands) 2006 2005 2006 2005
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Risk Management Asset (Liability) - Beginning of Period (13,776) - 98,426 -
Net Premium - 84,976 - 84,976
Increase (Decrease) in Fair Value 33,252 1,697 (78,950) 1,697
Risk Management Asset - End of Period 19,476 86,673 19,476 86,673
Less: Current Portion (1) 4,645 - 4,645 -
Risk Management Asset - Long-term Portion 14,831 86,673 14,831 86,673
===================================================================================================================
(1) Current portion represents the fair value of the risk management program
that expires within the next 12 months.
Income Taxes
For the third quarter of 2006, Western had an income tax expense of $35.5
million compared to $34.0 million for the same period last year. Included in
this expense is a future income tax expense of $35.5 million (2005 -
$33.4million) which reflects the increase in the future income tax liability
associated with expected tax depreciation claims and the reduction in the
future income tax assets associated with the Risk Management Activities.
Net Earnings
Western reported record net earnings of $84.5 million ($0.52 per share) in the
third quarter of 2006 compared to $79.4 million ($0.50 per share) in the third
quarter of 2005. Net earnings in the third quarter of 2006 include the impact
of an unrealized foreign exchange loss on both our US dollar denominated debt
and option premium liability together with a mark-to-market gain from risk
management activities. In the third quarter of 2006, there were net unrealized
foreign exchange and risk management gains of $33.1 million compared to an
unrealized gain of $31.9million in the third quarter of 2005. Excluding the
impact of unrealized foreign exchange and risk management gains, net earnings
were $61.3 million in the third quarter of 2006 compared to net earnings of
$53.2 million in the third quarter of 2005.
The following table provides the reconciliation between Net Earnings, Cash Flow
from Operations (before changes in non-cash working capital) and EBITDAX:
Reconciliation: Net Earnings (Loss) to EBITDAX Three Months Ended September 30 Nine Months Ended September 30
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($ thousands) 2006 2005 2006 2005
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Net Earnings Attributable to Common Shareholders 84,531 79,373 40,169 106,079
Add (Deduct):
Depreciation, Depletion and Amortization 20,470 13,119 37,836 36,654
Accretion on Asset Retirement Obligation 155 141 466 425
Stock-based Compensation 1,972 625 5,656 2,348
Interest Expense on Option Premium Liability 944 324 2,830 324
Unrealized Foreign Exchange (Gain) Loss 152 (30,206) (26,522) (20,306)
Unrealized (Gain) Loss on Risk Management (33,252) (1,697) 78,950 (1,697)
Future Income Tax Expense 35,528 33,371 197 50,651
Cash Settlement on Performance Share Units - - (2,104) (596)
Cash Settlement on Asset Retirement Obligation - (2) (91) (45)
Cash Flow From Operations, Before Changes
in Non-Cash Working Capital 110,500 95,048 137,387 173,837
Add:
Interest (excluding interest on Option Premium Liability) 12,638 13,262 36,313 44,008
Realized Foreign Exchange Loss 289 2,103 1,574 2,106
Large Corporations (Recovery) Tax 14 588 (127) 1,890
Cash Settlement on Performance Share Units - - 2,104 596
Cash Settlement on Asset Retirement Obligation - 2 91 45
EBITDAX 123,441 111,003 177,342 222,482
===================================================================================================================
EBITDAX (Earnings before Interest, Taxes, Depreciation, Depletion,
Amortization, Stock-based Compensation, Accretion on Asset Retirement
Obligation, Foreign Exchange and Risk Management) of $123.4 million was
recorded for the third quarter of 2006 compared to $111.0 million for the
comparable prior year period. This increase is due to improved Western
realizations associated with the continued strengthening of commodity prices
during the third quarter of 2006. Third quarter 2006 EBITDAX increased $131.6
million over the second quarter of 2006 as the majority of the turnaround
activities occurred during the second quarter significantly impacting
production and associated financial performance.
Cash flow from operations before changes in non-cash working capital
("cash flow from operations") was $110.5 million in the third quarter of 2006
compared to $95.0 million in the third quarter of 2005, establishing a new
record. Third quarter 2006 cash flows from operations represent a substantial
increase compared to the second quarter as operations returned to normal
performance with the culmination of the turnaround process.
FINANCIAL POSITION
Bank Debt
During the third quarter of 2006, Western increased its Revolving Credit
Facility by $14 million as a result of working capital commitments associated
with the turnaround and the ramp-up of capital for pre-FID expenditures.
Repayments to the Revolving Credit Facility were made during the last two
months of the quarter to bring the balance outstanding to $45 million. As
communicated in our second quarter report, the size of the Revolving Credit
Facility is a function of Western's share of the before tax present value
proved reserves associated with the Project. With the announcement of Western's
formal participation in Expansion 1, Western's proved reserves will
substantially increase. Western will be disclosing the economic value
associated with Expansion 1 reserves as part of its annual reporting process in
the first quarter of 2007. It is anticipated that increases to Western's
revolver would be undertaken with the existing banking syndicate commensurate
with this increased reserve value.
Capital Expenditures
Western's capital expenditures totaled $96.4 million in the third quarter of
2006 compared to $16.2 million for the comparable period in 2005. Capital
expenditures in the third quarter of 2006 included $9.4 million for base
operations, $6.6 million for sustaining capital, $45.4 million for expansion
related capital, and $35.0 million related to business development and
corporate expenditures. These business development expenditures relate to
Western's participation in the Chevron-operated Ells River in-situ project,
Western's in-situ lease acquisition activities and expenditures related to
Kurdistan.
Analysis of Cash Resources
Cash balances totaled $2.5 million at September 30, 2006 compared to $6.0
million at June 30, 2006. Cash inflows included: $110.5 million cash flow from
operations, $14 million increase in bank lines and $0.1 million from the
exercise of employee stock options. Cash outflows included $96.4 million of
capital expenditures, a $31.4 million increase in non-cash working capital and
$0.3 million in repayment of obligations under capital lease and deferred
charges.
Higher non-cash working capital during the third quarter of 2006 was the
result of a $49.6 million increase in accounts receivable offset by a $12.8
million increase in accounts payable, a $2.3 million decrease in inventory and
a $3.1 million decrease in prepaid expenses. The increase in receivable is
predominantly due to the return to normal operations and sales activities
following the turnaround. The increase in accounts payable reflects five months
of accrued interest on Western's long-term notes at September 30, 2006 compared
to two months accrued at June 30, 2006. The composition of the payable balance
has changed compared to the second quarter of 2006 where the majority of
expenditures were turnaround related compared to the third quarter which were
operational in nature.
Insurance Claims
There were no new developments during the third 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. Amounts owing under all
Western's insurance claims total $244 million as of September 30, 2006.
Flow-Through Shares
During the third quarter of 2006, it was communicated to Western that the
Canada Revenue Agency ("CRA") proposes to challenge the characterization of
certain expenditures capitalized as Canadian Exploration Expense ("CEE") and
which were incurred in 2001 and 2002. Western has yet to be formally reassessed
and continues to work with its Joint Venture Participants to seek resolution of
this potential challenge. If the CRA is successful in assessing a change in the
characterization of these expenditures, the resulting reduction would impact
Western's obligations under the indemnity provisions in the subscription
agreements for the flow-through shares and, in turn, would impact Western's
reported results. Western renounced CEE to certain of its shareholders in the
aggregate amount of $29.2 million in 2001 and $19.5 million in 2002.
UNDEVELOPED LAND
Western recently purchased leases 442 and 472 in the Athabasca region which
have the potential for in-situ development. With these lease acquisitions, and
including lease 353 which Western purchased in 2005, the Company's in-situ land
position has grown to over 21,000 gross acres. Early stage planning for these
in-situ leases is underway and will include an evaluation drilling program this
winter. There are no reserves or resources estimates currently associated with
Western's in-situ lands. The other Joint Venture Owners have the right to
participate in these newly acquired Western leases.
RESERVES AND RESOURCES
With Board approval of the AOSP Expansion 1, Western reported updated oil sands
reserve estimates using reserve definitions in accordance with National
Instrument 51-101. Western's qualified independent evaluator, GLJ Petroleum
Consultants ("GLJ"), has initially estimated that Western's working interest or
company gross proved plus probable reserves from AOSP Expansion 1 are
approximately 252 million barrels of synthetic crude oil. This represents an
increase of more than 80 per cent over the reserve position assigned to the
Muskeg River Mine by GLJ as at December 31, 2005 and reported in Western's
Annual Information Form, bringing the total estimated proved and probable
reserves to over 554 million barrels net of production as at the end of October
2006. Upon regulatory approval of the Muskeg River Mine expansion, GLJ will
also reclassify 84 million barrels of probable reserves net to Western to
proved reserves. As a result of this reclassification, total proved reserves
will represent 483 million barrels or over 87 per cent of the total estimated
554 million barrels of proved and probable reserves.
Over the next five years, Western and the other Joint Venture Owners have
an active 2,500 core hole drilling program planned to further define the
mineable resource and reserve potential on the AOSP's existing and new leases.
Western believes there are sufficient bitumen resources in place to support
multiple expansions beyond the three planned expansions at the AOSP. As new
data becomes available following each drilling season and an evaluation process
is completed, Western will continue to update its reserve and resource
estimates. To enhance its resource disclosure, Western anticipates disclosing
contingent resources as part of its annual filing obligations.
KURDISTAN UPDATE
Western, through its wholly-owned subsidiary, WesternZagros, continues to make
measured progress in ratifying the Exploration and Production Sharing Agreement
("EPSA") signed with the Kurdistan Regional Government in May of this year.
Seismic operations have been initiated and are expected to continue into 2007
in order to determine the initial exploration well locations.
WesternZagros is also moving steadily towards implementing the necessary
reporting, treasury and internal controls systems to support and ensure the
smooth conduct of operations in Kurdistan. Internationally experienced advisors
have been consulted in this process to assist Western in its efforts.
WesternZagros is also augmenting its oil and gas group, both in-country and
domestically, to ensure all areas of the operation are appropriately staffed.
Western recently filled the key position of Senior Drilling Manager for
Kurdistan with the addition of Mr. Matthew Swartout. Mr. Swartout has a great
depth of experience in Middle Eastern drilling operations and he will be a
valued addition to the team dedicated to our Kurdistan initiative.
OUTLOOK
With the first major turnaround now behind us, Western is anticipating
production to return to the record levels achieved during the second half of
2005. Western is maintaining its forecasted 2006 annual production target of
26,000 to 27,000 barrels per day.
Our formal commitment to participate to our 20 per cent interest in
Expansion 1 of the AOSP marks another significant milestone for Western. It
further demonstrates our commitment to our continuous construction expansion
strategy and reinforces our mandate to create value through the development of
large, long-life hydrocarbon resources. As previously communicated, Western
completed a preliminary analysis of the undeveloped lands that we have the
right to participate in within the Athabasca region, including both mining and
in-situ lands. Based on this analysis, Western believes there are sufficient
bitumen resources in place to support multiple expansions beyond the three
planned expansions of the AOSP. Given the resource potential on the leases
acquired by all Joint Venture Owners, including those in-situ leases recently
purchased by Western, our production could grow to the 150,000 to 200,000
barrel per day range.
Downstream integration is a key component of Western's growth strategy.
Beyond Expansion 1, Western is independently evaluating alternative downstream
solutions with the goal of improving product yields and sales price
realizations while reducing capital intensity. To capitalize on this
opportunity and meet these goals, Western is committed to a long-term strategy
involving commercially attractive, cost-effective, downstream integration for
upgrading bitumen into light synthetic crude oil products for both its future
mining and in-situ volumes. Given that volumes from future AOSP Expansions,
together with in-situ volumes from both Western and Chevron operated
properties, are not expected to come on stream until 2012, Western believes it
has ample time to secure the appropriate solution and act in the best interests
of its shareholders.
In the next several weeks, we anticipate communicating our formal 2007
capital expenditure guidance. In addition, pending Board approval, Western
plans to implement a comprehensive financial plan over the course of the next
year to provide the platform by which we will meet our financial commitments on
both Expansion 1 and Western's share of the in-situ development program. Should
commodity prices maintain the levels experienced over the last few quarters,
Western anticipates that a noteworthy portion of our total capital expenditures
would be financed through internally generated cash flow.
Business Risks
Western is subject to a number of business 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, which are available on
the Company's website.
Non-GAAP Financial 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.
CONSOLIDATED BALANCE SHEETS
As at September 30 As at December 31
(Unaudited) ($ thousands) 2006 2005
- -----------------------------------------------------------------------------------------------------------
Assets
Current Assets
Cash 2,512 5,590
Accounts Receivable 89,356 87,398
Inventory 23,457 21,083
Prepaid Expense 3,392 9,355
Current Portion of Risk Management (note 11) 4,645 -
123,362 123,426
Property, Plant and Equipment (note 1) 1,505,649 1,352,605
Risk Management (note 11) 14,831 98,426
Deferred Charges 14,143 16,063
1,534,623 1,467,094
1,657,985 1,590,520
===========================================================================================================
Liabilities
Current Liabilities
Accounts Payable and Accrued Liabilities 141,110 101,303
Current Portion of Lease Obligations (note 3) 2,278 3,396
Current Portion of Option Premium Liability (note 4) 17,774 -
161,162 104,699
Long-term Liabilities
Long-term Debt (note 2) 546,885 565,655
Lease Obligations (note 3) 57,320 55,809
Option Premium Liability (note 4) 66,720 85,416
Asset Retirement Obligation (note 5) 9,469 9,094
Future Income Tax (note 10) 56,642 56,445
737,036 772,419
898,198 877,118
Shareholders' Equity
Share Capital (note 7) 551,825 548,747
Contributed Surplus (note 9) 6,612 3,474
Retained Earnings 201,350 161,181
759,787 713,402
1,657,985 1,590,520
===========================================================================================================
Subsequent Event (note 13)
See Accompanying Notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
Three Months Ended September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
(Unaudited) ($ thousands, except amounts per share) 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Revenues (note 11) 322,175 275,191 695,662 685,541
Less Purchased Feedstocks and Transportation 115,928 89,502 254,534 259,942
206,247 185,689 441,128 425,599
Expenses
Operating 66,453 64,810 219,870 179,300
Research and Business Development 8,294 3,859 22,036 7,994
Royalties 1,536 1,407 2,894 2,954
General and Administrative 3,905 2,725 11,007 7,204
Insurance 2,618 1,885 7,979 5,665
Interest (note 6) 13,582 13,586 39,143 44,332
Stock-based Compensation (note 9) 1,972 625 5,656 2,348
Accretion on Asset Retirement Obligation (note 5) 155 141 466 425
Depreciation, Depletion and Amortization (note 1) 20,470 13,119 37,836 36,654
118,985 102,157 346,887 286,876
Earnings Before Other (Income) Expense and Income Taxes 87,262 83,532 94,241 138,723
Other (Income) Expense
Foreign Exchange (Gain) Loss 441 (28,103) (24,948) (18,200)
Unrealized (Gain) Loss on Risk Management (note 11) (33,252) (1,697) 78,950 (1,697)
Earnings Before Income Taxes 120,073 113,332 40,239 158,620
Income Tax Expense (note 10) 35,542 33,959 70 52,541
Net Earnings 84,531 79,373 40,169 106,079
Retained Earnings at Beginning of Period 116,819 38,438 161,181 11,732
Retained Earnings at End of Period 201,350 117,811 201,350 117,811
===================================================================================================================
Net Earnings Per Share (note 8)
Basic 0.52 0.50 0.25 0.66
Diluted 0.52 0.49 0.25 0.65
See Accompanying Notes to the Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
(Unaudited) ($ thousands) 2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Cash Provided by (Used In)
Cash From Operating Activities
Net Earnings 84,531 79,373 40,169 106,079
Non-cash Items
Stock-based Compensation (note 9) 1,972 625 5,656 2,348
Accretion on Asset Retirement Obligation (note 5) 155 141 466 425
Depreciation, Depletion and Amortization (note 1) 20,470 13,119 37,836 36,654
Interest Expense on Option Premium Liability (note 4) 944 324 2,830 324
Unrealized (Gain) Loss on Risk Management (note 11) (33,252) (1,697) 78,950 (1,697)
Unrealized Foreign Exchange (Gain) Loss (note 2 and 4) 152 (30,206) (26,522) (20,306)
Future Income Tax Expense (note 10) 35,528 33,371 197 50,651
Cash Items
Cash Settlement of Asset Retirement Obligation (note 5) - (2) (91) (45)
Cash Settlement of Performance Share Unit Plan (note 9) - - (2,104) (596)
110,500 95,048 137,387 173,837
(Increase) Decrease in Non-cash Working Capital (note 12) (39,863) 25,355 (9,425) (18,033)
70,637 120,403 127,962 155,804
Cash From (Used In) Financing Activities
Issue of Share Capital (note 7) 83 1,142 2,664 2,187
Issue (Repayment) of Long-term Debt, Net 14,000 (129,000) 4,000 (141,000)
Repayment of Obligations Under Capital Lease (334) (336) (1,006) (1,006)
13,749 (128,194) 5,658 (139,819)
Cash Invested
Capital Expenditures (96,402) (16,164) (187,561) (43,026)
Insurance Proceeds - 204 - 22,412
Decrease in Non-cash Working Capital (note 12) 8,490 24,488 50,863 6,054
(87,912) 8,528 (136,698) (14,560)
(Decrease) Increase in Cash (3,526) 737 (3,078) 1,425
Cash at Beginning of Period 6,038 4,403 5,590 3,715
Cash at End of Period 2,512 5,140 2,512 5,140
===================================================================================================================
See Accompanying Notes to the Consolidated Financial Statements
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 and the Property, Plant and Equipment
accounting policy provided in the consolidated financial statements for the
three and six month period ended June 30, 2006. 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. PROPERTY, PLANT AND EQUIPMENT
September 30, 2006 Cost Accum. DD&A* Net
- ---------------------------------------------------------------------------------------
Athabasca Oil Sands Project
Producing Assets 1,405,045 (139,529) 1,265,516
Capital Leases 52,705 (5,388) 47,317
Expansions 132,759 - 132,759
1,590,509 (144,917) 1,445,592
In Situ Projects 29,466 - 29,466
Kurdistan Exploration Project 18,316 - 18,316
Corporate and Other 13,939 (1,664) 12,275
1,652,230 (146,581) 1,505,649
=======================================================================================
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
In Situ Projects 797 - 797
Kurdistan Exploration Project 8,962 - 8,962
Corporate and Other 12,136 (1,362) 10,774
1,463,271 (110,666) 1,352,605
=======================================================================================
* Accumulated Depreciation, Depletion and Amortization
At September 30, 2006, the Producing Assets in the Athabasca Oil Sands Project
("AOSP") include asset retirement costs, net of amortization of $7.0 million
($7.2 million - 2005). Costs not currently subject to depreciation, depletion
and amortization include $132.8 million relating to the AOSP and $1.4 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 and the In Situ Projects are excluded from depletion as they represent
costs related to properties incurred in cost centres that are considered to be
in the pre-production stage. Currently, there are no proved reserves in these
cost centres. All costs, net of any associated revenues, in these cost centres
have been capitalized.
During the three month period ended September 30, 2006, assets included in AOSP
Producing Assets with a carrying value of $6.6 million were determined to be
impaired. The capital projects associated with these assets have been cancelled
and consequently the assets have no future economic benefit. Accordingly, the
Corporation has determined the carrying value of these projects to be nil and
has recognized, in Depreciation, Depletion and Amortization, an impairment of
$6.6 million.
2. LONG-TERM DEBT
September 30, December 31,
2006 2005
- --------------------------------------------------------------------------------
US $450 million Senior Secured Notes 501,885 524,655
Revolving Credit Facility 45,000 41,000
546,885 565,655
- -===============================================================================
The Corporation's US dollar denominated Senior Secured Notes (the "Notes") are
translated into Canadian dollars at the period end exchange rate. For the three
month period ended September 30, 2006, the unrealized foreign exchange loss
arising on the Notes was $0.1 million (September 30, 2005 - $29.0 million
unrealized foreign exchange gain). For the nine month period ended September
30, 2006, the unrealized foreign exchange gain arising on the Notes was $22.8
million (September 30, 2005 - $19.1 million unrealized foreign exchange gain).
As at September 30, 2006, a total of $207.0 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.
3. LEASE OBLIGATIONS
September 30, December 31,
2006 2005
- --------------------------------------------------------------------------------
Obligations Under Capital Lease 49,262 50,266
Operating Lease Guarantee Obligation 10,336 8,939
59,598 59,205
Less: Current Portion 2,278 - 3,396
57,320 55,809
================================================================================
The Obligations Under Capital Lease 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.
The Operating Lease Guarantee Obligation relates to the Mobile Equipment
leases. 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 leases. 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 nine month period ended
September 30, 2006, the Corporation paid nil and $0.6 million, respectively, in
regard to this obligation (September 30, 2005 - nil and $1.5 million,
respectively).
4. OPTION PREMIUM LIABILITY
The Corporation deferred payment and receipt of the premiums associated with
the options described in Note 11(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 into, 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%.
Interest expense recognized for the three and nine month periods ended
September 30, 2006 was $0.9 million and $2.8 million, respectively (September
30, 2005 - $0.3 million). 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 loss arising on the option premium
liability for the three month period ended September 30, 2006 was $0.02 million
(September30, 2005 - $1.2 million unrealized foreign exchange gain). The
unrealized foreign exchange gain arising on the option premium liability for
the nine month period ended September 30, 2006 was $3.8 million, respectively
(September30, 2005 - $1.2 million unrealized foreign exchange gain).
The following table presents the reconciliation of the net Option Premium
Liability:
Three Months Ended September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Option Premium Liability at Beginning of Period 83,533 - 85,416 -
Net Premiums - 84,976 - 84,976
Interest Expense 944 324 2,830 324
Unrealized Foreign Exchange (Gain) Loss 17 (1,181) (3,752) (1,181)
Option Premium Liability at End of Period 84,494 84,119 84,494 84,119
Less: Current Portion 17,774 - 17,774 -
66,720 84,119 66,720 84,119
===================================================================================================================
5. 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 September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Asset Retirement Obligation at Beginning of Period 9,314 8,432 9,094 8,191
Liabilities Settled - (2) (91) (45)
Accretion on Asset Retirement Obligation 155 141 466 425
Asset Retirement Obligation at End of Period 9,469 8,571 9,469 8,571
===================================================================================================================
6. INTEREST EXPENSE
Three Months Ended September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Interest on Long-term Debt 11,921 12,619 34,140 42,175
Interest on Obligations Under Capital Lease 717 643 2,173 1,833
Interest on Option Premium Liability 944 324 2,830 324
13,582 13,586 39,143 44,332
===================================================================================================================
Cash interest paid for the three and nine month periods ended September 30,
2006 was $1.5 million and $25.6million, respectively (September 30, 2005 - $1.7
million and $33.2 million, respectively). Cash interest received for the three
and nine month periods ended September 30, 2006 was $0.1 million and $0.2
million, respectively (September 30, 2005 - nil and $0.1 million,
respectively).
7. SHARE CAPITAL
Issued and Outstanding
Number of
Shares Amount
- -----------------------------------------------------------------------------------------------
Common Shares
Balance at December 31, 2005 160,518,041 548,747
Issued for Cash 571,608 2,664
Exercise of Stock Options Previously Recognized - 414
Total Share Capital at September 30, 2006 161,089,649 551,825
===============================================================================================
Outstanding
Stock Options 3,855,014
===============================================================================================
Diluted Shares at September 30, 2006 164,944,663
===============================================================================================
8. NET EARNINGS PER SHARE
Basic weighted average number of common shares for the three and nine month
periods ended September 30, 2006 are 161,084,823 and 160,928,037, respectively
(September 30, 2005 - 160,229,593 and 160,103,854, respectively). Diluted
weighted average number of shares for the three and nine month periods ended
September 30, 2006 are 162,923,641 and 163,496,679, respectively (September 30,
2005 - 162,479,152 and 162,398,905, respectively).
9. STOCK-BASED COMPENSATION
(a) Stock Option Plan
Under the Corporation's stock-based compensation plan, 102,000 options were
granted during the three month period ended September 30, 2006 at an average
exercise price of $26.80 per share (September 30, 2005 - 30,000 options at an
average exercise price of $27.75 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 September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------
Granted 102,000 30,000 899,540 383,670
Weighted-average Fair Value $11.92 $12.60 $15.52 $7.60
Risk Free Interest Rate 4.12% 3.72% 4.24% 3.86%
Expected Life (in Years) 6.00 6.00 6.00 6.00
Expected Volatility 34% 41% 33-43% 26-41%
Dividend Per Share - - - -
=================================================================================================
(b) Performance Share Unit Plan ("PSUP")
The following table presents the reconciliation of the number of Performance
Share Units:
Three Months Ended September 30 Nine Months Ended September 30
- ----------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- ----------------------------------------------------------------------------------------------------------
Outstanding at Beginning of Period 230,052 180,078 160,128 99,291
Granted 16,335 - 149,530 113,880
Exercised - - (63,111) (33,093)
Cancelled (858) (8,904) (1,018) (8,904)
Outstanding at End of Period 245,529 171,174 245,529 171,174
==========================================================================================================
(c) Deferred Share Unit Plan
Under the Deferred Share Unit Plan ("DSUP"), for the three and nine month
periods ended September 30, 2006, $0.04 million and $0.2 million (September 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 nine month periods ended
September 30, 2006 and 2005. The Corporation had 25,299 DSUs outstanding at
September 30, 2006 (September 30, 2005 - nil). As at September 30, 2006, the
Corporation had $0.3 million recorded in Accounts Payable and Accrued
Liabilities associated with the DSUP.
(d) Stock-based Compensation
For the three and nine month periods ended September 30, 2006, the Corporation
recognized $2.0 million and $5.7 million, respectively, (September 30, 2005 -
$0.6 million and $2.3 million) in compensation expense related to stock-based
compensation issued subsequent to January 1, 2003. For the three month period
ended September30, 2006, the compensation expense is comprised of $1.3 million
(September 30, 2005 - $0.4 million) in respect to the Corporation's stock
option plan and $0.7 million (September 30, 2005 - $0.2 million) in respect to
the Corporation's Performance Share Unit Plan. For the nine month period ended
September 30, 2006, the compensation expense is comprised of $3.3 million
(September 30, 2005 - $0.9 million) in respect to the Corporation's stock
option plan and $2.4 million (September 30, 2005 - $1.4 million) in respect to
the Corporation's Performance Share Unit Plan.
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 September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Net Earnings - As Reported 84,531 79,373 40,169 106,079
Compensation Expense 24 225 183 667
Net Earnings - Pro Forma 84,507 79,148 39,986 105,412
===================================================================================================================
Basic Earnings Per Share
As Reported 0.52 0.50 0.25 0.66
Pro Forma 0.52 0.49 0.25 0.66
Diluted Earnings Per Share
As Reported 0.52 0.49 0.25 0.65
Pro Forma 0.52 0.49 0.25 0.65
===================================================================================================================
(e) Contributed Surplus
The following table presents the reconciliation of Contributed Surplus:
Three Months Ended September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Contributed Surplus at Beginning of Period 4,640 2,372 3,474 1,245
Stock-based Compensation Expense 1,972 625 5,656 2,348
Cash Settlement of Performance Share Unit Plan - - (2,104) (596)
Exercise of Stock Options Previously Recognized - - (414) -
Contributed Surplus at End of Period 6,612 2,997 6,612 2,997
===================================================================================================================
10. INCOME TAX
Three Months Ended September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Current Income Tax (Recovery) Expense 14 588 (127) 1,890
Future Income Tax Expense 35,528 33,371 197 50,651
Income Tax Expense 35,542 33,959 70 52,541
===================================================================================================================
The future income tax liability consists of:
September 30, December 31,
2006 2005
- ----------------------------------------------------------------------------------------------------------------
Future Income Tax Assets
Unrealized Loss on Risk Management 20,006 -
Net Losses Carried Forward 3,931 4,707
Impairment of Long-lived Assets 686 796
Share Issue Costs 620 973
Future Income Tax Liabilities
Capital Assets in Excess of Tax Values (61,974) (39,924)
Unrealized Foreign Exchange Gain (16,661) (15,500)
Debt Issue Costs (3,250) (3,123)
Unrealized Gain on Risk Management - (4,374)
Net Future Income Tax Liability (56,642) (56,445)
================================================================================================================
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 September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Net Earnings Before Income Taxes 120,073 113,332 40,239 158,620
Income Tax Expense at Statutory Rate 41,425 42,635 13,882 59,672
Effect of Tax Rate Changes and Timing of Use (6,186) 313 (10,527) 1,349
Non-taxable Portion of Foreign Exchange (Gain) Loss 40 (6,040) (4,541) (3,980)
Non-deductible Expenses - - 326 -
Resource Allowance 98 (3,772) 101 (7,814)
Stock-based Compensation 653 235 1,226 660
Provision to Actual (502) - (270) 764
Large Corporations Tax (Recovery) Expense 14 588 (127) 1,890
Income Tax Expense 35,542 33,959 70 52,541
===================================================================================================================
11. 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 oil swap positions in place during the three and nine month
periods ended September 30, 2006 as the crude oil swaps were settled in 2005.
For the three and nine month periods ended September 30, 2005, the
Corporation's revenues were reduced by $27.8 million and $85.4 million,
respectively, from crude oil price hedging losses.
(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$92.41 per barrel for the three
year period beginning January 1, 2007, resulting in a net premium liability.
Payment of the net premium liability is deferred until the settlement of the
option contracts between 2007 and 2009.
As at September 30, 2006, the Corporation had outstanding the following
put and call options:
2007 2008 2009
- -----------------------------------------------------------------------------------------------------------
Barrels Per Day
Put Options Purchased 20,000 20,000 20,000
Call Options Sold 10,000 15,000 15,000
US$ 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 month
period ended September 30, 2006, the Corporation recognized an unrealized gain
of $33.3 million (September 30, 2005 - $1.7 million unrealized gain) and for
the nine month period ended September 30, 2006, the Corporation recognized an
unrealized loss of $79.0 million (September 30, 2005 - $1.7 million unrealized
gain) on the Risk Management Asset (Liability), marking it to 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 September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Risk Management Asset (Liability) at Beginning of Period (13,776) - 98,426 -
Net Premium - 84,976 - 84,976
Unrealized Gain (Loss) on Risk Management 33,252 1,697 (78,950) 1,697
Risk Management Asset at End of Period 19,476 86,673 19,476 86,673
Less: Current Portion 4,645 - 4,645 -
14,831 86,673 14,831 86,673
===================================================================================================================
12. CHANGES IN NON-CASH WORKING CAPITAL
Three Months Ended September 30 Nine Months Ended September 30
- -------------------------------------------------------------------------------------------------------------------
2006 2005 2006 2005
- -------------------------------------------------------------------------------------------------------------------
Source/(Use)
Operating Activities
Accounts Receivable (49,618) 5,336 (1,958) (21,379)
Inventory 2,306 (2,810) (2,374) (11,581)
Prepaid Expense 3,156 4,134 5,963 1,278
Accounts Payable and Accrued Liabilities 4,293 18,695 (11,056) 13,649
(39,863) 25,355 (9,425) (18,033)
===================================================================================================================
Investing Activities
Accounts Receivable - 19,380 - -
Accounts Payable and Accrued Liabilities 8,490 5,108 50,863 6,054
8,490 24,488 50,863 6,054
===================================================================================================================
13. SUBSEQUENT EVENT
On October 25, 2006, the Corporation announced that its Board of Directors
approved its participation, to its proportionate interest, in Expansion 1 of
the AOSP. Expansion 1 is a 100,000 barrel per day fully integrated expansion of
the existing AOSP facilities, with new oil sands mining operations on Lease 13
and associated bitumen upgrading at the Scotford Upgrader. It also includes the
construction of common upstream infrastructure that will be sized to support
further mine expansions.
CORPORATE INFORMATION
OFFICERS
James C. Houck
President and Chief Executive Officer
Steve D. L. Reynish
Executive Vice President and
Chief Operating Officer
David A. Dyck
Senior Vice President, Finance and
Chief Financial Officer
Charles W. Berard
Corporate Secretary
SENIOR MANAGEMENT
John Frangos
President, Western Oil Development Inc.
M. Simon Hatfield
Vice President and Managing Director,
Oil & Gas
Jack D. Jenkins
Vice President, Corporate Planning
& Human Resources
Gerry Luft
Vice President, Downstream
Ray Morley
Vice President, Business Development
Graig Ritchie
Vice President, Oil Sands
DIRECTORS
Guy J. Turcotte
Chairman of the Board,
Western Oil Sands Inc.
Calgary, Alberta
Geoffrey A. Cumming
Lead Director
Vice Chairman,
Gardiner Group Capital Limited
Toronto, Ontario
Deputy Chairman,
Emerald Capital Limited
Auckland, New Zealand
David J. Boone
President and Director,
Escavar Energy
Calgary, Alberta
James C. Houck
President and Chief Executive Officer,
Western Oil Sands Inc.
Calgary, Alberta
Oyvind Hushovd
Corporate Director
Kristiansand, Norway
John W. Lill
Executive Vice President and
Chief Operating Officer,
Dynatec Corporation
Richmond Hill, Ontario
Randall Oliphant
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
HEAD OFFICE
Suite 2400, Ernst & Young Tower
440 - 2nd Avenue S.W.
Calgary, Alberta T2P 5E9
Phone: (403) 233-1700
Fax: (403) 234-9156
WEBSITE
www.westernoilsands.com
AUDITORS
PricewaterhouseCoopers LLP
Calgary, Alberta
LEGAL COUNSEL
Macleod Dixon LLP
Calgary, Alberta
Paul, Weiss, Rifkind, Wharton
& Garrison LLP
New York, N.Y., USA
INDEPENDENT EVALUATORS
GLJ Petroleum Consultants Ltd.
Calgary, Alberta
Norwest Corporation
Calgary, Alberta
REGISTRAR AND
TRANSFER AGENT
Valiant Trust Company
Calgary, Alberta
STOCK EXCHANGE LISTING
The Toronto Stock Exchange
Trading Symbol:WTO