EXHIBIT 3
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MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion of financial condition and results of operations was
prepared as of February 22, 2007 and should be read in conjunction with the
Consolidated Financial Statements and Notes thereto. It offers Management's
analysis of the financial and operating results of Western Oil Sands Inc.
("Western") 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 Athabasca Oil Sands Project
("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, uncertainty in the estimation of
stock-based compensation and employee future benefits 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, 2006 which is available on SEDAR at www.sedar.com.
OVERVIEW
Western Oil Sands Inc. ("Western") is a Canadian corporation whose vision is to
create shareholder value through the opportunity capture and development of
large, world-class hydrocarbon resources. Western's primary asset is its 20 per
cent undivided interest in the Athabasca Oil Sands Project ("AOSP"). Shell
Canada Limited ("Shell") and Chevron Canada Limited ("Chevron") are the other
Joint Venture Owners, holding a 60 per cent and 20 per cent interest,
respectively. The Joint Venture's strategy is to exploit the mining and in-situ
recoverable bitumen reserves and resources found in oil sands deposits located
in the Athabasca region of Alberta. The initial Joint Venture asset is a mining
and extraction operation (the Muskeg River Mine) on the west side of Lease 13,
70 kilometres north of Fort McMurray, together with associated upgrading
infrastructure (the Scotford Upgrader) northeast of Edmonton, Alberta. Current
operations, with the assistance of certain third-party facilities, including a
493 kilometre pipeline connecting the Mine and the Upgrader, use established
processes to mine oil sands deposits, extract and upgrade the bitumen into two
streams of synthetic crude oil, namely Premium Albian Synthetic ("PAS") and
Albian Heavy Synthetic ("AHS"), and vacuum gas oil ("VGO"). VGO is sold to
Shell under a long-term contract for use in its adjacent refinery. In the
second quarter of 2006, the first full plant turnaround was successfully
executed. Following the turnaround, production levels returned to the record
levels established during the last quarter of 2005. Production optimization
initiatives are planned to continue on the base Project, with the objective of
achieving production volumes of approximately 200,000 barrels per day (40,000
barrels per day net to Western) by 2009. In terms of the base Project,
reliability and availability of the existing AOSP facilities will continue to
be a key focus for the Joint Venture.
During 2006 and in years prior, Western and the other Joint Venture
Owners devoted considerable time, effort and commitment of capital in planning
and completing the early stage execution of Expansion 1 of the AOSP. This work
culminated in Western, and the Joint Venture Owners, sanctioning Expansion 1 in
the fourth quarter of 2006. Expansion 1 is a 100,000 barrel per day (20,000
barrels net to Western) fully integrated expansion of the existing AOSP
facilities, with new oil sands mining operations on Lease 13 and associated
additional bitumen upgrading at the Scotford Upgrader. It also includes the
construction of common upstream infrastructure that will be sized to support
future mining expansions, consistent with the recent announcements from the
Joint Venture that regulatory applications will be filed to seek approval to
produce up to 770,000 barrels per day from Expansions3 through5. Construction
of a new 42-inch Corridor Pipeline connecting Fort McMurray to Edmonton also
began in 2006. This new pipeline will facilitate the movement of up to
1,000,000 barrels per day of production when fully complete.
Also during 2006, Western made noteworthy progress with respect to its
in-situ development initiative which represents an exciting new opportunity for
Western to create additional shareholder value. It is estimated that 80 per
cent of the bitumen resources in Alberta are in-situ in nature and currently
too deep to mine through surface mining techniques. In August 2006, Western
announced its decision to participate to its 20 per cent interest in the
Chevron-operated Ells River Project in the Athabasca region which has potential
for in-situ development. The Ells River Project is located on approximately
75,000 gross acres of property purchased by Chevron in 2005 and 2006. Chevron
has assembled a technical team that is dedicated to feasibility and other
technical evaluations going forward. Chevron has planned a significant core
hole evaluation drilling program over the winter of 2007 to assess the
potential of these leases. In addition, Western expanded its acreage position
in the Athabasca region and will operate its own in-situ project which covers
approximately 21,000 gross acres, approximately 14,000 acres net to Western.
Early stage planning for Western's in-situ leases is underway and this includes
a core hole evaluation drilling program of approximately 19 wells during the
2007 winter drilling season.
Western announced during 2006 that it is independently evaluating
alternative downstream solutions beyond Western's involvement in the fully
integrated operation of AOSP Expansion 1, with the goal of improving product
yields and sales price realizations at a lower capital intensity than current
configurations. To meet these goals, Western is committed to a long-term
strategy which involves commercially-attractive, cost-effective, downstream
integration for upgrading bitumen into light synthetic crude oil products
anticipated to be produced from Western's extensive and emerging mining and
in-situ resources.
In addition to these key initiatives, Western, through its wholly-owned
subsidiary, WesternZagros Limited ("WesternZagros"), negotiated the initial
form of an Exploration and Production Sharing Agreement ("EPSA") with the
Kurdistan Regional Government ("), subject to finalization of key terms and
ratification by the KRGto comply with expected federal legislation. The EPSA
provided for the exploration of conventional oil and gas in the Federal Region
of Kurdistan in northern Iraq. WesternZagros continues to work towards
ratification of an EPSA with the KRG which is expected to include the
finalization of terms including its contract area and the corresponding work
program commitments.
Commodity prices continued to hover at or near record levels during most
of 2006 and, consequently, Western achieved near-record cash flow, despite the
56-day turnaround in the second quarter of 2006. As a result, Western's
financial position has substantially improved as it embarks on Expansion 1 of
the AOSP. Noteworthy operating and financial achievements during 2006 include:
o Fourth quarter production averaged 35,515 barrels per day net to
Western, comparable to the record production of 35,600 barrels per day achieved
in the fourth quarter of 2005;
o Annual production averaged 27,500 barrels per day net to Western,
despite the two-month production interruption due to the full turnaround at the
Mine and Upgrader in the second quarter;
o Near-record annual cash flow from operations of $228.4 million, with
record quarterly cash flow from operations of $110.5million in the third
quarter;
o Capital expenditures of $301.3 million which were funded primarily
through cash flow from operations supplemented by a modest increase in
Western's Revolving Credit Facility;
o Proved and probable reserves increased 86 per cent from the prior year
to 577 million barrels and a best estimate of contingent resources of 891
million barrels;
o The lands associated with Western's proved and probable reserves
represent only approximately 11 per cent of the more than 69,000 net acres in
which Western has the right to participate;
o The permit application for the Muskeg River Mine expansion was approved
in December 2006;
o Environmentally, the Muskeg River Mine remains the only oil sands
mining operating to have achieved the internationally recognized ISO 14001
certification; and
o Over 12 million plus exposure hours recorded in 2006 within the AOSP
resulted in only a relatively minor lost time incident and the recordable
injury frequency rate improved significantly following the turnaround.
EXPANSION 1
During the fourth quarter of 2006, Western, along with the other Joint Venture
Owners, announced its approval of Expansion 1 of the AOSP. Expansion 1 is a
100,000 barrel per day (20,000 barrels per day net to Western) fully integrated
expansion of the existing AOSP facilities, with new oil sands mining operations
on the east side of Lease 13, an expansion of the extraction facilities at the
Muskeg River Mine and an expansion of the existing Upgrader located near
Edmonton. The capital cost estimate for Expansion 1 is approximately $11.2
billion ($2.2billion net to Western). Of the $11.2 billion estimate,
approximately 75 per cent is allocated for the actual costs of components and
construction labour, 20 per cent represents owners' costs and contingencies,
with the remaining five per cent representing the conversion of the total
capital cost to money-of-the-day prices. Mine production is scheduled to begin
in late 2009 with Upgrader production beginning in late 2010.
As at the end of December 2006, expenditures of $225.6 million related to
Expansion 1 were capitalized on Western's balance sheet. In order to proceed
with its planned schedule, the Project committed to major long lead time
equipment and also incurred other pre-construction expenditures in 2006.
Western has budgeted capital expenditures of $555 million for its share of
Expansion 1 for 2007. For Expansion 1, construction efforts to date have
focused on utilities work relating to the construction of permanent camp
facilities, piling and foundation activities for many of the key components
including the primary separation cell and de-aerator area and construction of
potable water and sewage treatment plants. One of the key cost saving
strategies in the construction of the facilities is the fabrication of many
modules off-site. Efforts in this regard are proceeding as planned with over
600 modules earmarked for such construction. To date, the Project has secured
the necessary skilled labour required for an operation of this nature.
Approximately 2,000 full-time equivalent individuals, representing a
combination of construction contractors and employees of the engineering,
procurement and construction management contractors, are currently working on
this major initiative on behalf of the Joint Venture. This workforce is
expected to increase substantially as the Project moves into full construction
over the next several years.
RESERVES, RESOURCES AND LAND
Under the terms of the Joint Venture Agreement for the AOSP, Western and the
other Joint Venture Owners have in place a Participation and Area of Mutual
Interest Agreement ("AMI"). The AMI stipulates that the Joint Venture Owners
have rights to participate in any additional leases that are acquired by any
one of the Owners in the Athabasca region.
Within the Project, Western has the following: proved and probable
reserves which are associated with the existing operations at the Muskeg River
Mine; proved and probable reserves associated with Expansion 1 of the AOSP;
resources on lands within the Joint Venture that have been evaluated; and,
finally, undeveloped lands which have been acquired by all three Owners during
the past few years which are included under the terms of the AMI and are
subject to evaluation for possible future development.
Reserves
GLJ Petroleum Consultants Ltd. ("GLJ"), in its report dated February 7, 2007,
independently estimated the proved and probable reserves on the total of the
west side of Lease 13, which is the current Muskeg River Mine, and the east
side of Lease 13 which comprises Expansion 1. All combined, there are 2.9
billion barrels (577 million barrels Western working interest) of proved and
probable reserves associated with the current Muskeg River Mine and the new
Jackpine Mine. (Expansion 1). Based on GLJ's forecasted AOSP's undiluted
bitumen production rate of 175,000 barrels per day for 2007, the proved plus
probable reserves have a reserve life index of 44 years. Western anticipates
substantial future reserve additions as the AOSP Joint Venture moves through
the gating process for the upcoming phases of additional mining expansions of
the AOSP, in addition to potential reserves associated with the in-situ
projects that Western and Chevron are pursuing. Resources from future mining
expansions will be booked as reserves when the expansions phases are permitted,
funding is approved and certain stipulations pursuant to the Joint Venture
Agreement are satisfied.
The table below summarizes the Project's reserves and Western's share of
those proved and probable reserves as at December 31, 2006 on a synthetic crude
oil basis utilizing GLJ's forecast of prices and costs. Synthetic crude oil is
dry bitumen, uplifted by two per cent for proved reserves and three per cent
for probable reserves as a result of the hydrocracking/hydrotreating process.
The following information relating to Western's reserves and present values of
estimated future net cash flow constitutes forward-looking statements as it is
based on assumptions relating to, among others, volumes of oil in place,
recoverability of bitumen, production rates, royalty rates, operating and
development costs, capital expenditures, commodity prices and foreign exchange
rates. For a description of the risks and uncertainties facing Western that
could impact the volume and value of the reserves reported below, see "Outlook
for 2007" and "Risk and Success Factors Relating to Western" and, additionally,
the "Risks and Uncertainties" contained in Western's Annual Information Form
for the year ended December 31, 2006.
RESERVES SUMMARY
Working Working Interest
Gross Working Interest Present Values of Estimated Future
Project Interest Net After Net Cash Flow Before Income Taxes
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Reserves Reserves Royalty 0% 10% 15% 20%
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(mmbbls) (mmbbls) (mmbbls) ($ millions)
Proved 2,479 496 454 12,663 2,957 1,613 913
Probable 405 81 71 3,554 911 607 452
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Proved Plus Probable 2,884 577 525 16,217 3,868 2,220 1,365
==========================================================================================================
RESERVES RECONCILIATION (WORKING INTEREST)
Proved Plus
Proved Probable
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(mmbbls) (mmbbls)
December 31, 2005 195 310
Production (10) (10)
Revisions 1 2
Muskeg River Mine Expansion 90 7
AOSP Expansion 1 Addition 220 268
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December 31, 2006 496 577
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Resources
Within the AOSP, several leases have been formally evaluated for resource
potential including Leases 88, 89, 90, 9 and the remainder of Lease 13. Western
will disclose resource potential on a per project basis rather than lease by
lease, as the mine plans straddle lease boundaries and contingent resources are
related to a specific mine plan. Disclosure in this manner will also create
alignment with regulatory permits and proposed mine plans.
In respect of an ongoing delineation drilling program on Leases 88, 89,
90, 9 and the remainder of Lease13, Western engaged Norwest Corporation
("Norwest") to prepare volumetric estimates of recoverable bitumen associated
with mining pits. GLJ used these geological and mining assessments to determine
contingent resources. Lease 17 was not included in the determination of any
future mine plans as insufficient core hole drilling was conducted on this
lease during last year's winter drilling season to fully assess its resource
potential.
As per the Canadian Oil and Gas Evaluation Handbook ("COGEH"), contingent
resources are those quantities of oil and gas estimated on a given date to be
potentially recoverable from known accumulations but are not currently
economic. GLJ has categorized the potentially recoverable resources as
contingent in view of ownership, regulatory applications and owner commitment
issues and not as a result of current economics. Western believes these
contingent resources will be economic to develop in the future. Over time, with
additional project development and financial commitment, Western would expect
these contingent resources to be converted to reserves.
Western has an enviable land position and asset base. Currently,
regulatory upstream approvals allow for 470,000 barrels of bitumen per day to
be extracted from a combination of the Muskeg River Mine and the Jackpine Mine.
This permitting capacity would allow significant expansions of the AOSP. Future
evaluation drilling will be conducted to delineate the resource potential on
other leases. In advance of this, Shell intends to file regulatory applications
that would add an incremental 300,000 barrels per day of mining permitting
capacity, bringing the total to 770,000 barrels per day. At this level,
sufficient approvals would be in place to advance AOSP Expansions 3 through 5.
These plans would take Western's share of production to 154,000 barrels per day
from mining expansions alone. These volumes do not include any resource
potential for expansions beyond Expansion5 which could potentially occur on
leases that have not yet been evaluated. The transition and disclosure from
acreage to resources, and ultimately reserves, will evolve over time as the
Joint Venture Owners continue to drill and sanction expansions of the AOSP.
The best case estimate for contingent resources (in addition to the
reserves discussed above) on a total AOSP Joint Venture basis exceeds 4.4
billion barrels of which Western's share would be 891 million barrels. All
contingent resources are reported on a synthetic crude oil basis. This data was
based on several key assumptions in order to calculate contingent resources,
namely, minimum bitumen by weight of seven per cent to total weight, minimum
mining thickness of three metres and a range of total volume to bitumen in
place ("TV:BIP") of 12:1, consistent with regulated operating criteria, and up
to a TV:BIP ratio of 16:1 as a high estimate. The upgrading yield assumptions
are consistent with the reserve estimate.
The following table summarizes the reserves and contingent resources
associated with Western's interest in the AOSP:
WESTERN'S SHARE OF MINEABLE SYNTHETIC CRUDE OIL VOLUMES (mmbbls)
P + P Reserves Plus
Contingent Resources (1) Reserves Contingent Resources
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Proved Plus
Project Areas Low Best High Proved Probable Best High
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Muskeg River Mine (2) 188 228 291 275 309 537 600
Jackpine (3) 314 458 645 220 268 726 913
Pierre River (4)(5) 102 205 306 - - 205 306
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Total 604 891 1,242 495 577 1,468 1,819
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(1) Contingent resources have been evaluated for Leases 13, 88, 89, 90 and 9.
Categories of Low, Best and High are used as recommended in the COGEH.
(2) Includes the west side of Lease 13, 90 and Sharkbite areas. Reserve
status has been assigned only to the west side of Lease 13.
(3) Includes the east side of Lease 13 and Leases 88 and 89 and represents
Expansions 1 through 3. Reserve status has only been assigned to part of the
east side of Lease 13.
(4) Includes volumes only for Lease 9. Lease 17 was not included in this
determination as core hole drilling to assess resource potential continues on
this lease.
(5) Represents Expansions 4 and 5.
In addition to the above, Western's view is that the Ells River Project
could contain resources (with pay thickness of greater than 18 metres) suitable
for in-situ development in excess of 7.4 billion barrels of original oil in
place (approximately 1.5 billion barrels net to Western). Based on this
estimate, production from the Ells River Project, combined with volumes from
Western's in-situ project (in which the Company holds an average 64 per cent
land interest), could support production in excess of 50,000 barrels per day
net to Western. These in-situ volumes, together with production associated with
the recently announced future mineable expansions, would increase Western's
total bitumen production to more than 200,000 barrels per day within the next
15 to 20 years.
An extensive winter core hole drilling program is continuing over the
next several years on the Muskeg River Mine, Jackpine Mine and Pierre River
Mine areas as well as on the Ells River Project and Western's in-situ lands.
Western would anticipate that as drilling progresses, discovered resources will
be identified, and that contingent resource volumes will continue to be amended
as delineation drilling extends onto previously sparsely drilled leases. In
addition, as Western continues to participate in expansion opportunities,
potential future development of these project areas will provide for
substantial growth opportunities in our proved and probable reserve base.
Unevaluated Land
The current land position assembled by all Joint Venture Owners approximates
300,000 acres (69,000 acres net to Western). Of this total, approximately 68
per cent represents mineable leases, with the remaining 32 per cent considered
prospective for in-situ development. Only a fraction of Western's undeveloped
land position has been evaluated. The lands associated with Western's proved
and probable reserves represent approximately 11 per cent of the more than
69,000 net acres of total undeveloped land in which Western has the right to
participate. As delineation of these lands continues, Western expects its
reported resources and reserves to increase and will be updated accordingly.
During 2006, Western and Chevron acquired additional leases in the
Athabasca region of northern Alberta. These leases are included under the terms
of the AMI. Chevron acquired five in-situ leases, namely Leases 348, 349, 350,
673 and 675, located approximately 50 kilometres northwest of Fort McMurray and
comprise approximately 75,000 acres (15,000 acres net to Western). Western
exercised its right to participate in the Chevron in-situ leases in August 2006
and provided a payment for its pro rata share of the lease acquisition costs.
Chevron has communicated that these leases have potential to produce
approximately 100,000 barrels per day (20,000 barrels net to Western). Chevron,
a world leader with respect to heavy oil development, has assembled a dedicated
team to explore and assess this opportunity.
In terms of Western's in-situ land position, Leases 442 and 472 were
acquired in 2006. Taken together with Lease 353, which was acquired in 2005,
Western's operated land position has grown to over 21,000 acres (approximately
14,000 acres net to Western). Western holds an average 64 per cent working
interest in these in-situ lands. Pursuant to the AMI, the other Joint Venture
Owners elected to participate in Lease 353 to a 20 per cent interest, with one
other Joint Venture Owner electing to participate in Leases 442 and 472. The
participating owners have provided payment for their share of lease acquisition
costs to secure their respective working interests.
Western also has the right to participate in the development of the
leases acquired by Shell until 2009 for future mining expansions of the AOSP.
The leases could potentially be developed as an extension to the the AOSP's
continuous construction expansion strategy.
The exploration and development of this significant land base, both
mineable and in-situ, could involve a substantial and material capital
commitment by Western to continue to grow its land position and capture
opportunities to add resources. Assessments regarding our involvement will
always be made in the context of maintaining the integrity of our financial
position and creating shareholder value. To manage this growing land position
and evaluate potential opportunities, we expanded our organizational
capabilities in 2006, particularly in the area of heavy oil development with
key management appointments, including Mr. Graig Ritchie as Vice President, Oil
Sands and Mr. Matt Swartout as Senior Drilling Manager.
OPERATING RESULTS
Fiscal 2006 represents the third full year of commercial operations for
Western. The Project's original nameplate productive capacity was 155,000
barrels per calendar day. As a result of successful and ongoing production
optimization initiatives at both the Mine and Upgrader, the Project has
increased the calendar day average production to a range of 165,000 to 175,000
barrels per day in recent quarters, with a near-term goal of increasing
production to approximately 200,000 barrels per day by 2009. For short-term
intervals the mine has achieved production rates in excess of 215,000 barrels
per day. During the second quarter of 2006, operations were impacted by the
first full plant turnaround which extended to a 56-day period. The turnaround
schedule was longer than anticipated because it was determined that additional
maintenance and repair work was required in order to remove large amounts of
coke from the reactor vessels at the Upgrader. With efforts focused on
increasing the reliability of the base Project, consistent and stable
operations should follow which, in turn, optimizes the efficiency of these
major facilities. Full turnarounds are expected to be required on a three to
four year cycle.
HIGHLIGHTS
2006 2005 2004
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Operating Data (bbls/d)
Bitumen Production 27,500 31,994 27,108
Synthetic Crude Sales 37,326 42,534 36,210
Operating Expense per Processed Barrel ($/bbl) (1) 28.38 22.06(9) 21.17
- ---------------------------------------------------------------------------------------------------------
Financial Data ($ thousands, except as indicated)
Gross Revenue 983,560 910,330 636,911
Realized Crude Oil Sales Price - Oil Sands ($/bbl) (1)(2) 60.51 49.91 34.60
Cash Flow from Operations (1)(3) 228,449 244,231 23,044
Cash Flow per Share - Basic ($/Share) (1)(4) 1.42 1.52 0.15
Net Earnings Attributable to Common Shareholders (6) 63,370 149,449 19,452
Net Earnings per Share ($/Share)
Basic 0.39 0.93 0.12
Diluted 0.39 0.92 0.12
EBITDAX (1)(5) 276,916 307,008 87,587
Net Capital Expenditures (7) 301,273 46,833 39,968
Total Assets 1,794,159 1,590,520 1,470,870
Long-term Debt 601,385 565,655 662,620
Long-term Financial Liabilities (8) 723,174 706,880 716,094
Weighted Average Shares Outstanding - Basic (Shares) 160,991,406 160,169,887 156,926,514
=========================================================================================================
(1) Please refer to page 56 for a discussion of Non-GAAP financial measures.
(2) The realized crude oil sales price is the revenue derived from the sale
of Western's share of the Project's synthetic crude oil, net of the risk
management activities, divided by the corresponding volume. Please refer to
page 35 for calculation.
(3) Cash flow from operations is expressed before changes in non-cash working
capital.
(4) Cash flow per share is calculated as cash flow from operations divided by
weighted average common shares outstanding, basic.
(5) Earnings before interest, taxes, depreciation, depletion, amortization,
stock-based compensation, accretion on asset retirement obligation, foreign
exchange and risk management as calculated on page 43.
(6) Western has not paid cash dividends in any of the above referenced fiscal
years.
(7) Net capital expenditures are capital expenditures net of any insurance
proceeds received during the period.
(8) Long-term financial liabilities includes long-term debt, option premium
liability and lease obligations.
(9) Operating costs per processed barrel for 2006 were $24.50, net of
turnaround costs of $3.88 per processed barrel.
FINANCIAL PERFORMANCE
Revenue
Western achieved record gross crude oil sales revenue of $983.6 million in
fiscal 2006 compared to $910.3 million in 2005, including $825.4 million (2005
- - $777.9 million) from proprietary production at an average realized price of
$60.51 per barrel (2005 - $49.91 per barrel). Record sales revenues were
achieved largely due to a 21 per cent increase in Western's realized crude oil
price as a result of the continued strength in world crude oil prices partially
offset by a 14 per cent decrease in bitumen production due to the full planned
plant turnaround and repair of a conveyor belt during the year. During 2006,
Western had no proprietary barrels subject to financial hedge instruments and,
consequently, enjoyed the full appreciation of the underlying 21 per cent
increase in West Texas Intermediate ("WTI") light sweet crude oil through our
synthetic crude oil sales. A careful and deliberate decision was made to not
hedge any barrels in 2006 as the capital expenditures were not large relative
to the capital spending profile in subsequent years. In 2005, gross revenues
were reduced by $110.4 million due to out-of-the-money fixed priced swap
contracts on a portion of Western's proprietary production and, as a result,
Western's crude oil price realization was reduced by $7.11 per barrel.
Western's crude oil sales were subject to an overall quality differential
of $12.82 per barrel (2005 - $12.27 per barrel) off of the Edmonton PAR
benchmark crude oil price of $73.33 per barrel in 2006. The quality
differential has increased marginally from the prior year due to a heavier than
normal sales mix associated with the period prior to, and immediately
following, the full plant turnaround. During this period, the Upgrader was not
running at optimal conversion rates resulting in a heavier blend of synthetic
crude oil. This was offset by a general narrowing of the heavy crude oil
differential during 2006 which helped maintain higher oil sands revenues and
realized synthetic crude oil sales prices. The heavy crude oil differential
averaged 35 per cent of WTI prices, or $22.58 per barrel in 2006 compared to 39
per cent or $21.83 per barrel in 2005. Western has generally observed a
narrowing of the heavy oil differential over the last year thought to be due to
in part by crude oil pipeline reversals enabling western Canadian heavy oil
producers to ship to additional markets in the Midwest and Gulf Coast regions
of the United States. Increasingly, refineries in the United States are
purchasing additional heavy crude oil to capture the value inherent in the
differential by processing heavy oil into higher-valued refined products such
as gasoline, diesel and jet fuel. As the graph on page 32 indicates and
notwithstanding the above, Western's realized prices remain closely correlated
to underlying movements in WTI. During 2006, Western experienced its highest
price realizations since production start-up primarily due to the factors
outlined above as well as a marked improvement in the reliability of the plant
which, when the plant turnaround is excluded, allowed the Project to produce a
lighter overall sales mix through better conversion of bitumen into light
synthetic crude oil at the Upgrader.
With the objective of providing greater cash flow certainty for the years
of significant capital expenditures, Western executed an extensive hedging
program covering 2007 to 2009, with entirely different hedging products or
derivative instruments employed for this program. Western implemented a
pay-collar strategy, whereby a series of put and call options were both bought
and sold to establish a floor price for a portion of planned production, with a
corresponding ceiling that Western would receive on a similar but smaller
number of barrels. The range of these collars provides a weighted average floor
price of US$52.42 on 20,000 barrels per day over the three years and a weighted
average ceiling of US$92.41 on an average of 13,333 barrels per day over the
same time period. This program provides greater cash flow certainty given the
substantial capital commitments associated with Expansion1 of the AOSP over the
next three years. In addition, the collar strategy does not limit the upside
potential related to commodity price appreciation to the same degree as the
fixed price swap contracts that Western employed in the past.
Western generated net revenue of $630.0 million in 2006 compared to
$591.4 million in 2005, representing a seven per cent increase. Net revenue
reflects the costs of purchased feedstocks and transportation costs downstream
of Edmonton. Feedstocks are third-party crude oil products introduced at the
Upgrader. Some feedstocks are used in the hydrocracking/hydrotreating process,
while others are used as blendstock to further optimize various qualities of
synthetic crude oil products. The cost of these feedstocks depends on oil
markets and the spread between heavy and light crude oil prices.
NET REVENUE
($ thousands, except as indicated) 2006 2005
- ---------------------------------------------------------------------------
Revenue
Oil Sands (1) 825,418 777,876
Marketing and Transportation 158,142 132,454
- ---------------------------------------------------------------------------
Total Revenue 983,560 910,330
Purchased Feedstocks and Transportation
Oil Sands 196,066 185,693
Marketing and Transportation 157,456 133,241
- ---------------------------------------------------------------------------
Total Purchased Feedstocks and Transportation 353,522 318,934
Net Revenue
Oil Sands (1) 629,352 592,183
Marketing and Transportation 686 (787)
- ---------------------------------------------------------------------------
Total Net Revenue 630,038 591,396
Synthetic Crude Sales (bbls/d) 37,326 42,534
Crude Oil Sales Price ($/bbl) (2) 60.51 49.91
============================================================================
(1) Oil sands revenue and net revenue are presented net of Western's hedging
activities.
(2) Realized crude oil sales price ($/bbl) is calculated as oil sands revenue
less any transportation costs divided by synthetic crude sales volume. In 2006,
$1.1million (2005 - $3.0 million) had been incurred for transportation costs
related to oil sands.
Operating Costs
Western's share of the Project's operating costs totalled $286.3 million in
2006 (2005 - $250.4 million) including $40.2 million associated with the cost
of the turnaround. Also included in this amount are costs associated with
removing overburden at the Mine and transporting bitumen from the Mine to the
Upgrader. On a per processed barrel of bitumen basis, unit operating costs were
$28.38 per barrel based on average production of 27,500 barrels per day in 2006
compared to $22.06 per barrel based on average production of 31,994 barrels per
day in 2005. Excluding the impact of the turnaround, operating costs were
$24.50 per processed barrel for 2006 compared to $22.06 per processed barrel
for the prior year period. However, unit operating costs per processed barrel
in 2006 are impacted by lower annual production rates compared to the prior
year period.
Higher unit operating costs in 2006 were largely due to higher input
costs for materials and supplies in an escalating commodity price environment,
offset in part by lower natural gas costs during 2006 compared to the previous
year. On a unit basis, natural gas costs were $4.07 per processed barrel
compared to $5.04 per processed barrel in 2005. This 19 per cent decrease is
consistent with the 18 per cent decrease in the market price for natural gas
over the same time periods, indicating a similar gas intensity for the Project
over the last several years. Unit operating costs in 2006 were also impacted by
repair costs and associated lost production stemming from a tear in the
conveyor belt at the Mine in the first quarter.
Operating costs, on both an absolute basis and on a per unit basis, were
impacted significantly by the first full turnaround of the Project in 2006.
This process extended for a period of 56 days during the second quarter and,
for a large part of that time, little or no production was recorded. Turnaround
activities added $3.88 per processed barrel in 2006. Given that the cost
structure of the operation is predominantly fixed, many of the costs incurred
when the Project is in full operation continued during the turnaround. As a
result, operating costs per unit increased substantially in 2006 and a
comparison to the prior year period is not meaningful. For accounting purposes,
Western has expensed all of the costs associated with the turnaround, whereas
other oil sands producers capitalize certain components of turnaround costs and
amortize them over the period to the next turnaround. Western's share of the
turnaround costs was $40.2 million. The turnaround proved to be more costly and
longer in duration than originally budgeted due to additional maintenance and
repair work at the Upgrader in order to remove large amounts of coke from the
reactor vessels. Consequently, the Project was delayed in returning to full
production. Operating costs returned to expected levels towards the latter part
of 2006. Following the turnaround, operating costs were $20.38 per processed
barrel over the last two quarters of the year on a bitumen production base of
slightly more than 34,000 barrels per day net to Western over this time period.
Western believes its operating costs are impacted somewhat by longer-term
WTI prices and associated energy costs. In 2006, WTI averaged US$66.22 per
barrel compared to US$56.56 per barrel for 2005 which resulted in upward
pressure on certain cost components as suppliers of these components and
services themselves experienced higher cost structures largely due to higher
energy costs and other commodity prices. Ultimately, this contributed to a
higher cost structure for oil sands operations. Despite the upward pressures on
operating costs in a rising commodity cycle, unit operating costs typically
decline over time as the technological and engineering challenges are addressed
and resolved and as production optimization initiatives are completed.
Production optimization activities requiring relatively modest amounts of
capital are planned to continue over the life of the Project at both the Mine
and the Upgrader in order to increase throughput and/or reduce absolute costs.
Production at the Mine has more consistently met or exceeded 200,000 barrels
per day on a stream basis which demonstrates the effectiveness of our
production optimization activities. Ongoing efforts with respect to these
activities should result in sustained upstream calendar day production of
approximately 200,000 barrels per day by 2009. Corresponding initiatives at the
Upgrader are planned to be undertaken to process this higher level of
production as well as improving product quality.
Western recognizes that operating costs are a key metric among companies
active in the mineable oil sands industry; however, oil sands producers have
different cost structures and accounting treatments that require careful
analysis to make meaningful comparisons. Western, for example, includes the
cost of transporting processed bitumen from Fort McMurray to Edmonton as part
of its overall operating costs, whereas other industry players either do not
have this cost category or net these transportation costs from oil sands
revenue. Nevertheless, all companies active in the energy industry are coming
to terms with the higher commodity price environment and associated increased
costs for materials, supplies and natural gas. While the entire industry's cost
structure has shifted upwards, the Joint Venture will continue to evaluate all
methods to control and reduce its costs. As the majority of the AOSP's
operating costs are fixed, to the extent the Project can maintain and increase
production, total unit operating costs should decrease as the costs are
distributed over a growing production base. We believe the AOSP has the
potential to be one of the lowest cost producers of all the Canadian oil sands
mining projects.
OPERATING COSTS
($ thousands, except as indicated) 2006 2005
- -----------------------------------------------------------------------------------------------------------
Operating Expenses for Bitumen Sold
Operating Expense - Income Statement 246,164 250,389
Operating Expense - (Inventoried)/Expensed in Purchased Feedstocks 7,765 11,704
Turnaround Costs - Income Statement 40,161 --
- -----------------------------------------------------------------------------------------------------------
Total Operating Expenses for Bitumen Sold 294,090 262,093
- -----------------------------------------------------------------------------------------------------------
Sales (barrels per day)
Total Synthetic Crude Sales 37,326 42,534
Purchased Upgrader Blendstocks 8,932 9,979
- -----------------------------------------------------------------------------------------------------------
Synthetic Crude Sales Excluding Blendstocks 28,394 32,555
- -----------------------------------------------------------------------------------------------------------
Operating Expenses per Processed Barrel ($/bbl) (1) 28.38 22.06
- -----------------------------------------------------------------------------------------------------------
Operating Expenses per Processed Barrel Excluding Turnaround Costs ($/bbl)(2) 24.50 22.06
===========================================================================================================
(1) Operating expenses per processed barrel ($/bbl) are calculated as total
operating expenses for bitumen sold divided by synthetic crude sales excluding
blendstocks. This calculation recognizes that, intrinsic in the Project's
operations, bitumen production from the Mine receives an approximate three per
cent uplift as a result of the hydrotreating/hydroconversion process, which is
included in synthetic crude sales excluding blendstocks.
(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.
Operating Netbacks
Western's 2006 operating netback was $33.84 per dry bitumen barrel produced,
down from $38.32 per dry bitumen barrel produced (excluding hedges) in the
prior year period. This decrease is largely due to the $40.2 million incurred
for the turnaround in the second quarter as well as the costs associated with
replacing the conveyor belt during the first quarter of 2006. The netback for
2006, however, was considerably higher than the netback achieved in 2004 and
2003 due to the significant increase in underlying crude oil prices over these
time periods. Netbacks in the second half of 2006 improved substantially, with
a netback of $45.77 per dry bitumen barrel produced in the third quarter and
$37.12 per dry bitumen barrel produced in the fourth quarter. The decrease in
the operating netback was partially offset by the narrowing of the heavy oil
differential from the prior year period as additional markets for Canadian
heavy oil are opening in the United States through existing pipeline reversals,
together with refineries reconfiguring their assets to process a larger portion
of heavy oil to capitalize on the heavy crude oil differential.
Royalties
Royalties were $4.1 million or $0.40 per barrel of bitumen in 2006 compared to
$4.0 million or $0.34 per barrel in 2005. Higher gross royalties are the result
of higher deemed bitumen prices for 2006 which serve as the basis for the
royalty calculation, partially offset by reduced production during 2006 due to
the turnaround. Initially, royalties are calculated at one per cent of the
gross revenue from the bitumen produced (based on its deemed value prior to
upgrading) until recovery of all capital costs associated with the AOSP,
together with a return on capital equal to the Government of Canada's federal
long-term bond rate. After full capital cost recovery, the royalty is
calculated as the greater of one per cent of the gross revenue on the bitumen
produced or 25 per cent of the net revenue on the bitumen produced.
During 2006, Western announced its participation in Expansion 1 of the
AOSP and we fully expect to participate in subsequent mining expansions of the
AOSP. As such, Western assumes that additional capital incurred to construct
future expansions will be added to the capital base for royalty purposes,
extending our royalty horizon in the absence of any legislative amendments to
the royalty regime. At current commodity prices, Western does not anticipate
conversion to the 25 per cent of net bitumen revenues for the next several
years. The move to the higher royalty rate may be accelerated or postponed
depending on future crude oil prices, foreign exchange rates and the timing and
inclusion of capital expenditures and the Alberta government's treatment of
bitumen extraction expansion efforts.
CORPORATE RESULTS
Research and Business Development
A portion of Western's annual budget is directed to research and business
development activities. These activities include: research and development
efforts with the objective of identifying ways to add value to our existing
assets; the addition of internal technical capabilities in order to evaluate
opportunities as they arise either through the Joint Venture or independently;
and finally, as part of our long-term strategy, plans to expand our
organizational capabilities to evaluate opportunities related to downstream
integration. A portion of these expenditures also relate to WesternZagros'
initiative in Kurdistan. Western incurred $34.9 million for research and
business development in 2006 (2005 - $10.7 million), of which $22.4 million
(2005 - $5 million) relates specifically to AOSP-related research projects. The
majority of the balance of $12.5 million is related Western-led research
activities related to oil sand extraction and recovery methodologies, increased
administrative costs associated with building the organizational capabilities
to assess in-situ opportunities, downstream integration strategies and
initiatives and costs related to progressing the negotiation of our EPSA in
Kurdistan.
General and Administrative Expenses
General and administrative expenses ("G&A") were $28.5 million in 2006 compared
to $14.5 million in the prior period. Of this amount, $12.1 million (2005 -
$3.1 million) relates to stock-based compensation. Net of stock-based
compensation, G&A expenses were $16.4 million compared to $11.4 million in
2005. The increase from the prior year period is largely a function of higher
office rent and increased salaries and benefits stemming from a near doubling
in the number of employees in 2006. It also reflects additional professional
costs incurred during 2006 due to increased public company compliance
requirements compared to 2005.
Insurance Expenses
Insurance expenses were $11.5 million in 2006 compared to $8.0 million in 2005.
Western maintains insurance policies covering property damage, business
interruption, commercial general liability, directors and officers liability,
in addition to various corporate policies. Insurance expense is higher in 2006
compared to the previous year due to an increase in coverage associated with
Western's business interruption policy. Western's insurance placement strategy
is to obtain sufficient coverage on business interruption to ensure sufficient
cash flow is received after a major loss. As such, when underlying commodity
prices increase, this desired level of coverage is more costly. Another factor
impacting the cost of the business interruption policy is worldwide loss events
which cause insurance carriers to re-adjust premiums charged on such policies.
These factors were partially offset by the strengthening of the US/Cdn exchange
rate as these premiums are paid in US dollars. There were no material
reductions in coverage compared to the prior year. Indeed, additional coverages
are being secured both on a Joint Venture basis relating to the construction
and start-up of Expansion 1, together with policies relating to Western's
operation of an in-situ project. As such, Western anticipates insurance costs
to increase as these operations grow.
Interest Expense
During 2006, total interest charges decreased by $5.4 million, or nine per
cent, to $52.8 million compared to $58.2 million in 2005. Of the total interest
charges in 2006, $2.8 million relating to Expansion 1 was capitalized.
Capitalized interest will increase in the future to the extent that we employ
debt financing to fund our share of the capital costs of Expansion 1.
Capitalized interest will continue to be recorded until the assets associated
with Expansion 1 begin commercial operations. This is consistent with the
treatment of interest charges associated during the construction of the base
Project. Of the remaining $50.0 million in interest charges recorded on our
income statement, $43.4 million is related to interest charges on debt
obligations (2005 - $54.3 million), $2.8million (2005 - $2.6 million) to
capital lease obligations and $3.8 million (2005 - $1.3 million) to 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.
Western's debt obligations include US$450 million of Senior Secured Notes
and a $340 million Revolving Credit Facility. Western's average interest rate
decreased marginally from 2005. This decrease is due to two factors: the
strengthening of the US/Cdn exchange rate as interest payments on our US$450
million denominated debt are recorded in Canadian dollars for financial
reporting purposes and lower interest rates on amounts drawn under the
Revolving Facility resulting from amendments executed in the fourth quarter of
2005. These positive factors were partially offset by interest charges on
larger drawn amounts under the Revolving Facility. The Notes bear interest at
8.375 per cent and are not callable before their maturity date of May 1, 2012.
Western's ability to meet fixed debt servicing costs continues to improve which
can be measured by the interest coverage ratio. This ratio has improved to a
factor over five times in 2006 from under one time in 2003, a seven-fold
increase with no material deterioration in this ratio in a full turnaround
year. As we begin to fund our share of the capital costs of Expansion 1, and to
the extent that debt facilities are used to finance this expansion, ratios such
as interest coverage may fall from present levels; however, we intend to manage
these levels to ensure our continued participation in Expansion 1 and other
AOSP or Western-driven growth initiatives. Interest expense on a per barrel
basis also decreased substantially due to the addition of reserves associated
with Expansion 1 from previous years. We anticipate this ratio to increase
somewhat as debt is placed on the balance sheet to fund our share of Expansion
1. Western believes all of its key growth initiatives can be supported by its
financial performance and its ability to access capital markets.
The following table summarizes our interest expense and average cost of debt
for the past two fiscal years.
INTEREST AND LONG-TERM DEBT FINANCING
($ thousands, except as indicated) 2006 2005
- ----------------------------------------------------------------------------
Interest Expense
Interest Expense on Long-term Debt 46,190 54,324
Interest on Obligations under Capital Lease 2,823 2,562
Interest on Option Premium Liability 3,799 1,279
- ----------------------------------------------------------------------------
Total Financing Charges 52,812 58,165
- ----------------------------------------------------------------------------
Long-term Debt Financing
US$450 Million Senior Secured Notes (1) 524,385 524,655
Revolving and Senior Credit Facilities 77,000 41,000
- ----------------------------------------------------------------------------
Total Long-term Debt 601,385 565,655
- ----------------------------------------------------------------------------
Average Long-term Debt Level 583,520 661,638
Average Cost of Long-term Debt (2) 7.92% 8.21%
============================================================================
(1) Under Canadian GAAP, the Senior Secured Notes are recorded in Canadian
dollars at exchange rates in effect at each balance sheet date. Unrealized
foreign exchange gains or losses are then included on the Consolidated
Statement of Operations.
(2) Calculated by dividing the interest expense on long-term debt by the
average long-term debt balance outstanding during the year.
Depreciation, Depletion and Amortization
In 2006, Western recorded $61.6 million as depreciation, depletion and
amortization expense compared to $50.7million in 2005. This 21 per cent
increase is primarily the result of two separate decisions to write-off early
stage pilot projects. At the Joint Venture level, Western had a $9.4 million
write-off relating to certain AOSP production optimization and profitability
projects in the pre-feasibility stage (predominantly at the Mine) that were
discontinued as future benefits were not conclusive. An additional write-off of
$5.6 million occurred as a result of oil sands activities that Western
independently pursued and, due to technical reasons, elected not to continue.
Depletion is calculated on a unit of production basis for Western's share of
Project capital costs, while previously deferred financing charges are
amortized on a straight-line basis over the remaining life of the debt
facilities. The increase for 2006 is partially offset by the 14 per cent
decrease in production in 2006 versus 2005 as a result of the turnaround in the
second quarter of 2006.
DEPRECIATION, DEPLETION AND AMORTIZATION
Year ended December 31 2006 2005
- -----------------------------------------------------------------------------------------------
($ thousands) $/bbl ($ thousands) $/bbl
- -----------------------------------------------------------------------------------------------
Depreciation and Depletion 44,022 4.39 48,206 4.13
Accelerated Depreciation and Depletion 14,979 1.49 -- --
Amortization 2,559 0.25 2,532 0.22
- -----------------------------------------------------------------------------------------------
Total Depreciation, Depletion
and Amortization 61,560 6.13 50,738 4.35
===============================================================================================
Foreign Exchange
In 2006, WTI averaged US$66.22 per barrel compared to US$56.56 per barrel in
2005, representing a 17 per cent increase. This increase in WTI is one factor,
out of many, that may have contributed to the strengthening in the Canadian
dollar relative to the US dollar. For Western, the negative impact of the
foreign exchange rate increase on revenue was somewhat offset by lower interest
costs expressed in Canadian dollars on our US dollar denominated Senior Secured
Notes and a reduced liability (as measured in Canadian dollars) associated with
this debt. In 2006, we recorded an unrealized foreign exchange gain of $0.2
million compared to a gain of $17.8million in 2005 relating to the conversion
of the Senior Secured Notes and option premium liability to Canadian dollars.
As reference points, the noon-day closing foreign exchange rate on December 31,
2006 was $0.8581 US/Cdn compared to $0.8577 US/Cdn on December 31, 2005. In
terms of average noon-day rates for the respective periods, fiscal 2006 was
$0.8817 US/Cdn compared to $0.8254 US/Cdn for fiscal 2005.
Income Taxes
Western has significant tax pools totalling $1.4 billion that were accumulated
in conjunction with our 20 per cent share of the construction costs for the
Muskeg River Mine and Extraction Plant and the Scotford Upgrader. These tax
pools will be used to offset future taxable income and extend the time horizon
before Western pays cash taxes.
As at December 31, 2006, Western recorded a future income tax liability
of $73.1 million compared to $56.4 million at December 31, 2005. Western
recognized approximately $16.7 million of future income tax expense during the
year as we experienced profitable operations despite the nearly two-month
turnaround. During 2006, no amounts were expensed for the Large Corporation Tax
(2005 - $3.0 million) as this tax was eliminated in early 2006 by the federal
government. No other current taxes are payable and our cash tax horizon is not
expected to occur for several years as additional capital incurred for the
construction of Expansion 1 contributes to the existing tax pools, thereby
offsetting taxable income in future years beyond which current pools would
cover.
TAX POOLS
December 31 ($ thousands) 2006 2005
- -------------------------------------------------------------------------------
Canadian Exploration Expense 109,623 89,140
Canadian Development Expense 39,994 23,657
Cumulative Eligible Capital 7,370 7,925
Capital Cost Allowance 175,892 126,001
Accelerated Capital Cost Allowance 1,085,421 1,090,155
- -------------------------------------------------------------------------------
Total Depreciable Tax Pools 1,418,300 1,336,878
Loss Carry Forwards 9,055 14,000
Financing and Share Issue Costs 3,902 9,596
- -------------------------------------------------------------------------------
Total Tax Pools 1,431,257 1,360,474
===============================================================================
Net Earnings
Net earnings were $63.4 million ($0.39 per share) in 2006 compared to $149.4
million ($0.93 per share) in 2005. This year-over-year decrease is in large
part due to the full turnaround completed during 2006, together with a $72.1
million unrealized risk management loss ($49.9 million after tax) associated
with marking to market Western's strategic crude oil hedging program for 2007
through to 2009 compared to an unrealized risk management gain of $13.5 million
in 2005 ($8.9 million after tax). Earnings for the year reflect $0.3 million of
unrealized foreign exchange gains on our US$450 million Senior Secured Notes
and option premium liability, a $72.1 million unrealized loss on risk
management activities and a future income tax expense of $16.7 million.
Earnings before interest, taxes, depreciation, depletion and amortization,
stock-based compensation, accretion on asset retirement obligation, foreign
exchange gains and risk management gains were $276.9 million. Cash flow from
operations, before changes in non-cash working capital, was $228.4 million
($1.42 per share) in 2006 compared to $244.2 million ($1.52 per share) in 2005.
Robust commodity prices, together with sustained reliable operations over the
course of the year, excluding the effects of the full turnaround, resulted in
substantial EBITDAX which was predominantly used to assist in the funding of
early stage capital for Expansion 1.
NET EARNINGS
December 31 ($ thousands) 2006 2005 2004
- ------------------------------------------------------------------------------------------------------
Net Earnings 63,370 149,449 19,452
After Tax Impact of:
Unrealized Risk Management (Gain)/Loss 49,927 (8,928) --
Unrealized Foreign Exchange Gain (181) (14,810) (33,243)
- ------------------------------------------------------------------------------------------------------
Net Earnings (Loss) Excluding Unrealized Gain (Loss) 113,116 125,711 (13,791)
- ------------------------------------------------------------------------------------------------------
Net Earnings (Loss) Excluding Unrealized Gain (Loss) Per Share ($)
Basic 0.70 0.78 (0.09)
Diluted 0.69 0.77 (0.09)
======================================================================================================
RECONCILIATION: NET EARNINGS TO EBITDAX
The following table provides the reconciliation between net earnings
attributable to common shareholders, cash flow from operations (before changes
in non-cash working capital) and EBITDAX:
December 31 (thousands) 2006 2005 2004
- ------------------------------------------------------------------------------------------------
Net Earnings Attributable to Common Shareholders 63,370 149,449 19,452
Add (Deduct):
Depreciation, Depletion and Amortization 61,560 50,738 44,515
Accretion on Asset Retirement Obligation 1,256 562 471
Stock-based Compensation 12,083 3,149 967
Impairment of Long-lived Assets -- -- 4,733
Unrealized Foreign Exchange Gain (212) (17,803) (39,960)
Unrealized Risk Management (Gain)/Loss 72,118 (13,450) --
Future Income Tax Expense (Recovery) 16,668 70,956 (7,104)
Interest Expense on Option Premium Liability 3,801 1,278 --
Cash Settlement on Asset Retirement Obligations (91) (52) --
Cash Settlement on Performance Share Units (2,104) (596) (30)
- ------------------------------------------------------------------------------------------------
Cash Flow From Operations, Before Changes
in Non-Cash Working Capital 228,449 244,231 23,044
Add (Deduct):
Interest (excluding interest on Option Premium Liability) 46,216 56,887 61,154
Realized Foreign Exchange Loss 163 2,242 1,610
Current Taxes (Recovery) (107) 3,000 1,749
Cash Settlement on Asset Retirement Obligations 91 52 --
Cash Settlement on Performance Share Units 2,104 596 30
- ------------------------------------------------------------------------------------------------
EBITDAX 276,916 307,008 87,587
================================================================================================
Please refer to page 56 for a discussion of Non-GAAP financial measures.
Quarterly Information
The following table summarizes key financial information on a quarterly basis
for the last two fiscal years.
QUARTERLY INFORMATION
($ millions, except per share amounts) Q1 Q2 Q3 Q4 Total
- ---------------------------------------------------------------------------------------
2006
Net Revenue 139.2 95.6 206.2 189.0 630.0
Capital Expenditures, Net 35.3 55.8 96.4 113.7 301.3
Long-term Debt 525.2 532.8 546.9 601.4 601.4
Cash Flow from Operations (1) 47.8 (20.8) 110.5 91.1 228.4
Cash Flow per Share (2)(5) 0.30 (0.13) 0.69 0.57 1.42
Earnings (Loss) Attributable to
Common Shareholders (3)(4)(7) (24.8) (23.0) 84.4 26.8 63.4
Earnings (Loss) per Share
Basic (3)(7) (0.15) (0.14) 0.52 0.17 0.39
Diluted (3)(7) (0.15) (0.14) 0.52 0.16 0.39
- ---------------------------------------------------------------------------------------
2005
Net Revenue 91.7 148.2 185.7 165.8 591.4
Capital Expenditures, Net 17.5 (12.9) 16.0 26.2 46.8
Long-term Debt 777.3 755.5 597.5 565.7 565.7
Cash Flow from Operations (1) 10.8 68.0 95.0 70.4 244.2
Cash Flow per Share (2)(5)(6) 0.07 0.42 0.59 0.44 1.52
Earnings (Loss) Attributable to
Common Shareholders (1.9) 28.7 79.3 43.3 149.4
Earnings (Loss) per Share
Basic (6) (0.01) 0.18 0.50 0.27 0.93
Diluted (6) (0.01) 0.18 0.49 0.27 0.92
- ---------------------------------------------------------------------------------------
(1) Cash flow from operations is expressed before changes in non-cash working
capital.
(2) Cash flow per share is calculated as cash flow from operations divided by
weighted average common shares outstanding, basic.
(3) Includes unrealized foreign exchange gains(losses) on US$450 million
Senior Secured Notes and Option Premium Liability: (Q1 - $(0.6) million, Q2 -
$27.3 million, Q3 - $(0.1) million, Q4 - $(26.3) million).
(4) Includes unrealized risk management gains/(loss) on strategic crude oil
program (Q1 -$(67.7) million, Q2 -$(44.5) million, Q3 - $33.3 million, Q4 -
$6.8 million)
(5) Please refer to page 56 for a discussion of Non-GAAP financial measures.
(6) Per share amounts for the first quarter 2005 have been restated to
reflect 3:1 share split effective May 30, 2005.
(7) 2006 quarterly net earnings (loss) and earnings per share amounts have
been restated to reflect accounting treatment change to stock-based
compensation.
(8) Total amounts may not add due to rounding.
LIQUIDITY AND FINANCIAL POSITION
Western maintained a strong financial position in 2006, largely due to robust
commodity prices during the majority of the year, combined with strong
production in the months following the turnaround. It is important to note that
this credit profile was maintained after considering the full impact of the
plant turnaround, where little or no production was recorded for a portion of
the second quarter, and while operating and capital costs of the business
continued during this period. This financial position provides us with a solid
foundation to finance our share of the capital costs associated with Expansion
1, while maintaining the base Project.
During 2006, Western's capital costs of $301.3 million were funded
primarily through cash flow from operations of $228.4 million. The balance was
funded by $36 million of incremental borrowings under the Revolving Credit
Facility and working capital. Total amounts drawn under the Revolving Credit
Facility were $77 million at year-end. At December 31, 2006, Western had $253
million in unused working capital capacity. A key barometer of the financial
strength of a company is its debt to total capitalization ratio. For Western,
this ratio has continued to improve from a high of 66 per cent in 2003 to 48
per cent in 2006. This level provides the basis for additional borrowings,
should Western elect to do so, to fund upcoming capital initiatives including
Expansion 1 of the AOSP and activities related to in-situ evaluation.
Western implemented a strategic crude oil risk management program in the
third quarter of 2005 which establishes a weighted average floor price of
US$52.42 on 20,000 barrels per day of production from 2007 through to 2009.
This program provides greater cash flow certainty during those years where
significant AOSP capital expenditures for Expansion 1 are expected. Incremental
debt may be required to fund future expansion phases and other initiatives as
they arise. Throughout these expansion efforts, we expect to maintain a
fiscally prudent capital structure which employs both debt and potentially
equity capital should the need arise. Western's view is that it is well
positioned to fund its share of the AOSP Expansion 1, together with future
upstream expansions of the AOSP, while at the same time be in a position to
finance growth associated with Western's in-situ development, downstream
initiative and Kurdistan opportunity.
Debt Financing
In 2006, Western maintained its US$450 million of Senior Secured Notes as they
are non-callable with a maturity of May 1, 2012. We were also successful in
amending our Revolving Credit Facility in May 2006. This amendment altered the
nature of some of the covenants in the underlying credit agreement to
facilitate the development of Western's key strategic initiatives. We did not
increase the capacity of our Revolving Facility in 2006; however, the size of
the current Facility is a function of the present value of our share of
reserves from the AOSP. Under Western's current debt capital structure, all
bank borrowings rank in priority to the holders of Western's US$450million
Notes. Based on the reserve evaluation as at December 31, 2006, Western has
full access to the $340 million limit under the Revolving Facility. Western
anticipates it can fund the capital costs associated with the AOSP Expansion 1
through a combination of cash flow from operations and incremental borrowings
and is actively evaluating various debt structures to accomplish this
objective.
Western benefited from the pricing amendment finalized in the fourth
quarter of 2005 as underlying interest rates softened and Western carried
minimal balances throughout the course of 2006. Western currently pays nil to
225 basis points over the bank's prime lending rate, bankers acceptances or US
Libor notes, as applicable, on amounts drawn under the Revolving Facility. At
December 31, 2006, $77 million (December 31, 2005 - $41million) had been drawn
on this facility with $253 million in unused working capital capacity.
Additionally, as at December 31, 2006, letters of credit issued in the amount
of $9.6 million (December 31, 2005 - $8.9 million) were outstanding under the
Revolving Credit Facility.
Equity Financing
Cash flow from operations, together with a modest increase in the Revolving
Facility, was sufficient to fund the capital expenditures and working capital
commitments during 2006. Western will continue to assess all forms of financing
vehicles to ensure our capital structure leverages off the existing asset base
in a prudent manner as we pursue an independent downstream integration
opportunity for our share of bitumen production beyond Expansion1, including
both mineable and in-situ volumes.
The share performance graph compares the yearly change in the cumulative
total shareholder return of a $100 investment made on December 31, 2000 in
Western's Common Shares with the cumulative total return of the S&P/TSX Total
Return Composite Index and the S&P/TSX Capped Energy Index, assuming the
reinvestment of dividends, where applicable, for the comparable period. Western
has significantly outperformed both indices since its inception with a compound
rate of return of 37 per cent.
EQUITY CAPITAL
At December 31 2006
- -------------------------------------------------------------------------------
Issued and Outstanding:
Common Shares 161,378,399
Outstanding:
Stock Options 3,633,264
- -------------------------------------------------------------------------------
Fully Diluted Number of Shares 165,011,663
===============================================================================
Capital Expenditures
Net capital expenditures totalled $301.3 million in 2006 compared to $46.8
million in 2005. Of this total, AOSP initiatives accounted for $251 million,
including $187.4 million for Expansion 1 which includes $2.8 million in
capitalized interest. Under the terms of the Joint Venture Agreement, Western
is responsible for its 20 per cent share of the capital costs related to
Expansion 1. Western also incurs capital expenditures related to the evaluation
of in-situ leases for its operated properties as well as Chevron's Ells River
Project, both of which are included in the Joint Venture pursuant to the AMI.
Capital expenditures of $15.2 million related to WesternZagros' initiative in
Kurdistan were also incurred in 2006. The AOSP, and the expansion plans
associated with this asset, will continue to drive Western's capital
expenditures going forward, particularly as the AOSP embarks on its continuous
construction expansion strategy.
December 31 ($ millions) 2006 2005
- ----------------------------------------------------------------------------------------
Project Related Capital
Profitability Capital, Production Optimization and Mobile Equipment 42.7 31.2
Growth Initiatives 184.6 14.6
Sustaining Capital 23.8 5.8
- ----------------------------------------------------------------------------------------
Total Project Related Capital 251.1 51.6
Kurdistan Project 15.2 9.5
In-situ Projects (Ells River and Western-operated) 25.0 0.8
Business Development and General Corporate Expenditures 3.4 3.0
Capitalized Insurance Costs 3.8 4.4
Capitalized Interest 2.8 --
- ----------------------------------------------------------------------------------------
Gross Capital Expenditures 301.3 69.4
Insurance Proceeds -- (22.5)
- ----------------------------------------------------------------------------------------
Net Capital Expenditures 301.3 46.8
========================================================================================
Analysis of Cash Resources
Cash balances totalled $3.1 million at the end of 2006, slightly lower than the
$5.6 million as at December 31, 2005. Cash inflows included net operating cash
flow of $228.4 million, drawdowns of long-term debt of $36.0 million, equity
proceeds of $4.9 million from the exercise of stock options and a working
capital decrease of $30.8 million. Cash outflows included capital expenditures
of $301.3 million and obligations under capital leases of $1.3 million.
Modest draws under the Revolving Facility were necessary to fund
Western's share of capital expenditures during 2006. Additional capital
expenditures are anticipated as construction of Expansion 1 accelerates.
Western's 2007 capital expenditure program is forecasted to be $715 million,
which will be funded in part by cash flow from operations and existing bank
lines. It it likely that additional sources of funding will be required to
provide for any shortfall in cash requirements for 2007, as well as subsequent
years leading up to the completion of Expansion1. Western also anticipates
several years of negative free cash flow, which is the difference between cash
flow from operations less capital expenditures. Western will critically assess
and determine the most attractive financing structures to bridge this financing
gap.
Contractual Obligations and Commitments
Western has assumed various contractual obligations and commitments in the
normal course of its operations. Summarized below are significant financial
obligations as of February 22, 2007, and represent future cash payments
required under existing contractual agreements. Western has entered into these
agreements either directly or as an Owner in the Joint Venture. Feedstocks are
included in the table below to comply with continuous disclosure obligations in
Canada; however, Western could sell these products back to the market and
eliminate any negative impact in the event of operational curtailments.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
Payments Due By Period
($) <1 Year 1 - 3 Years 4 - 5 Years After 5 Years Total
- ----------------------------------------------------------------------------------------------------------
US$450 Million Senior Secured Notes -- -- -- 524,385 524,385
Revolving Credit Facility (1) -- -- -- 77,000 77,000
Obligations Under Capital Lease 1,341 2,680 2,680 42,227 48,928
Option Premium Liability 25,971 69,775 -- -- 95,426
Feedstocks 106,352 39,612 20,726 58,727 225,417
Pipelines and Utilities 33,300 78,801 86,347 558,641 757,089
Mobile Equipment Lease 5,242 32,174 8,625 -- 46,041
Exploration Work 8,728 500 -- -- 9,228
- ----------------------------------------------------------------------------------------------------------
Total Contractual Obligations 180,434 223,542 118,378 1,260,980 1,783,334
==========================================================================================================
(1) The Revolving Credit Facility is a three-year bank facility maturing on
October 31, 2009, extendible annually at the lenders' discretion. Management
considers this to be part of our long-term capital structure.
(2) In addition, we have an obligation to fund Western's share of the
Project's Pension Fund and have made commitments related to our risk management
program: see Notes 17 and 18, respectively, of the Consolidated Financial
Statements.
Insurance Claims
At the end of 2006, Western had only one large claim outstanding, namely, $200
million pursuant to our Cost Overrun and Project Delay Policy, commonly
referred to as Section IV. In the second quarter of 2005, the Joint Venture was
successful in settlement proceedings with the named insurers on Section III in
the amount of $220 million ($44 million net to Western). To date, Western has
received $19.4 million of its share of this settlement amount as certain
insurers on Section III are also named insurers on Section IV, and they have
withheld insurance proceeds payable to Western. Western is optimistic that it
will receive the outstanding amounts upon conclusion of Section IV arbitration
proceedings. Costs and premiums associated with Section III were capitalized as
Western was pre-commercial operations at that time and, as such, amounts
received pursuant to this settlement were reported as a reduction in capital
assets. Similar to Section III, there are amounts being withheld by certain
insurers relating to the January 6, 2003 physical property damage claim,
commonly referred to as Section I. To date, Western has received $16.1 million
on this claim, with $19.4 million outstanding.
Arbitration proceedings under the terms of Section IV of Western's Cost
Overrun and Project Delay insurance policy continue with formal hearings
expected to commence during 2007. A judgement is expected subsequent to this
process, although Western makes no representations as to the timing or results
of this arbitration. In preparation of the arbitration process, several
examinations for discovery have been conducted with key individuals over the
last several months. In order to preserve Western's rights regarding this
policy, Western filed insurance claims for the full limit of the policy, namely
$200 million, and Western will also be seeking interest and punitive and
aggravated damages.
Due to the proceedings with Section IV, amounts that were previously
settled at the Joint Venture level, but where common carriers exist on
Western's proprietary policy, have not yet been paid to our pro rata share.
With the addition of Section 1 (fire and freeze damage), Section III (Joint
Venture delay and start-up) and Section IV, Western has a total of $244 million
($1.52 per share) outstanding in insurance claims. Other than amounts collected
up to December 31, 2006, no outstanding amounts are recorded in Western's
financial statements nor are they included in any of our financing strategies.
Flow-through Shares
In connection with the issuance of flow-through shares in 2001 and 2002,
Western renounced Canadian exploration expenses in the aggregate amount of
$29.2 million and $19.5 million, respectively. Under the mechanics of
renouncing qualifying expenditures pursuant to flow-through shares, individual
shareholders can reduce their income subject to personal income taxes.
Commencing in the latter part of the year, discussions were held between the
AOSP and the Canada Revenue Agency ("CRA") regarding the proper
characterization of certain expenditures included in the Canadian exploration
expenses in those years. If the CRA successfully asserts a change in the
characterization of these expenditures, any resulting reduction in the
renunciations could impact Western's obligations under the indemnity provisions
in the subscription agreements and in turn, will impact Western's reported
results. The subscription agreements for such flow-through shares stipulate
that Western has indemnified subscribers for an amount equal to the tax payable
and any associated interest by the subscribers if such renunciations are
reduced under the Income Tax Act (Canada).
Fourth Quarter 2006
The completion of the first full turnaround at both the Mine and the Upgrader
in the second quarter of 2006 set the stage for strong production in the latter
half of 2006. Fourth quarter production averaged 35,500 barrels per day net to
Western, representing the second consecutive quarter of significant production
volumes. Production in the fourth quarter nearly eclipsed the record set in the
third quarter of 2005, where production averaged 35,600 barrels per day net to
Western.
During the fourth quarter, cash flow from operations of $91.1 million
financed virtually all the capital expenditures during the quarter; however,
both underlying crude prices and heavy crude oil differentials contributed to
lower overall price realizations. Crude oil averaged US$60.21 per barrel,
considerably lower than the average crude prices experienced in the prior three
quarters. The crude oil heavy differential widened to approximately 35 per cent
of WTI compared to the prior two quarters, where observed differentials
approximated 26 per cent to 28 per cent of WTI. As underlying crude oil prices
decline, there is a corresponding decrease in Western's cash flow and
profitability since Western's revenues are sensitive to fluctuations in crude
oil prices.
A weakening of the US/Cdn exchange rate, which results in more Canadian
funds received on US denominated crude sales, partially offset the negative
impacts of the changes in crude oil prices and the heavy oil differential. The
average exchange rate for the fourth quarter was US/Cdn$0.8778 compared to
US/Cdn$0.8919 for the third quarter of 2006. Due to these factors, Western's
sales price realizations totalled $55.08 per barrel in the fourth quarter
compared to $67.42 per barrel for the third quarter. In the fourth quarter of
2006, operating costs were reduced to $20.12 per processed barrel compared to
$22.38 per processed barrel in the third quarter. This reduction in per unit
costs is largely the result of increased production in the fourth quarter
compared to the previous quarter which provides greater economies of scale,
partially offset by a six per cent increase in underlying natural gas prices in
the fourth quarter. AECO gas closing settlement prices averaged $6.44 Cdn/mcf
for the fourth quarter compared to $6.10 Cdn/mcf for the third quarter.
OUTLOOK FOR 2007
Western cautions readers and prospective investors of our securities not to
place undue reliance on forward-looking information as by its nature, this
information is based on current expectations regarding future events that
involve a number of assumptions, inherent risks and uncertainties, which could
cause actual results to differ materially from those anticipated by Western.
These risks include, but are not limited to, risks of commodity prices in the
marketplace for crude oil and natural gas; risks associated with the
extraction, treatment and upgrading of mineable oil sands deposits; risks
surrounding the level and timing of capital expenditures required to fulfill
the Project's growth strategy; risks of securing adequate and timely downstream
solutions for future volumes; 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 or expansion strategy; risk that
the other Joint Venture Owners may not meet their obligations to the Project,
expansions thereof or related agreements with Western; risk that the other
Joint Venture Owners may not agree with Western on matters relating to the
Project including Expansion 1; 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; risk of changes in governmental
regulation that could affect the viability of the Project; risks surrounding
major interruptions in operational performance together with adequacy and
timeliness of insurance coverage thereto; risks associated with political and
regulatory instability in Kurdistan; risks associated with ratification of the
EPSA including the possibility of changes to its terms; 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.
For 2007, Western remains focused on its key initiatives: the AOSP and
the execution of Expansion 1; in-situ evaluation and development of both
Western's in-situ leases and the Chevron-operated Ells River Project;
evaluating and identifying downstream integration opportunities; and supporting
WesternZagros as it pursues its initiative in Kurdistan.
Western's 2007 capital budget is $715 million, $655 million of which
relates directly to the AOSP, $35 million is budgeted for in-situ exploration
and development for both Chevron's and Western's in-situ leases, $20 million is
directed to WesternZagros' initiative in Kurdistan and $5 million is allocated
to other corporate capital items. Of the total budget, $555 million or 78 per
cent is allocated to Expansion 1 of the AOSP. Capital expenditures relating to
Expansion 1 are expected to continue to grow over the next couple of years as
development efforts accelerate. Western anticipates its share of production
from the AOSP to average approximately 33,000 to 35,000 barrels per day in
2007. Western is evaluating capitalization strategies and structures in order
to fund our share of forecasted capital expenditures which, for AOSPExpansion
1, is anticipated to be comprised solely of cash flow from operations together
with incremental borrowings. If commodity prices continue to weaken as observed
in the early part of 2007, Western's strategic hedging program implemented in
fall of 2005 provides downside protection on the majority of our 2007
production and maintains a base level of cash flow. This program is monitored
on an ongoing basis to ensure its specific components continue to achieve the
overall objectives.
Western anticipates research and business development expenses to be
approximately $67 million in 2007, with 52 per cent of this amount dedicated to
projects at the Joint Venture level. The balance is earmarked for technology
efforts which may benefit mining and in-situ extraction and recovery
techniques, assessments and reviews associated with identifying a downstream
opportunity for Western's share of bitumen production, in-situ development and
corporate administrative expenses stemming from efforts in Kurdistan.
In 2007, Western will continue to pursue downstream integration
opportunities to maximize value from its growing oil sands resources and
undeveloped acreage position. Related to these initiatives, Western intends to
explore and pursue alternatives that enhance the full value of our assets and
future growth potential. This may result in an acquisition or sale of assets,
merger or other corporate transaction. Western's advisors, Goldman, Sachs & Co.
and TD Securities Inc. will be assisting in these activities which may involve
contacting third parties. There can be no assurances that any of these
activities will result in the consummation of an agreement or transaction or
result in any change to Western's current ongoing business strategy.
FUTURE EXPANSIONS
Subsequent to year end, on January 24, 2007, Western announced future growth
plans for the AOSP with proposed permit applications that would enable
production from Expansions 3 through 5 of the Project. These plans would see
mineable production increasing to approximately 770,000 barrels per day or
154,000 barrels per day net to Western. These volumes, together with
anticipated production of in excess of 50,000 barrels per day from in-situ
development would increase Western's share of total bitumen production to more
than 200,000 barrels per day over the next 15 to 20 years. We also see
potential for mining expansions, beyond Expansion 5, based on the resource
potential of the unevaluated leases associated with the AOSP.
Seeking early stakeholder and regulator support is fundamental to the
AOSP's growth strategy. The public disclosure documents were issued in order to
start the process of the AOSP's next phase of oil sands development, including
the proposed Jackpine Mine Expansion, and an additional mine, called Pierre
River Mine, on the west side of the Athabasca River. The AOSP's growth strategy
includes the approved Muskeg River Mine permit at 270,000 barrels per day and
the approved Jackpine Mine permit at 200,000 barrels per day. The Jackpine Mine
Expansion is a proposed expansion of the Jackpine Mine to 300,000 barrels per
day, representing Expansions 1 through 3. The Pierre River Mine represents
Expansions 4 and 5, initially on Leases 9 and 17. Actual timing for these
expansion projects will depend on market conditions, key economic indicators,
the ability to meet sustainable development criteria and the outcome of the
regulatory process.
RISK AND SUCCESS FACTORS RELATING TO WESTERN
Western faces a number of risks that we need to manage in conducting our
business affairs. The following discussion identifies some of our key areas of
exposure and, where applicable, sets forth measures undertaken to reduce or
mitigate these exposures. A complete discussion of risk factors that may impact
our business is provided in our Annual Information Form.
Financial Risks
The following table details the sensitivities of Western's cash flow and net
earnings per share to certain relevant operating factors of the Project for
2007.
SENSITIVITY ANALYSIS
Basic Normalized
Cash Flow Cash Flow Earnings Earnings
Variable Base Case Variation ($ millions) per Share ($) ($ millions) per Share ($)
- -----------------------------------------------------------------------------------------------------------------
Production (bbls/d) 34,000 1,000 bbls/day 19.37 0.12 11.76 0.07
Oil Prices $60.00 US$1.00 12.02 0.07 7.55 0.05
Non-Gas Operating Costs $16.53 $1.00/bbl 12.60 0.08 8.64 0.05
Gas Prices (1) $ 7.71 $0.10/mcf 0.80 0.00 0.51 0.00
Foreign Exchange (2) $ 0.87 US/Cdn $0.01 7.25 0.04 6.22 0.04
=================================================================================================================
(1) Each $1.00 per thousand cubic feet change in gas price results in a
change of $ 0.50 per barrel in operating cost.
(2) Excludes unrealized foreign exchange gains or losses on long-term
monetary items. The impact of the Canadian dollar strengthening by US$0.01
would increase net earnings by $4.1 million based on December 31, 2006, US
dollar denominated debt levels.
Western's financial results depend on, amongst other factors, the
prevailing price of crude oil and the US/Cdn currency exchange rate. Oil prices
and currency exchange rates fluctuate significantly in response to supply and
demand factors beyond our control, which could have an impact on future
financial results. Any prolonged period of low oil prices could result in a
decision by the Joint Venture Owners to suspend or reduce production. Any such
suspension or reduction of production would result in a corresponding decrease
in our future revenues and earnings and could expose Western to significant
additional expense as a result of certain long-term contracts. In addition,
because natural gas comprises a substantial part of variable operating costs,
any prolonged period of high natural gas prices could negatively impact our
financial results. Hedging activities could result in losses or limit the
benefit of certain commodity price increases.
Western's debt level and restrictive covenants will have an important
impact on our future operations. Our ability to make scheduled payments or to
refinance our debt obligations depends on our financial and operating
performance which, in turn, depends on prevailing industry and general economic
conditions beyond our control. There can be no assurance that our operating
performance, cash flow, and capital resources will be sufficient to repay our
debt and other obligations in the future.
To mitigate Western's exposure to these financial risks and provide a
stable financial footing as we enter Expansion 1 of the AOSP, we completed a
strategic crude oil risk management program. The overriding objective of the
risk management program was to ensure the ability to fund significant capital
expenditures in the event of a precipitous drop in the crude oil price. The
program itself is a series of put and call options. Western purchased puts at
various levels and financed the cost of these puts, in part, by selling call
options on lower volumes over the same time period. The net cost of the program
was US$3.74 per put barrel. All options bought and sold were executed on a
deferred basis. Hence, Western made no upfront cash payment for these options
but will do so as each monthly option expires. Western deferred the options in
order to properly match the underlying cash flow but, more importantly, the
implicit interest rate within the deferred options pricing was lower than
Western's incremental borrowing rate. An interest expense associated with this
program is a result of this deferral strategy.
The program is summarized as follows:
Period (calendar year)
- -------------------------------------------------------------------------------
2007 2008 2009
- -------------------------------------------------------------------------------
Put options purchased (bbls/d) 20,000 20,000 20,000
Call options sold (bbls/d) 10,000 15,000 15,000
Average put strike price (US$/bbl) 52.50 54.25 50.50
Average call strike price (US$/bbl) 92.50 94.25 90.50
===============================================================================
($ thousands) 2006 2005
- -------------------------------------------------------------------------------
Risk Management Asset - Beginning of Period 98,426 --
Net Premium -- 84,976
Unrealized Gain (Loss) on Risk Management Asset 72,118 13,450
- -------------------------------------------------------------------------------
Risk Management Asset - End of Period 26,308 98,426
Less: Current Portion 7,601 --
- -------------------------------------------------------------------------------
18,707 98,426
===============================================================================
Western is required to finance its share of the Project's operating costs
in light of a volatile commodity price environment and ramp-up challenges.
Should insufficient cash flow be generated from operations, additional
financing may be required to fund capital projects and future expansion
projects. If there is a business interruption, Western may require additional
financing to fund its activities until Business Interruption Insurance proceeds
are received.
Operational and Business Risks
Western currently has only one producing asset. As such, the vast majority of
our capital expenditures is directly or indirectly related to oil sands
construction, development and expansion, with all of our operating cash flow
derived from oil sands operations.
Western is subject to the operational risks inherent in the oil sands
business. Any unplanned operational outage or slowdown can impact production
levels, costs and financial results. Factors that could influence the
likelihood of this include, but are not limited to, uncertainties within the
ore body, extreme weather conditions and mechanical difficulties.
Western sells its share of synthetic crude oil production to refineries
in North America. These sales compete with the sales of both synthetic and
conventional crude oil. Other suppliers of synthetic crude oil exist and there
are several additional projects being contemplated. If undertaken and
completed, these projects may result in a significant increase in the supply of
synthetic crude oil to the market. In addition, not all refineries are able to
process or refine synthetic crude oil. There can be no assurance that
sufficient market demand will exist at all times to absorb Western's share of
the Project's synthetic crude oil production at economically viable prices.
As an Owner in the AOSP, Western actively participates in operational
risk management programs implemented by the Joint Venture to mitigate the above
risks. Western's exposure to operational risks is also managed by maintaining
appropriate levels of insurance. To that end, in October 2006, Western placed
US$900 million of Property and Business Interruption Insurance, up from US$800
million in 2005 as well as US$100 million of Liability Insurance to protect our
ownership interest against losses or damages to the owners' facilities, to
preserve our operating income and to protect against our risk of loss to third
parties.
The Project depends on successful operation of facilities owned and
operated by third parties. The Joint Venture Owners are party to certain
agreements with third parties to provide for, among other things, the following
services and utilities:
o Pipeline transportation is provided through the Corridor Pipeline;
o Electricity and steam are provided to the Mine and the Extraction
Plant from the Muskeg River cogeneration facility;
o Transportation of natural gas to the Muskeg River cogeneration
facility is provided by the ATCO pipeline;
o Hydrogen is provided to the Upgrader from the HMU and Dow Chemicals
Canada Inc., or Dow; and
o Electricity and steam are provided to the Upgrader from the
Upgrader cogeneration facility.
All of these third-party arrangements are critical to the successful
operation of the Project. Disruptions related to these facilities could have an
adverse impact on future financial results.
Western may be faced with competition from other industry participants in
the oil sands business. This could take the form of competition for skilled
people, increased demands on the Fort McMurray infrastructure (housing, roads,
schools, etc.), or higher prices for the products, equipment and services
required to operate and maintain the plant. The Joint Venture has significant
expansion plan, and the strong working relationships the Project has developed
with the trade unions will be an important factor in its future activities. The
Joint Venture's relationship with its employees and provincial building trade
unions is important to its future because poor productivity and work
disruptions may adversely affect the Project - whether in construction or in
operations.
In 2006, WesternZagros, a wholly-owned subsidiary of Western, announced
an initiative to explore for conventional oil and gas in the Federal Region of
Kurdistan, in northern Iraq. Oil and gas exploration activities have their own
inherent risks. However, risks regarding this initiative are heightened due to
the political and economic instability in Iraq. Agreements between the central
government an the regional provinces have yet to been finalized, including the
petroleum law, which results in risks related to legal, regulatory and tax
environments.
Environmental Risks
Canada is a signatory to the United Nations Framework Convention on Climate
Change and has ratified the Kyoto Protocol established thereunder to set
legally binding targets to reduce nationwide emissions of carbon dioxide,
methane, nitrous oxide and other so-called "greenhouse gases". The Project may
be a significant producer of some greenhouse gases covered by the treaty. The
Government of Canada has put forward a Climate Change Plan for Canada which
suggests further legislation will set greenhouse gases emission reduction
requirements for various industrial activities, including oil and gas
production. Future federal legislation, together with existing provincial
emission reduction legislation, such as in Alberta's Climate Change and
Emissions Management Act, may require the reduction of emissions and/or
emissions intensity from the Project. The direct or indirect costs of such
legislation may adversely affect the Project. There can be no assurance that
future environmental approvals, laws or regulations will not adversely impact
the Owners' ability to operate the Project or increase or maintain production
or will not increase unit costs of production. Equipment from suppliers that
can meet future emission standards or other environmental requirements may not
be available on an economic basis, or at all, and other methods of reducing
emissions to required levels may significantly increase operating costs or
reduce output.
Western will be responsible for compliance with terms and conditions set
forth in the Project's environmental and regulatory approvals and all laws and
regulations regarding the decommissioning and abandonment of the Project and
reclamation of its lands. The costs related to these activities may be
substantially higher than anticipated. It is not possible to accurately predict
these costs since they will be a function of regulatory requirements at the
time and the value of the equipment salvaged. In addition, to the extent
Western does not meet the minimum credit rating required under the Joint
Venture Agreement, we must establish and fund a reclamation trust fund. Western
currently does not hold the minimum credit rating. Even if we did hold the
minimum credit rating, in the future, it may be determined that it is prudent,
or be required by applicable laws or regulations, to establish and fund one or
more additional funds to provide for payment of future decommissioning,
abandonment and reclamation costs. Even if we conclude that such a fund is
prudent or required, we may lack the financial resources to do so.
The Joint Venture Owners have established programs to monitor and report
on environmental performance including reportable incidents, spills and
compliance issues. In addition, comprehensive quarterly reports are prepared
covering all aspects of health, safety and sustainable development on Lease 13
and the Upgrader to ensure that the Project is in compliance with all laws and
regulations and that management are accountable for performance set by the
Joint Venture Owners.
NON-GAAP FINANCIAL MEASURES
Western includes cash flow from operations per share, netback per barrel, net
earnings excluding unrealized gain/(loss), net earnings excluding unrealized
gain/(loss) per share and earnings before interest, taxes, depreciation,
depletion and amortization, stock-based compensation, accretion on asset
retirement obligation, foreign exchange gains and risk management gains
("EBITDAX") as investors may use this information to better analyze our
operating performance. Western also includes certain per barrel information,
such as realized crude oil sales price and operating costs, to provide per unit
numbers that can be compared against industry benchmarks, such as the Edmonton
PAR benchmark. The additional information should not be considered in isolation
or as a substitute for measures of operating performance prepared in accordance
with Canadian Generally Accepted Accounting Principles ("GAAP"). Non-GAAP
financial measures do not have any standardized meaning prescribed by Canadian
GAAP and are therefore unlikely to be comparable to similar measures presented
by other issuers. Management believes that, in addition to Net Earnings (Loss)
per Share and Net Earnings (Loss) Attributable to Common Shareholders (both
Canadian GAAP measures), cash flow from operations per share, normalized net
earnings, normalized net earnings per share and EBITDAX provide a better basis
for evaluating its operating performance, as they both exclude fluctuations on
the US dollar denominated Senior Secured Notes, risk management gains (losses)
and certain other non-cash items, such as depreciation, depletion and
amortization, and future income tax recoveries. In addition, EBITDAX provides a
useful indicator of our ability to fund financing costs and any future capital
requirements.
CRITICAL ACCOUNTING ESTIMATES
Western's critical accounting estimates are defined as those estimates that
have a significant impact on the portrayal of its financial position and
operations and that require management to make judgments, assumptions and
estimates in the application of Canadian GAAP. Judgments, assumptions and
estimates are based on historical experience and other factors that Management
believe to be reasonable under current conditions. As events occur and
additional information is obtained, these judgments, assumptions and estimates
may be subject to change. Our critical accounting policies and estimates have
been reviewed and approved by our Audit Committee, in consultation with
Management. We believe the following are the critical accounting estimates used
in the preparation of our Consolidated Financial Statements. Our significant
accounting policies can be found in note 2 to the Consolidated Financial
Statements.
Property, Plant and Equipment ("PP&E")
Western capitalizes costs specifically related to the acquisition, exploration,
development and construction of the Project and other initiatives. This
includes interest, which is capitalized during the construction and start-up
phase for each project. Conventional crude oil and in-situ properties are
accounted for in accordance with the full cost method, whereby all costs
associated with the acquisition of, exploration for and the development of
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.
Depletion on crude oil properties is provided over the life of proved and
probable reserves on a unit of production basis and commences when the
facilities are substantially complete and after commercial production has
begun. Other PP&E assets are depreciated on a straight-line basis over their
useful lives, except for lease acquisition costs and certain Mine assets, which
are amortized and depreciated over the life of proved and probable reserves.
Reserve estimates can have a significant impact on earnings, as they are a key
component to the calculation of depletion. A downward revision in the reserve
estimate would result in increased depletion and a reduction of earnings.
PP&E assets are reviewed for impairment whenever events or conditions
indicate that their net carrying amount may not be recoverable from estimated
future cash flows. If an impairment is identified the assets are written down
to the estimated fair market value. The calculation of these future cash flows
are dependent on a number of estimates, which include reserves, timing of
production, crude oil price, operating cost estimates and foreign exchange
rates. As a result, future cash flows are subject to significant Management
judgment.
Derivative Financial Instruments
Financial instruments that do not qualify as hedges or have not been designated
as hedges under Accounting Guideline 13, are recorded using the mark-to-market
method of accounting, whereby instruments are recorded in the Consolidated
Balance Sheet as either an asset or a liability with changes in fair value
recognized in net earnings. The fair values of such financial instruments are
based on an estimate of the amounts that would have been received or paid to
settle these instruments prior to maturity. Financial instruments that do
qualify as hedges under Accounting Guideline 13, and are designated as hedges,
are not recognized on the Consolidated Balance Sheet and gains and losses on
the hedge are deferred and recognized in revenues in the period the hedge sale
transaction occurs.
Asset Retirement Obligation
Western recognizes an asset and a liability for asset retirement obligations in
the period in which they are incurred by estimating the fair value of the
obligation. We determine the fair value by first estimating the expected timing
and amount of cash flow, using third-party costs that will be required for
future dismantlement and site restoration, and then calculating the present
value of these future expenditures using a credit adjusted risk free rate
appropriate for Western. Any change in timing or amount of the cash flow
subsequent to initial recognition results in a change in the asset and
liability, which then impacts the depletion on the asset and the accretion
charged on the liability. Estimating the timing and amount of third-party cash
flow to settle this obligation is inherently difficult and is based on
Management's current experience.
Stock-based Compensation Plans
Western recognizes stock-based compensation as part of general and
administrative expense in the Consolidated Statements of Operation for all
common share options ("options") and Performance Share Units ("PSU's") after
January 1, 2003, with a corresponding increase in Contributed Surplus in the
Consolidated Balance Sheets. The expense is based upon the fair value of the
options and PSU's determined at the grant date utilizing the Black-Scholes
option pricing model and the Monte-Carlo Simulation model, respectively.
Western also has a Deferred Share Unit Plan which is accounted for on a
mark-to-market basis, whereby a liability and compensation expense are recorded
for each period based upon the number of Deferred Share Units outstanding and
the current market price of Western's shares.
Western, as an owner of the AOSP, shares in the related costs associated
with the AOSP's stock-based compensation plans. The AOSP's plans involve Stock
Appreciation Rights which may require settlement with cash payments. The
expense recognized as part of operating expense in the Consolidated Statements
of Operations and as part of Accounts Payable and Accrued Liabilities in the
Consolidated Balance Sheets is determined at the balance sheet date based upon
the Black-Scholes option pricing model.
Income Tax
Western follows the liability method of accounting for income taxes whereby
future income taxes are recognized based on the differences between the
carrying values of assets and liabilities reported in the Consolidated
Financial Statements and their respective tax basis. Future income tax assets
and liabilities are recognized at the tax rates at which Management expects the
temporary differences to reverse. Management bases this expectation on future
earnings, which require estimates for reserves, timing of production, crude oil
price, operating cost estimates and foreign exchange rates. As a result, future
earnings are subject to significant Management judgment and changes.
Employee Future Benefits
Western, as an owner of the AOSP, has a defined benefit pension plan for
employees of the AOSP. Costs associated to this plan are determined using the
projected benefit method prorated on length of service and reflects the AOSP's
best estimate of expected plan investment performance, salary escalation,
retirement ages of employees, withdrawal rates and mortality rates. Expected
return on plan assets is based on the fair value of those assets and the
obligation is discounted using a market interest rate at the beginning of the
year based on high quality corporate debt instruments. Pension expense includes
the cost of pension benefits earned during the current year, the interest cost
on the pension obligations, the expected return on pension plan assets, the
amortization of adjustments arising from pension plan amendments and the excess
of the net actuarial gain or loss over 10 per cent of the greater of benefits
obligation and the fair value of plan assets.
Arrangements Containing a Lease
Western, through its 20 per cent ownership interest in AOSP, is party to a
number of long-term third-party arrangements to provide for pipeline
transportation of bitumen and upgraded products, and to provide electrical and
thermal energy. With the issuance of the Emerging Issues Committee Abstract 150
("EIC-150"), we are required to determine whether any arrangements agreed to,
committed to, or modified after January 1, 2005 contain a lease that is within
the scope of CICA Section 3065 "Leases". To date, none of these long-term
third-party contracts were agreed to, committed to, or modified after January
1, 2005 and, therefore, we are not required to consider whether they contain a
lease that is within the scope of CICA Section 3065. However, the AOSP or
Western may request modification of these agreements in the future to meet
certain requirements related to the AOSP growth plans. Any modifications may
result in certain of these long-term third-party arrangements being treated as
capital leases, thereby, increasing both Western's assets and liabilities on
its Consolidated Balance Sheet.
CHANGES IN ACCOUNTING POLICY
Stock-based Compensation for Employees Eligible to Retire Before the Vesting
Date
For the year ending December 31, 2006, Western retroactively adopted Emerging
Issues Committee Abstract 162 ("EIC-162"). EIC-162 requires the Corporation to
recognize stock-based compensation expense for awards granted to employees
eligible for retirement under stock-based compensation plans that contain
provisions that allow an employee to continue vesting in an award in accordance
with the stated vesting terms after the employee has retired. During 2006, the
Corporation amended the stock option and performance share unit plans allow an
employee to continue vesting in an award in accordance with the stated vesting
terms after the employee has retired and, accordingly, stock-based compensation
expense of $3.6 million has been included in general and administrative
expense, representing the additional compensation expense recognized for
employees eligible for retirement during the vesting period. There is no impact
to the Consolidated Financial Statements as at December 31, 2005 as no such
retirement provisions existed during this period.
Non-monetary Transactions
On January 1, 2006, Western prospectively adopted CICA Handbook Section 3831,
"Non-Monetary Transactions" which replaces Section 3830, "Non-Monetary
Transactions". Section 3831 establishes standards for the measurement and
disclosure of non-monetary transactions. Section 3830 prescribes that exchanges
of non-monetary transactions should be measured based on the fair value of the
assets exchanged, while providing an exception for non-monetary exchanges in
transactions which do not result in the culmination of the earnings process.
Section 3831 eliminates this exception provided in Section 3830 and replaces it
with an exception for exchanges of non-monetary assets that do not have
commercial substance. A transaction has commercial substance when the entity's
future cash flows are expected to change significantly as a result of the
transaction. There is no impact on the Consolidated Financial Statements as
Western did not have exchanges of non-monetary transactions after January 1,
2006 within the scope of Section 3831.
Implicit Variable Interests under AcG-15
On January 1, 2006, Western adopted Emerging Issues Committee Abstract 157
("EIC-157"). EIC-157 requires that a reporting enterprise consider whether it
holds an implicit variable interest in the Variable Interest Entity ("VIE") or
potential VIE. The determination of whether an implicit variable interest
exists should also be based on whether the reporting enterprise may absorb
variability on the VIE or potential VIE. The Corporation has entered into
operating leases, as described in note 19(a) to the Consolidated Financial
Statements, with a VIE. These operating leases as structured do not meet the
criteria for consolidation by the Corporation and therefore, the adoption of
this accounting policy had no impact on Western's Consolidated Financial
Statements.
Conditional Asset Retirement Obligations
On January 1, 2006, Western retroactively adopted Emerging Issues Committee
Abstract 159 ("EIC-159"). EIC-159 clarifies that the term "conditional asset
retirement obligation" as used in CICA 3110, "Asset Retirement Obligations"
refers to a legal obligation to perform an asset retirement activity in which
the timing and (or) method of settlement are conditional on a future event that
may or may not be within the control of the entity. EIC-159 requires a
liability to be recognized for the fair value of a conditional asset retirement
obligation if the fair value of the liability can be reasonably estimated; an
entity to apply expected present value technique if certain conditions exist
indicating sufficient information to reasonably estimate conditional asset
retirement obligation; and that a liability should be recognized initially in
the period in which sufficient information becomes available to estimate a
conditional asset retirement obligations fair value. There is no impact on the
Consolidated Financial Statements from the retroactive adoption of EIC-159.
FUTURE CHANGES IN ACCOUNTING POLICY
Financial Instruments
The CICA issued Section 3855, "Financial Instruments - Recognition and
Measurement", which prescribes when a financial instrument is to be recognized
on the balance sheet and at what amount - sometimes using fair value, other
times using cost-based measures. This Section also specifies how financial
instrument gains and losses are to be presented. A financial instrument is any
contract that gives rise to a financial asset of one party and a financial
liability or equity instrument of another party. These may include loans and
notes receivable and payable, investments in debt and equity securities and
derivative contracts such as forwards, swaps and options. Other significant
accounting implications arising on adoption of Section 3855 include the initial
recognition of certain financial guarantees at fair value on the balance sheet
and the requirement to expense or use of the effective interest rate method of
amortization for any transaction costs or fees, premiums or discounts earned or
incurred for financial instruments measured at amortized cost. This Section
applies to interim and annual financial statements relating to fiscal years
beginning on or after October 31, 2006. Western will adopt this Section on
January 1, 2007 and does not expect there to be any material impact to the
Consolidated Financial Statements upon adoption of the standard on January 1,
2007.
Hedges
The CICA issued Section 3865, "Hedges", which replaces the guidance formerly in
Section 1650, "Foreign Currency Translation" and Accounting Guideline 13,
"Hedging Relationships" by specifying how hedge accounting is applied and what
disclosures are necessary when it is applied. This Section applies to interim
and annual financial statements relating to fiscal years beginning on or after
October 31, 2006. Western plans to adopt this Section on January1, 2007 and
does not expect there to be any material impact on the Consolidated Financial
Statements upon adoption of the standard on January 1, 2007.
Financial Instruments - Disclosures and Presentations
The CICA issued Section 3862, "Financial Instruments - Disclosures", which
modifies the disclosure requirements of Section 3861, "Financial Instruments -
Disclosures and Presentation" and Section 3863, "Financial Instruments -
Presentations", which carries forward unchanged the presentation requirements
for financial instruments of Section3861. Section 3862 requires entities to
provide disclosures in their financial statements that enable users to evaluate
the significance of financial instruments on the entity's financial position
and its performance and the nature and extent of risks arising from financial
instruments to which the entity is exposed during the period and at the balance
sheet date, and how the entity manages those risks. Section 3863 establishes
standards for presentation of financial instruments and non-financial
derivatives. It deals with the classification of financial instruments, from
the perspective of the issuer, between liabilities and equities, the
classification of related interest, dividends, losses and gains, and
circumstances in which financial assets and financial liabilities are offset.
These Sections apply to interim and annual financial statements relating to
fiscal years beginning on or after October 1, 2007. Early adoption is permitted
at the same time an entity adopts other standards relating to the accounting
for financial instruments. Western plans to adopt this Section on January 1,
2007 and does not expect there to be any material impact on the Consolidated
Financial Statements upon adoption of the standard on January 1, 2007.
Comprehensive Income
The CICA issued Section 1530, "Comprehensive Income", which established new
standards for reporting the display of comprehensive income. Comprehensive
income is the change in equity (net assets) of an enterprise during a reporting
period from transactions and other events and circumstances from non-owner
sources. It includes all changes in equity during the period except those
resulting from investments by owners and distributions to owners. This Section
applies to interim and annual financial statements relating to fiscal years
beginning on or after October 31, 2006. Earlier adoption is permitted only as
at the beginning of a fiscal year ending on or after December 31, 2004. Western
plans to adopt this Section on January 1, 2007 and does not expect there to be
any material impact on the Consolidated Financial Statements upon adoption of
the standard on January 1, 2007.
Equity
The CICA issued Section 3251, "Equity", which replaces Section 3250, "Surplus".
It establishes standards for the presentation of equity and changes in equity
during a reporting period. This Section applies to interim and annual financial
statements relating to fiscal years beginning on or after October 31, 2006.
Western plans to adopt this Section on January 1, 2007 and does not expect
there to be any material impact on the Consolidated Financial Statements upon
adoption of the standard on January 1, 2007.
Accounting Changes
The CICA issued Section 1506, "Accounting Changes", which replaces former
Section 1506. The Section establishes criteria for changing accounting
policies, together with the accounting treatment and disclosure of changes in
accounting policies and estimates, and correction of errors. This Section
applies to interim and annual financial statements relating to fiscal years
beginning on or after January 1, 2007. Western plans to adopt this Section on
January 1, 2007 and does not expect there to be any material impact on the
Consolidated Financial Statements upon adoption of the standard on January 1,
2007.
Determining the Variability to be Considered in Applying AcG-15
The Emerging Issues Committee issued Abstract 163, "Determining the Variability
to be Considered in Applying AcG-15", which addresses how an enterprise should
determine the variability to be considered in applying AcG-15, "Consolidation
of Variable Interest Entities". This Abstract applies to all entities
(including newly created entities) with which that enterprise first becomes
involved, and to all entities previously required to be analyzed under AcG-15
when a reconsideration event has occurred pursuant to paragraph 11 of AcG-15,
beginning the first day of the interim or annual reporting period beginning on
or after January 1, 2007. Retrospective application to the date of the initial
application of AcG-15, is permitted but not required. Western plans to adopt
this Section on January 1, 2007 and does not expect there to be any material
impact on the Consolidated Financial Statements upon adoption of the standard
on January 1, 2007.
Capital Disclosures
The CICA issued Section 1535, "Capital Disclosures", which establishes new
standards for disclosing information about an entity's capital and how it is
managed. It requires the disclosure of information about an entity's
objectives, policies and processes for managing capital. This Section applies
to interim and annual financial statements relating to fiscal years beginning
on or after October 1, 2007. Western plans to adopt this Section on January 1,
2008 for the Consolidated Financial Statements.
CONTROLS AND PROCEDURES
Disclosure Controls
Disclosure controls and procedures are designed to provide reasonable assurance
that all relevant information is gathered, reported, processed, summarized and
reported to management, including the President and Chief Executive Officer
("CEO") and the Chief Financial Officer ("CFO"), on a timely basis so that
appropriate decisions are made regarding public disclosure.
As of December 31, 2006, an evaluation was carried out, under the
supervision of and with the participation of management, including the CEO and
CFO, of the effectiveness of our disclosure controls and procedures as defined
in Canada in Multilateral Instrument 52-109, Certification of Disclosure in
Issuers' Annual and Interim Filings, and in the United States by Rules
13a-15(e) and 15d-15(e) under the Securities and Exchange Act of 1934. Based on
that evaluation, the CEO and CFO concluded that the design and operation of our
disclosure controls and procedures were effective as at December 31, 2006 to
ensure that information required to be disclosed by us is accumulated and
communicated to the management of Western to allow for timely decisions
regarding required disclosure as specified under Canadian and U.S. securities
laws.
Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate
internal control over financial reporting as defined in Rules 13a-15(f) and
15d-15(f) under the Securities Exchange Act of 1934, as amended and in Canada
as defined in Multilateral Instrument 52-109 - Certification of Disclosure in
Issuers' Annual and Interim Filings. Our internal control over financial
reporting is designed to provide reasonable assurance regarding the reliability
of our financial reporting and preparation of our financial statements for
external purposes in accordance with accounting principles generally accepted
in Canada. Our internal control over financial reporting includes those
policies and procedures that: pertain to the maintenance of records that in
reasonable detail accurately and fairly reflect our transactions and
disposition of the assets; provide reasonable assurance that transactions are
recorded as necessary to permit preparation of our financial statements in
accordance with generally accepted accounting principles and that receipts and
expenditures of our assets are being made only in accordance with
authorizations of our management and directors; and provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition,
use or disposition of our assets that could have a material effect on our
financial statements. Because of its inherent limitations, internal control
over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.
Our management, with the participation of our principal executive officer
and principal financial officer, evaluated the effectiveness of our internal
control over financial reporting as of December 31, 2006. In making this
evaluation, management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission ("COSO") in Internal
Control - Integrated Framework.
There was one exclusion from our evaluation. Our 20 per cent undivided
working interest in the AOSP, was excluded from our evaluation as we do not
have the ability to dictate or modify this entity's internal control over
financial reporting, and we do not have the ability, in practice, to assess
those controls. However, we have assessed our internal control over financial
reporting with respect to the inclusion of our share of the AOSP and its
results of operations in our consolidated financial statements. For further
discussion of this exclusion from the scope of our evaluation see "Scope of
Management's Report on Internal Control over Financial Reporting" below.
Based on our evaluation, our management concluded that our internal
control over financial reporting was effective as of December 31, 2006.
Our management's evaluation of the effectiveness of our internal control
over financial reporting as of December 31, 2006, has been audited by
PricewaterhouseCoopers LLP, independent auditors, as stated in their report on
page 66 herein.
Scope of Management's Evaluation of Internal Control over Financial
Reporting
Western is the holder of a 20 per cent undivided interest in the AOSP and
conducts the operation of the AOSP through a Joint Venture Agreement (the
"Agreement") with Chevron, the other 20 per cent interest holder, and Shell,
the 60 per cent interest holder. The Agreement is structured such that Shell,
as the project administrator and controller of the executive committee of the
AOSP, is delegated all managerial responsibilities, including the ability to
control operations, create accounts and keep internal controls over the AOSP.
Shell charges us our proportionate share of the expenditures and provides us
with our proportionate share of saleable synthetic crude which we market
directly to third parties.
Pursuant to the Agreement, and as described below, we have the
contractual right to audit Shell's determination of our share of costs and
outputs of the AOSP. During our 2006 fiscal year, our 20 per cent undivided
working interest in the AOSP comprised 96 per cent of our total Property, Plant
and Equipment, 100 per cent of Operating Expenses, 54 per cent of Purchased
Feedstocks and Transportation, and 64 per cent of Research and Business
Development Expense as at and for the year ended December 31, 2006. However, we
do not have the right or ability to dictate or modify the internal control over
financial reporting of the AOSP, and we do not have the ability, in practice,
to evaluate those controls. Further, we are not able to influence the control
environment or control evaluations of the AOSP. As a result, we have excluded
the AOSP from our evaluation of internal control over financial reporting
relating to the AOSP.
Pursuant to the Agreement, we have a control structure which includes,
among other things, the following:
o the right to participate in the committee that grants the
authority under which all other committees operate including the approval of
the annual budget;
o the right to participate in the committee that reviews operations
and capital spending as well as the approval of certain spending and contracts;
o the right to participate in quarterly accounting and audit
committee meetings; and
o the right to participate in other committees and work groups as
needed.
In addition, we have and we exercise our right to audit, on a routine
basis, Shell's determination of our share of costs as noted and outputs of the
AOSP. Although these activities do not provide the ability to evaluate the
internal control over financial reporting of the AOSP, the foregoing
constitutes a control environment for the purposes of evaluating our internal
control over financial reporting. Accordingly, despite the exclusion of the
AOSP from our management's review, our management has evaluated our internal
control over financial reporting with respect to the inclusion of our share of
the AOSP and its results in our consolidated financial statements.
No changes were made in our internal control over financial reporting
during the year ended December31, 2006, that have materially affected, or are
reasonably likely to affect, our internal control over financial reporting.