EXHIBIT 1
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[LOGO - WESTERN OIL SANDS]
ANNUAL INFORMATION FORM
March 28, 2006
TABLE OF CONTENTS
PAGE
INTRODUCTORY INFORMATION......................................................i
FORWARD LOOKING INFORMATION...................................................i
CORPORATE STRUCTURE...........................................................1
GENERAL DEVELOPMENT OF THE BUSINESS...........................................2
Operating Activities.................................................2
Financing Activities.................................................4
NARRATIVE DESCRIPTION OF THE BUSINESS.........................................4
Project Overview.....................................................5
Joint Venture Agreement..............................................6
General.....................................................6
Joint Venture and Related Agreements........................6
Executive Committee and Project Administrator...............6
Western Personnel...........................................7
The Athabasca Oil Sands Project......................................7
Production History..........................................7
Production Estimates........................................7
Reserves, Resources and Land................................8
Reserves....................................................8
Costs Incurred.............................................13
Significant Factors or Uncertainties on Reserves Data......13
Land Tenure................................................13
Royalties..................................................13
Environmental Considerations...............................14
Abandonment and Reclamation Costs..........................14
Third Party Facilities.....................................15
Marketing and Sales........................................15
Insurance..................................................15
AOSP Expansions............................................16
Dispositions...............................................17
Proposed Expansions and Feasibility Study Agreement........17
Regulatory Approvals.......................................18
Resources..................................................18
Land Position..............................................19
Forward Contracts..........................................20
Tax Horizon................................................21
DIVIDEND POLICY..............................................................21
DESCRIPTION OF SHARE CAPITAL.................................................21
MARKET FOR SECURITIES........................................................23
CREDIT RATINGS...............................................................23
DIRECTORS AND OFFICERS.......................................................24
AUDIT COMMITTEE..............................................................27
Composition and Qualifications......................................27
Responsibilities and Terms of Reference.............................28
Auditor Service Fees................................................28
RISKS AND UNCERTAINTIES......................................................29
TRANSFER AGENTS AND REGISTRAR................................................39
TABLE OF CONTENTS
(continued)
PAGE
INTEREST OF EXPERTS..........................................................39
LEGAL PROCEEDINGS............................................................40
ADDITIONAL INFORMATION.......................................................40
GLOSSARY ....................................................................41
APPENDIX A - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR
APPENDIX B - REPORT OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION
APPENDIX C - AUDIT COMMITTEE CHARTER
INTRODUCTORY INFORMATION
References in this Annual Information Form to Western Oil Sands Inc.
("Western" or the "Corporation") includes Western and its material
wholly-owned subsidiaries, 852006 Alberta Ltd., Western Oil Sands L.P. and
Western Oil Development Inc. unless the context otherwise requires. INITIALLY
CAPITALIZED TERMS USED HEREIN AND NOT OTHERWISE DEFINED HAVE THE MEANINGS
ASCRIBED THERETO IN THE GLOSSARY.
Unless otherwise indicated, all financial information included and
incorporated by reference in this Annual Information Form is determined using
Canadian generally accepted accounting principles ("Canadian GAAP"), which
differs from generally accepted accounting principles in the United States
("U.S. GAAP"). The notes to Western's audited consolidated financial
statements contain a discussion of the principal differences between Western's
financial results calculated under Canadian GAAP and under U.S. GAAP.
UNLESS OTHERWISE SPECIFIED, ALL DOLLAR AMOUNTS ARE EXPRESSED IN CANADIAN
DOLLARS, ALL REFERENCES TO "DOLLARS" OR "$" ARE TO CANADIAN DOLLARS AND ALL
REFERENCES TO "US$" ARE TO UNITED STATES DOLLARS.
FORWARD LOOKING INFORMATION
This Annual Information Form contains certain forward-looking statements
relating but not limited to Western's 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 Corporation'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 associated with the extraction,
treatment and upgrading of mineable oil sands deposits; risks surrounding the
level and timing of capital expenditures required to fulfill the Project's
growth strategy; risks of financing these growth initiatives at commercially
attractive levels; risks of being unable to participate in expansion and
corresponding loss of voting rights in the AOSP; risks relating to the
execution of the Project's optimization strategy; risks involving the
uncertainty of estimates involved in the reserve and resource estimation
process, 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 commodity price and 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. Forward-looking statements are not based on historical
facts but rather on the expectation of management of the Corporation
("Management") regarding the Corporation's future growth or results of
operations, production, future capital and other expenditures (including the
amount, nature and sources of funding thereof), competitive advantages, plans
for and results of drilling activity, environmental matters, business
prospects and opportunities. These forward-looking statements are made as of
the date of the Annual Information Form, and the Corporation assumes no
obligation to update or revise them to reflect new events or circumstances,
except as required by law. For additional information relating to risk factors
please refer to "Risks and Uncertainties".
WESTERN OIL SANDS INC.
ANNUAL INFORMATION FORM
CORPORATE STRUCTURE
Western Oil Sands Inc. was incorporated under the BUSINESS CORPORATIONS ACT
(Alberta) on June 18, 1999. The Corporation amended its articles on July 27,
1999, October 6, 1999, November 30, 1999, December 22, 1999, December 8, 2000,
March 14, 2001 and May 21, 2002 to change its name to Western Oil Sands Inc.,
to remove its private company restrictions, to amend its share capital to
create a class of Non-voting Convertible Equity Shares, to designate a series
of Class D Preferred Shares and to fix the rights, privileges, restrictions
and conditions attaching to such series and to increase the maximum number of
directors permitted. On June 1, 2005, the Corporation amended its articles to
divide the issued and outstanding Class A Shares on a three for one basis,
such that each outstanding Class A Share resulted in three outstanding Class A
Shares (the "Share Split")
Western has the following material wholly-owned subsidiaries; 852006 Alberta
Ltd. (which together with Western holds a 20% undivided interest in the
Project) and Western Oil Development Inc., as shown below:
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_____________________
| |
--------------- | Western | -----------------
| | (Alberta) | 100% |
| 100% |_____________________| |
____________________ | _____________________
|852006 Alberta Ltd. | General | | Western Oil |
| (Alberta) | Partner | | Development Inc |
| |\ | | (Alberta) |
|____________________| \ 1% Limited | |_____________________
\ Partnership |
\ Units |
99% Limited \ |
Partnership Units \ |
_________________________
| Western Oil Sands L.P. |
| (Alberta) |
|_________________________|
|
| 20%
|
/ \
/ \
/ \
/Project \
/ \
/____________\
Western's head office is located at 2400 Ernst & Young Tower, 440 - Second
Avenue S.W., Calgary, Alberta T2P 5E9 and its registered office is located at
Suite 3700, 400 Third Avenue S.W., Calgary, Alberta T2P 4H2.
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GENERAL DEVELOPMENT OF THE BUSINESS
Western is a Canadian corporation that holds a 20 percent undivided ownership
interest in the multibillion dollar Joint Venture that is exploiting the
recoverable bitumen reserves and resources found in certain oil sands deposits
located in the Athabasca region of Alberta. Shell and Chevron hold the
remaining 60 percent and 20 percent undivided ownership interest in the Joint
Venture, respectively. If a joint venture party acquires additional interests
in the Athabasca region, the other joint venture parties have the option to
participate so that all parties are on an equal basis or on a basis otherwise
agreed, in the acquired interest. These transactions are governed by the terms
set out in the Area of Mutual Interest Agreement ("AMI") and the Joint Venture
Agreement. ("JVA"). The current operating Project, which includes facilities
owned by the Joint Venture and third parties, uses established processes to
mine oil sands deposits, extract and upgrade the bitumen into synthetic crude
oil and vacuum gas oil, or VGO. Western is also actively pursuing research and
development efforts to add value to existing assets; downstream initiatives to
reduce exposure to heavy oil differentials; and identifying and evaluating
opportunities in resource development of oil sands and other ventures with
significant long-life hydrocarbon resource potential.
OPERATING ACTIVITIES
March 2006 represents nearly three years of commercial operations for the
Athabasca Oil Sands Project ("AOSP"). The Project has made great strides in
production capacity, recently establishing three consecutive quarterly
production records in fiscal 2005 since its start-up and commissioning. The
maturation of the Project has proceeded for the most part without major
incident but for the fire that occurred at the Mine on January 6, 2003 during
the start-up and commissioning. This fire occurred in the froth cleaning
circuit resulting in limited damage, primarily to electrical cables,
instrumentation and insulation in the solvent recovery area of the froth
treatment plant. Repairs were completed expeditiously, however, severe weather
conditions caused broader freeze damage and impeded progress. Start-up
recommenced on April 4, 2003 and the Project achieved fully integrated
operations between the Mine and the Scotford Upgrader on April 19, 2003. This
unfortunate event resulted in the submission of insurance claims pursuant to
various policies both by the Project and Western itself. All Joint Venture
claims have now been settled, however, Western continues to pursue its own
claims.
On June 1, 2003, Western reported the start of commercial operations as all
aspects of the facilities became fully operational and the Project achieved 50
percent of the stated design capacity of 155,000 barrels per day. Since the
commencement of commercial production, ramp-up continued uninterrupted for
2003, with production increases each quarter. Production ramped-up at the Mine
to approach design levels by the end of 2003, averaging 138,000 barrels per
day in December. Production in 2003 averaged 118,000 barrels per day. By the
end of 2003, nine months after start-up, the Project was operating at 89 per
cent of design capacity. In fiscal 2004, the operation set several records
including record monthly production and daily production to that point.
Despite the records set to that point, during the course of 2004 two unplanned
operational events occurred. At the Mine site, the froth settlers for Train 2
failed in July 2004 and repairs and modifications were required. Similar
repairs were conducted on the froth settlers for Train 1. The froth settlers
form part of the froth treatment process which combines the rich bitumen froth
from storage tanks with a solvent to separate out the remaining solids, water
and heavy asphaltenes. The end result of this process is clean diluted
bitumen. Operations were brought to full capacity at both the Mine and
Upgrader upon completion of these repairs, however, additional operational
issues surfaced at the Upgrader. The extent of this unforeseen event, and the
associated events that followed, resulted in lower production for the fourth
quarter of 2004 which lagged into the first quarter of 2005 resulting in
yearly production levels far
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below the Corporation's expectations. Measured steps were taken to avoid a
recurrence of these events in the future and key learnings were obtained,
setting the stage for the record production levels achieved in the last three
quarters of 2005. Full production at both the Mine and Upgrader re-commenced
on January 30, 2005.
The key lessons garnered from these repairs set the stage for the ensuing
consecutive quarterly production records established from the second to the
fourth quarter of 2005. Average production for 2005 reached nearly160,000
barrels per day which is above the original stated calendar day design rate,
an increase of 18 per cent from approximately 135,500 barrels per day recorded
in 2004. The Project achieved this production record with particular focus and
attention to reliability and increased availability of the facilities at both
the Mine and the Upgrader. Within the space of less than three years, the
Project has progressed from start-up and commissioning to exceeding stated
design rates. This rapid timeline has exceeded performance expectations for an
operation of this size and complexity and is due to the dedication of the
Project's personnel, together with personnel at Albian which is the AOSP's
operating entity for the Mine.
Operating costs for 2005 were $22.06 per processed barrel, up slightly from
$21.17 per processed barrel in 2004 in large part due to inflationary impacts
to labour, materials and higher natural gas costs associated with the robust
commodity market.
Fiscal 2005 represented the second full year of commercial operations for the
Project. A few noteworthy milestones included:
o production of 100 million barrels of bitumen in just over two
years of operation;
o record consecutive quarterly production in the second, third and
fourth quarters of approximately 164,000 barrels per day,
165,000 barrels per day and 178,000 barrels per day,
respectively;
o record annual production of approximately 160,000 barrels per
day of bitumen in 2005;
o Albian became the first company in Canada to become ISO 14001
certified under the new standards; and
o Albian achieved one year without a lost time incident on July
1st and July 5th marked four million person hours without a lost
time incident.
These milestones demonstrate the Project's ability to safely extract,
transport and process significant volumes of bitumen. However, the Project is
complex and can, from time to time, experience unforeseen operational issues
requiring immediate attention and repair as has been evidenced over the last
several years. When these events occur, the Joint Venture systematically and
methodically addresses the outages to return to full production as soon as
practicable and applies the lessons learned to prevent future outages.
Subsequent to the year-ended December 31, 2005, the conveyor belt used at the
Mine to transport bitumen ore from the primary crushers to the extraction
plant developed a vertical tear. As a result, overall operations were reduced
to approximately one-third of stated design rates for three weeks. Repairs and
replacement of the conveyor belt were completed ahead of schedule with
production brought back to stated design rates on March 20, 2006.
The Project continues to make progress on production optimization programs
which once completed, are expected to increase production volumes to between
180,000 and 200,000 barrels per day by 2008 - 2009.
-4-
These optimization programs, as well as other initiatives, do not require
significant amounts of capital to complete. Therefore, Western believes that
substantial additional volumes may be achieved with a modest capital
investment over the course of the next two to three years to meet this
objective. See "Forward-looking Information" and "Risks and Uncertainties"
FINANCING ACTIVITIES
Western has used a combination of debt and equity capital to fund its share of
Project capital costs associated with construction and its share of operating
costs. Western's credit position has improved significantly over the last
several years as excess free cash flow has been aggressively applied to reduce
its revolving bank facilities. The following outlines key financing activities
up to and including fiscal 2005 undertaken by the Corporation in the last
three years:
o A public offering of Common Shares at $8.17 per share (adjusted
to reflect the Share Split) for gross proceeds of $50.225
million completed on February 7, 2003;
o On October 16, 2003, the Corporation entered into a $240 million
credit facility (the "Revolving Credit Facility") with a
syndicate of Canadian chartered banks. This facility replaced a
$110 million credit facility entered into by the Corporation in
November 2002 and subsequently amended in 2003 (the "Working
Capital Facility"). The proceeds were used to repay amounts
outstanding under a bridge facility entered into in October
2001, the Working Capital Facility and to provide for working
capital during operations.
o A $68 million bought-deal equity offering consisting of
6,000,000 Common Shares at a price of $11.33 per share (adjusted
to reflect the Share Split) completed on April 8, 2004;
o During March 2005, Western successfully refinanced its $100
million Senior Credit Facility by the assumption of this full
amount into Western's Revolving Credit Facility, thereby
increasing the Revolving Credit Facility to $340 million. The
additional $100 million is subject to the same terms and
conditions as those contained in the Revolving Credit Facility;
o During October 2005, Western successfully amended its $340
million Revolving Credit Facility with respect to pricing or
spreads on both drawn and undrawn allocations to reflect
Western's improved credit position. Western also amended the
structure of the Revolving Credit Facility from a 364-day
revolver with a two year term-out provision for non-revolving
allocations to a three-year revolving facility extendible
annually at the lenders' discretion; and
o Repayment of $175 million in debt credit facilities during the
course of fiscal 2005.
NARRATIVE DESCRIPTION OF THE BUSINESS
Western is a Canadian corporation that holds a 20 percent undivided ownership
interest in a multibillion dollar Joint Venture to exploit the recoverable
bitumen resources found in certain oil sands deposits at the Muskeg River Mine
located on the western portion of Lease 13. This is Western's only material
asset and it is our primary focus. Shell and Chevron hold the remaining 60
percent and 20 percent undivided ownership interest in the Joint Venture,
respectively. Detailed expansion plans are underway to exploit bitumen
resources on other mineable oil sands leases in the Athabasca area in which
Western has a right to participate. Lease 13 is located in northern Alberta
approximately 70 km north of Fort McMurray, Alberta, abutting the Athabasca
River; and the integrated Scotford Upgrader is situated near Shell's existing
refinery near Fort Saskatchewan, Alberta. The Project, which includes
facilities owned by the Joint Venture and third parties, uses established
processes to mine oil sands deposits, extract and upgrade the bitumen into
synthetic crude oil and vacuum gas oil, or VGO. Western is also actively
pursuing
-5-
research and development efforts to add value to existing assets; downstream
initiatives to reduce exposure to heavy oil differentials; and identifying and
evaluating opportunities in resource development of oil sands and other
ventures with significant long-life hydrocarbon resource potential.
Construction of the Mine and Upgrader was completed in December 2002, at a
total capital cost of $5.7 billion ($1.14 billion to Western's account).
Bitumen production commenced at the Mine in January 2003, reaching commercial
levels in June 2003. Ramp up of production at the Project continued through
2004 with average production of approximately 135,500 barrels per day (87
percent of design capacity). Considerable focus and attention was directed to
increased reliability and availability of our extraction facilities and
upgrader during 2005, resulting in production records for three consecutive
quarters, aggregating to a yearly production record of nearly 160,000 barrels
per day. This production level is above the stated calendar day design rate of
155,000 barrels per day as the Project continues to look for product
optimization programs to enhance reliability further.
As at December 31, 2005, Western had 41 employees.
PROJECT OVERVIEW
The Project is designed to produce high quality bitumen by surface mining
certain Athabasca oil sands deposits and upgrading the extracted bitumen into
custom blended petroleum products for sale to conventional refineries where it
is used to produce petroleum products. Approximately 275,000 tonnes per day of
ore, in addition to approximately 155,000 tonnes per day of overburden, low
grade (waste) oil sand and extraction plant rejects can be mined from the
Mine. At design rates approximately 155,000 barrels per day of bitumen is
extracted from this ore in the Extraction Plant and with the addition of
non-bitumen feedstocks approximately 190,000 barrels per day of refinery
feedstocks and synthetic crude oil blends can be produced by the Upgrader.
The Project is an integrated oil sands development in which:
o Oil sands deposits are mined using open pit techniques at the
Mine located on the western portion of Lease 13, which is a
truck and shovel mine operation;
o Raw bitumen is extracted from the oil sands through processes
powered by electrical and thermal energy at the Extraction Plant
that is located on the western portion of Lease 13. The
extraction process consists of primary extraction and froth
treatment stages;
o Once extracted, the raw bitumen feedstock is transported from
the Mine through a dual pipeline system to the Scotford Upgrader
located near Fort Saskatchewan, Alberta where it is upgraded
into refinery feedstocks;
o Upgrading is the final stage of the production process. The
bitumen feedstock is distilled to recover diluent, then
undergoes a hydro-conversion process with integrated
hydro-treating to generate suitable product streams; and
o After the bitumen has been upgraded, it is sold as refinery
feedstock to North American refineries and to the Scotford
Refinery, which is adjacent to the Scotford Upgrader, for
further processing. A dual pipeline system connects the Scotford
Upgrader to certain third party pipelines in Edmonton, Alberta.
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JOINT VENTURE AGREEMENT
The following section describes the general terms of the Joint Venture
Agreement and certain other relevant agreements.
GENERAL
The Joint Venture, which commenced December 6, 1999, consists of the
following: (i) the mining of oil sands from the western portion of Lease 13;
(ii) extraction of bitumen from such oil sands at the Extraction Plant; (iii)
the upgrading of such diluted bitumen in the Upgrader into refinery feedstocks
and synthetic crude oil blends; (iv) certain rights of the Corporation and
Chevron to participate in mining operations on the east area of Lease 13 and
in Shell's Other Athabasca Leases; (v) an area of mutual interest for
expansion of operations of the Joint Venture; (vi) the disposition of the
Upgrader products; and (vii) the construction operations relating to the
foregoing.
The Joint Venture has been established pursuant to a number of agreements
among the Owners and is the subject of other agreements between the Owners and
third parties.
JOINT VENTURE AND RELATED AGREEMENTS
The principal agreement, which established the Joint Venture and governs the
relationship of the Owners, is the Joint Venture Agreement. This agreement
also sets out the manner in which certain of the other Project agreements will
be managed.
The agreement provides for the formation of the Joint Venture, the manner in
which the Joint Venture is administered, the creation and manner in which the
Executive Committee, which is the decision making body in respect of most
matters, functions, the responsibilities of the project administrator,
secondments of Owners' personnel, budgets, costs, technology matters,
dispositions, defaults, environmental matters, expansions, Owner's rights
vis-a-vis each other, as well as financial, accounting, banking matters, basic
design parameters of the Project and other matters.
The Joint Venture continues until all abandonment and decommissioning
obligations of the Owners have been fulfilled in accordance with applicable
laws and all required regulatory approvals have been received, all third party
Project agreements have been terminated and all accounts among the Owners in
respect of the Project have been settled.
EXECUTIVE COMMITTEE AND PROJECT ADMINISTRATOR
The Joint Venture Agreement establishes an Executive Committee that is
responsible for most decisions relative to the Joint Venture, other than those
which are requirements of the Owners. One of Shell's representatives has been
appointed as the first Chairman and each Owner has appointed two
representatives to the Executive Committee. Voting at the Executive Committee
level is based upon Owners' ownership interests.
The Executive Committee also oversees the operations of Albian and Shell as
operators of the Mine and Extraction Plant and the Upgrader and related
facilities and ensures that each Owner has an ongoing opportunity to provide
qualified secondees to the Project.
The project administrator, which initially is Shell, has an administrative
function and deals with day to day matters that include making payments under
third-party Project agreements and dealing with administrative matters
relating to non-performing Owners. The project administrator is responsible
for
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carrying out the directions of the Executive Committee and appointing an
individual to act as project integration manager.
WESTERN PERSONNEL
Albian operates the Mine and the Extraction Plant pursuant to an operating
agreement. The mining and extraction services agreement dated December 6, 1999
between Western and Albian (the "Mining and Extraction Services Agreement")
sets out that Western will provide certain mine and extraction management
services including the full and part-time services of certain of its employees
and consultants to Albian. Further, Western will identify additional personnel
to be employed by Albian beyond the Western personnel who are necessary for
the operation of the Mine and the Extraction Plant. Western has five employees
working directly for the Joint Venture, two of which are operational personnel
at the Mine while the remaining three are based in Calgary and their primary
role is to assist with our Joint Venture partners in the planning and
feasibility studies associated with expansion initiatives. All costs incurred
by Western and approved by the Executive Committee in respect of the provision
of services by Western pursuant to the Mining and Extraction Services
Agreement are reimbursed by Albian.
THE ATHABASCA OIL SANDS PROJECT
PRODUCTION HISTORY
The following table sets forth certain information in respect of production,
product prices received, royalties, production costs and netbacks received by
Western for its synthetic crude oil production for each quarter of its most
recently completed financial year:
THREE MONTHS ENDED
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MARCH 31, 2005 JUNE 30, 2005 SEPTEMBER 30, 2005 DECEMBER 31, 2005
-------------- ------------- ------------------ -----------------
Average Daily Production - dry
bitumen basis (bbl/day) 26,503 32,757 33,034 35,572
Average Net Prices Received
($Cdn/bbl) 50.44 66.74 77.38 68.28
Royalties ($Cdn/bbl) 0.28 0.30 0.46 0.32
Operating Expenses ($Cdn/bbl) 24.79 18.57 21.33 21.72
Feedstocks ($Cdn/bbl) 11.56 17.14 16.29 17.58
Netback Received
($Cdn/bbl)((2)) 13.81 30.73 39.30 28.66
NOTES:
(1) All per barrel amounts are stated on a dry production bitumen basis.
(2) Netback is calculated as oil sands revenue less royalties, operating
expenses and feedstocks on a per barrel of production basis.
PRODUCTION ESTIMATES
Western estimates that its synthetic crude oil production from the AOSP will
be between 145,000 to 150,000 barrels per day (29,000 to 30,000 barrels per
day, net to Western) for 2006. Production for 2006 will be impacted by an
estimated eight week turnaround of the entire operation during the second
quarter of 2006 together with the unscheduled repairs in March to the conveyor
belt at the Mine. Production from the Project accounts for 100% of Western's
estimated production in 2006.
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RESERVES, RESOURCES AND LAND
Under the terms of the Joint Venture Agreement for the AOSP, Western and its
partners have in place a Participation and Area of Mutual Interest Agreement
("AMI"). The AMI stipulates that the Joint Venture partners have rights to
participate in any additional leases that are acquired by any one of the
partners in the Athabasca region.
Within the Project we have the following: proved and probable reserves which
are associated with the existing operations at the Muskeg River Mine;
resources on lands within the Joint Venture that have been evaluated; and
finally, undeveloped lands which have been acquired by all three partners
during the past year which are included under the terms of the AMI and are
subject to evaluation for possible future development.
RESERVES
Lease 13 encompasses 49,872 acres hectares and lies within the mineable oil
sands area of the Athabasca deposits. Bitumen has been extracted from the west
side of Lease 13 for nearly three years. The operating Mine covers a 121
square kilometre portion of the western portion of Lease 13.
GLJ Petroleum Consultants Ltd. ("GLJ") prepared a report dated February 13,
2006 which evaluated the reserves attributable to Western as of December 31,
2005. This west portion of Lease 13 has been estimated by GLJ to contain
approximately 1.6 billion barrels of oil. Of the 1.6 billion barrels of
reserves, approximately 1.0 billion barrels are proved reserves while 0.6
billion barrels are considered probable reserves. Based on the Project's
design capacity, the Mine has a reserve life index (both proved and probable)
of 27 years at a non-declining undiluted bitumen production rate of 155,000
barrels per day.
The following table below outlines the Joint Venture's proved and probable
reserves on the western portion of Lease 13 as estimated by GLJ.
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WESTERN'S
TOTAL SHARE
(MMBBLS) (MMBBLS)
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JOINT VENTURE (RESERVES)
Western portion of Lease 13 1,551 310
- -------------------------------------------------------------------------------
Reserves represent those quantities of oil and gas anticipated to be
economically recoverable from Discovered Resources. Quantities of oil and gas
must not be classified as reserves unless there is an expectation that the
accumulation will be developed and placed on production within a reasonable
timeframe. Reserves are a subset of recoverable resources which itself is a
subset of discovered resources. See "Resources".
The tables below summarize the upgraded bitumen reserves and the value of
future net revenue attributable to Western's ownership as evaluated in the GLJ
Report. The information set forth below relating to Western's reserves
constitutes forward-looking information which is subject to certain risks and
uncertainties. See "Forward-Looking Information" and "Risks and
Uncertainties".
All evaluations of future revenue are after the deduction of future income tax
expenses, unless otherwise noted in the tables, royalties, development costs
and production costs, but before consideration of indirect costs such as
administrative, overhead and other miscellaneous expenses. THE ESTIMATED
FUTURE NET REVENUES CONTAINED IN THE FOLLOWING TABLES DO NOT NECESSARILY
REPRESENT THE FAIR MARKET VALUE OF THE CORPORATION'S RESERVES. THERE IS NO
ASSURANCE THAT THE FORECAST PRICE AND COST ASSUMPTIONS
-9-
CONTAINED IN THE GLJ REPORT WILL BE ATTAINED AND VARIANCES COULD BE MATERIAL.
Other assumptions and qualifications relating to costs and other matters are
included in the GLJ Report. The recovery and reserves estimates attributable
to Western's ownership in the Project are estimates only. Actual reserves may
be greater or less than those calculated.
It is noted that the accuracy of any reserve estimate, especially when based
on volumetric analysis, is a function of the quality of available data and of
engineering interpretation and judgment. While reserve estimates presented
herein are considered reasonable, performance subsequent to the date of the
estimate may justify their revision, either upward or downward. The GLJ Report
presents net revenue projections prepared for the reserves attributable to the
ownership interest of Western along with a discussion of the evaluation.
SUMMARY OF RESERVES AS AT DECEMBER 31, 2005
CONSTANT PRICES AND COSTS FORECAST PRICES AND COSTS
----------------------------------- ----------------------------------
UPGRADED BITUMEN UPGRADED BITUMEN
----------------------------------- ----------------------------------
GROSS NET GROSS NET
(MMBBL) (MMBBL) (MMBBL) (MMBBL)
--------------- ------------- -------------- -------------
Proved Developed Producing 190 182 190 175
Proved Developed Non-Producing 5 4 5 4
--------------- ------------- -------------- -------------
Total Proved 195 186 195 179
Total Probable 115 109 115 104
--------------- ------------- -------------- -------------
Total Proved Plus Probable 310 295 310 283
=============== ============= ============== =============
NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON CONSTANT PRICES AND COSTS
BEFORE DEDUCTING INCOMES TAXES AFTER DEDUCTING INCOME TAXES
---------------------------------------- -------------------------------------
DISCOUNTED AT
UNDISCOUNTED DISCOUNTED AT 10% UNDISCOUNTED 10%
(MM$) (MM$) (MM$) (MM$)
------------------ -------------------- ------------------- -----------------
Proved Developed Producing 6,109 3,099 4,498 2,423
Proved Developed Non-Producing 232 240 148 152
------------------ -------------------- ------------------- -----------------
Total Proved 6,341 3,339 4,645 2,575
Total Probable 4,015 960 2,672 639
------------------ -------------------- ------------------- -----------------
Total Proved Plus Probable 10,356 4,299 7,317 3,214
------------------ -------------------- ------------------- -----------------
The following tables present the estimated future net revenue attributable to
Western, as set forth in the GLJ Report:
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
BASED ON CONSTANT PRICES AND COSTS
FUTURE FUTURE
NET NET
ABANDONMENT REVENUE REVENUE
AND BEFORE AFTER
OPERATING DEVELOPMENT RECLAMATION INCOME INCOME INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES TAXES TAXES
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
--------- ---------- ---------- ------------- -------------- ---------- -------- --------
Total Proved 11,377 519 4,087 429 - 6,341 1,696 4,645
--------- ---------- ---------- ------------- -------------- ---------- -------- --------
Total Proved
Plus Probable 18,111 910 6,243 602 - 10,356 3,039 7,317
--------- ---------- ---------- ------------- -------------- ---------- -------- --------
-10-
FUTURE NET REVENUE BY PRODUCTION GROUP
BASED ON CONSTANT PRICES AND COSTS
The future net revenue before income taxes and discounted at 10% per year in
respect of the total proved and total proved plus probable upgraded bitumen
reserves attributable to Western's ownership interest in the Project as at
December 31, 2005 are $3,339 million and $4,299 million, in each case based on
constant prices and costs.
NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON FORECAST PRICES AND COSTS
BEFORE DEDUCTING INCOME TAXES AFTER DEDUCTING INCOME TAXES
DISCOUNTED AT DISCOUNTED AT
------------------------------------------ ----------------------------------------
0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
Proved Developed Producing 3,494 2,473 1,875 1,502 1,254 2,755 2,029 1,595 1,316 1,127
Proved Developed
Non-producing 156 163 139 109 83 96 100 84 64 47
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total Proved 3,650 2,636 2,014 1,611 1,337 2,851 2,130 1,679 1,381 1,174
Total Probable 2,799 1,301 671 386 248 1,862 866 448 260 168
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total Proved Plus Probable 6,449 3,937 2,685 1,997 1,585 4,713 2,996 2,127 1,641 1,342
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
BASED ON FORECAST PRICES AND COSTS
FUTURE FUTURE
NET NET
ABANDONMENT REVENUE REVENUE
AND BEFORE AFTER
OPERATING DEVELOPMENT RECLAMATION INCOME INCOME INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES TAXES TAXES
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
--------- ---------- ---------- ------------- -------------- ---------- -------- --------
Total Proved 9,203 723 4,316 514 - 3,650 799 2,851
Total Proved
Plus Probable 15,526 1,341 6,964 772 - 6,449 1,736 4,713
FUTURE NET REVENUE BY PRODUCTION GROUP
BASED ON FORECAST PRICES AND COSTS
The future net revenue before income taxes and discounted at 10% per year in
respect of the total proved and total proved plus probable upgraded bitumen
reserves attributable to Western's ownership interest in the Project as at
December 31, 2005 are $2,014 million and $2,685 million, in each case based on
forecast prices and costs.
RECONCILIATION OF NET RESERVES BY PRINCIPAL PRODUCT TYPE
BASED ON CONSTANT PRICES AND COSTS
Both fiscal 2005 and 2004 represent full years of production. The following
table sets forth a reconciliation of the changes in Western's bitumen reserves
as at December 31, 2005 against such reserves as at December 31, 2004 based on
the constant price and cost assumptions set forth in Note 8 below:
-11-
UPGRADED BITUMEN
---------------------------------------------
NET PROVED PLUS
NET PROVED NET PROBABLE PROBABLE
(MMBBL) (MMBBL) (MMBBL)
---------- ------------ --------
At December 31, 2004 202 112 314
---------- ------------ --------
Extensions - - -
Improved Recovery - - -
Technical Revisions 3 2 5
Discoveries - - -
Acquisitions - - -
Dispositions - - -
Economic Factors (7) (5) (12)
Production (12) - (12)
---------- ------------ --------
At December 31, 2005 186 109 295
RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% BASED ON CONSTANT PRICES AND COSTS
The following table sets forth changes between future net revenue estimates
attributable to net proved reserves as at December 31, 2005 against such
reserves as at December 31, 2004:
(MM$)
-----
Estimated Future Net Revenue at December 31, 2004 1,832
-----
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (237)
Net Change in Prices, Production Costs and Royalties Related to Future Production 1,378
Changes in Previously Estimated Development Costs Incurred During the Period 28
Changes in Estimated Future Development Costs (196)
Extensions and Improved Recovery -
Discoveries -
Acquisitions of Reserves -
Dispositions of Reserves -
Net Change Resulting from Revisions in Quantity Estimates 24
Accretion of Discount Pre Tax 183
Net Change in Income Taxes (437)
Other changes, including Hedging -
-----
Estimated Future Net Revenue at December 31, 2005 2,575
=====
NOTES:
(1) Reserve definitions consistent with National Instrument 51-101 - Standards
of Disclosure for Oil and Gas Activities ("NI 51-101") have been used in
the GLJ Report, where: "Proved" reserves are those reserves that can be
estimated with a high degree of certainty to be recoverable. The targeted
level of certainty under a specific set of economic conditions is at least
a 90 percent probability that the quantities actually recovered will equal
or exceed the estimated proved reserves "Probable" reserves are those
reserves that are less certain to be recovered than proved reserves. It is
equally likely that the actual remaining quantities recovered will be
greater or less than the sum of the estimated proved plus probable
reserves. "Proved Plus Probable" reserves include those additional
reserves that are less certain to be recovered than proved reserves. The
targeted level of certainty under a specific set of economic conditions is
at least a 50 percent probability that the quantities actually recovered
will equal or exceed the sum of the estimated proved plus probable
reserves.
(2) All of the Project reserves are classified as "developed". The proved
non-producing reserves relate to recovery factor and capacity improvements
associated with de-bottlenecking capital investments. Although the capital
is significant relative to the cost of drilling a well, classifying the
non-producing reserves as undeveloped is not considered appropriate for
this mining project.
(3) Reserves have not been attributed to Western for the bitumen deposits
present in the eastern portion of Lease 13. Western does not currently
hold a working interest position in these expansion opportunities.
Although preliminary resource base assessments have been conducted on some
of the leases held through the Joint Venture, no reserves have been
attributed to Leases 88, 89, 90, 9, 15, 17, 309, 310, 351, 352, 631, and
632.
(4) Upgraded bitumen is equivalent to a synthetic oil product type. This term
is used rather than synthetic oil since production from the Upgrader
includes volumes attributable to off-lease feedstock purchases that cannot
be booked as Project reserves. Upgrading swells the bitumen such that the
upgraded bitumen corresponds to 1.03 barrels of undiluted bitumen.
(5) The oil price forecasts reflect total revenues associated with the output
from the Upgrader less the purchase costs associated with feedstock.
Changes to the product mix and associated feedstock composition will occur
relative to what they have been. In the constant price case, GLJ estimates
the oil pricing to be the December 31, 2005 Edmonton Par less $10.00/bbl
in 2006, reflecting the average December 2005 offset to Edmonton Par for
each feedstock product and marketable product stream, and Western's
budgeted
-12-
compositions of feedstock and sales. In the forecast price case, GLJ
estimates the oil pricing to be Edmonton Par less $10.00/bbl based upon
the average for 2005..
(6) Bitumen production has been forecast by GLJ to be 145,000 barrels per day
in 2005 in the proved category growing to 180,000 barrels per day by 2009
in the total proved category. In the proved plus probable case, production
is forecast to grow from a rate of 150,000 barrels per day in 2005 to an
average rate of 195,000 barrels per day by 2008. The incremental probable
reserves reflect the current mine plan as well as improved extraction
recovery relative to the proved category.
(7) Royalties are paid at the Mine boundary using a deemed bitumen revenue. In
the constant price case, GLJ has used a bitumen price of $27.74/bbl based
upon the December 2005 offset and a posted December 31, 2005 price for LLB
Crude Oil at Hardisty. In the forecast price case, GLJ has deducted
$0.50/bbl to GLJ's price for 12 degree heavy oil at Hardisty to reflect
historic royalty calculations. The capital expense base for the Project at
December 31, 2005 is estimated at $1,650 million.
(8) The constant price reflects December 31, 2005 prices of $68.27/bbl
Edmonton Par oil, $39.20/bbl LLB Crude Oil at Hardisty, $9.46/MMBTU gas
and zero inflation. In the forecast price assumptions, the following GLJ
price forecast was used:
EXCHANGE WTI CRUDE OIL AT LIGHT, SWEET CRUDE OIL AT HEAVY CRUDE OIL ALBERTA PLANT
YEAR INFLATION RATE CUSHING OKLAHOMA EDMONTON (40 API, 0.3% S) (12 API) AT HARDISTY SPOT GAS
(%) ($US/$CDN) ($US/BBL) ($CDN/BBL) ($CDN/BBL) ($/MMBTU)
- ---------------------------------------------------------------------------------------------------------------------
2006 2.0 0.85 57.00 66.25 33.25 10.35
2007 2.0 0.85 55.00 64.00 32.75 9.00
2008 2.0 0.85 51.00 59.25 32.50 7.75
2009 2.0 0.85 48.00 55.75 32.00 7.25
2010 2.0 0.85 46.50 54.00 32.00 6.95
2011 2.0 0.85 45.00 52.25 33.50 6.65
2012 2.0 0.85 45.00 52.25 33.50 6.65
2013 2.0 0.85 46.00 53.25 34.00 6.80
2014 2.0 0.85 46.75 54.25 34.75 6.95
2015 2.0 0.85 47.75 55.50 35.25 7.15
2016 2.0 0.85 48.75 56.50 36.00 7.30
2017+ 2.0 0.85 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
In consideration of oil sands mining cost pressures, rather than the
projected inflation of 2.0 percent above, GLJ assumed a 5.0 percent
inflation factor for the Muskeg River Mine component of the project during
the period 2006 through 2008, 4.0 percent in 2009, 3.0 percent in 2010
followed by 2.0 percent thereafter.
(9) Western's weighted average historical realized price for 2005 was $49.91
per synthetic barrel sold, $57.02 per synthetic barrel sold excluding the
effects of hedging activities.
(10) GLJ is an independent qualified reserves evaluator appointed pursuant to
NI 51-101.
FUTURE DEVELOPMENT COSTS
The following table sets forth the future development costs associated with the
development of Western's reserves as set forth in the GLJ Report.
TOTAL PROVED TOTAL PROVED TOTAL PROVED PLUS
ESTIMATED USING ESTIMATED USING PROBABLE ESTIMATED
CONSTANT PRICES AND FORECAST PRICES AND USING FORECAST
COSTS COSTS PRICES AND COSTS
(MM$) (MM$) (MM$)
------------------- ------------------- --------------
2006 65.0 67.5 72.8
2007 80.0 86.0 96.7
2008 50.0 55.5 60.1
2009 20.0 23.2 24.4
2010 20.0 23.8 25.1
------------------- ------------------- --------------
Total for all years undiscounted 429.1 513.8 772.3
------------------- ------------------- --------------
Total for all years discounted at 10%/year 276.6 317.6 383.0
=================== =================== ==============
Western intends to finance these development costs through a combination of
free cash-flow from operations together with existing banking facilities. To
the extent that bank facilities increase, costs associated with this borrowing
would likely be similar to the rates that have been incurred in the prior
years. This anticipated financing strategy would not affect the reserve
balances nor the estimated future net revenue associated with these reserves
listed above.
-13-
COSTS INCURRED
The following table sets forth costs incurred by Western in respect of the
Project for the year ended December 31, 2005:
PROPERTY ACQUISITION COSTS EXPLORATION COSTS DEVELOPMENT COSTS
(MM$) (MM$) (MM$)
- --------------------------------------- ----------------- -----------------
PROVED PROPERTIES UNPROVED PROPERTIES
- ----------------- -------------------
Nil Nil $31.7(1) $27.7
(1) Includes $27.7 million incurred to fund Western's commitments pursuant to
the first phase of the expansion
SIGNIFICANT FACTORS OR UNCERTAINTIES ON RESERVES DATA
Western's reserves to date relate only to the west side of Lease 13. All
infrastructure components are in place to extract the independently evaluated
reserves. Since significant capital costs have already been incurred for the
Project, the exposure to rising capital costs is limited to expansion projects
required to extract the undeveloped resources. Certain maintenance capital
costs will be expended over the life of the reserves to repair and replace
certain components, particularly at the Mine and extraction facilities given
the abrasive nature of the ore being processed. However, risk remains with
respect to ore quality, existence of deleterious materials such as water or
clay fines and ore body geometry such as strip ratio. Important economic
factors in the determination of the future net revenues associated with the
reserves are forecasted prices of crude oil and natural gas. Should future
prices vary significantly from prices used by GLJ in their independent
assessment, the corresponding future net revenues associated with the reserves
may be materially different. See section titled "Risks and Uncertainties".
LAND TENURE
Oil produced from oil sands is produced under Crown Oil Sands Leases granted
by the Province of Alberta. Such Crown Oil Sands Leases have an initial term
of 15 years, and may be continued thereafter under the OIL SANDS TENURE
REGULATION (Alberta) to the extent that the lessee has attained the required
minimum level of evaluation of the oil sands in the leases or the leases are
producing. Lease 13 has been continued under such regulation. The real
property related to the pipelines, the Upgrader and the cogeneration
facilities fall into two basic categories of ownership: (i) a number of
locations, including some pumping/compressor stations, are owned in fee
simple; and (ii) the majority of locations are covered by leases, easements,
rights-of-way, permits or licenses from landowners or governmental authorities
permitting the land to be used in such a manner.
ROYALTIES
An initial royalty of 1% of the gross revenue on the bitumen produced is paid
until the Owners have recovered 100% of the capital costs associated with the
Mine and Extraction Plant, including a return on capital. Such return is based
on the monthly Canadian federal long-term bond rate. Subsequent thereto, the
royalty will be the greater of 1% of the gross revenue on the bitumen produced
and 25% of net bitumen revenue. Gross revenue is calculated based on the fair
market value of the bitumen prior to upgrading. Net revenue is determined by
deducting from gross revenue the aggregate of all allowable operating costs,
interest expense and amortization of capital costs and any loss carryforwards.
Based on forecasted production levels and proposed capital expansions, Western
does not foresee the higher royalty rates to take effect in the immediately
foreseeable future.
-14-
ENVIRONMENTAL CONSIDERATIONS
The key environmental issues and stakeholder concerns to be managed by the
Owners in the development of the Mine are similar to those currently being
managed by existing oil sands operators and communities and encompass the
health of local and regional residents and Project employees, surface
disturbance on the terrestrial ecosystem, effects on traditional land use and
historical resources, local and regional air quality, water quality, health of
the aquatic ecosystem in the Athabasca and Muskeg rivers and cumulative
effects on wildlife populations and aquatic resources. The Owners have
committed to both site-specific and regional monitoring programs that will
track the effects of the Project and the cumulative effects of regional
development on environmental components and ecosystems.
The Owners will operate the Project to achieve compliance with applicable
statutes, regulations, codes, permit conditions and, to the extent
practicable, government guidelines. Where the applicable laws are not clear or
do not address all environmental concerns, management will apply appropriate
internal standards and guidelines to address such concerns. In addition to
complying with legislation and regulations and exercising due diligence, the
Owners will strive to continuously improve the overall environmental
performance of the operation and products while aspiring for short term and
long term commercial success for the Project. Air quality is of particular
importance to the Project, and has taken on greater significance with the
federal government's ratification of the Kyoto agreement. As part of a
Voluntary Climate Change Action Plan, the Joint Venture has substantially
reduced emission targets for the Project. As it stands today, the Project is
operating with emissions that are approximately 27 per cent lower than the
original case that was approved by the Alberta Energy and Utilities Board.
This has been achieved through the addition of cogeneration units, the use of
waste hydrogen from a neighbouring facility and a variety of process
improvements. Western's goal is to further reduce emissions by another 40 per
cent by 2010 through a combination of energy efficiency projects. To achieve
this goal, the Owners are pursuing a multi-faceted plan, which includes energy
efficiency projects, investigation of cleaner technology, the purchase of
domestic and international offsets and tree-planting offset programs.
ABANDONMENT AND RECLAMATION COSTS
Western has abandonment and reclamation liabilities relating to the Mine,
Upgrader and related facilities. Western estimates the abandonment liability,
net of salvage, for these assets with consideration given to the expected cost
to abandon and reclaim the lands and facilities. These estimates are based on
prevailing industry conditions, regulatory requirements and past experience.
The value is determined by Western first estimating the anticipated timing and
amount of net cash outflows using third party costs for future dismantlement
and site restoration. These future payments are then present valued using a
credit adjusted risk free rate appropriate for Western.
The liability is estimated in the period in which the liability is incurred.
These estimates are prepared annually and adjustments are made quarterly for
material changes in the amount of the liability or the timing of abandonment.
Where material differences are identified, adjustments to the liabilities or
accretion expense are made on a prospective basis.
Western's share of the present value of abandonment and reclamation costs that
require recognition in its financial statements at December 31, 2005 is $9.1
million ($199.0 million undiscounted). These liabilities relate to Western's
20% working interest in the Project's future dismantlement costs and site
restoration costs for the Mine, Upgrader and related facilities. GLJ has not
included any abandonment and reclamation costs in the GLJ Report. Western does
not anticipate any material expenditures relating to abandonment and
reclamation during the next three years as the current mine plan contemplates
development over 30 years.
-15-
THIRD PARTY FACILITIES
The Owners have entered into various contracts with certain third parties to
construct, own and operate certain additional facilities required by the
Project. Terasen Pipelines (Corridor) Inc. ("Terasen") constructed the dual
pipeline system that connects the Mine to the Scotford Upgrader and the
Scotford Upgrader to certain third party pipelines. Terasen was acquired
during the course of 2005 by Kinder Morgan, Inc. ("Kinder Morgan") Kinder
Morgan now operates this system directly. The Owners are severally responsible
for the costs of transportation on the pipeline systems, which is on a take or
pay basis.
ATCO built, owns and operates the cogeneration facility located on Lease 13
which provides power and steam for the Mine and Extraction Plant. ATCO also
owns and operates the cogeneration facility constructed to provide electrical
power to the Upgrader. The Owners are obligated to purchase power from ATCO
under long-term contracts. ATCO has the ability to sell any excess power
generated by the cogeneration facilities to the commercial power market.
MARKETING AND SALES
Shell Canada Products Limited takes delivery of vacuum gas oil at the Scotford
Refinery, representing approximately one-third of the total Upgrader
production, pursuant to a long-term sales arrangement. Western sells
approximately 12,000 barrels per day of vacuum gas oil to Shell Canada
Products Limited under this arrangement representing its 20% share of such
total sales. The remaining production from the Upgrader and any third party
feedstocks currently form the basis of two streams of synthetic crude oil (one
heavy and one light) totalling approximately 150,000 barrels per day (30,000
barrels per day to Western). This production is taken in kind and marketed by
each Owner to numerous refineries throughout North America. The Scotford
Upgrader is located at the hub of the western Canadian refining industry near
Edmonton, Alberta, providing the Owners with access to a number of pipeline
systems, to which the Corridor pipeline system is connected. Provisions for
pipeline deliveries have been established through most major crude oil
trunkline systems. As a result, Western is able to sell all of its production
volumes into the traditional North American markets.
Market acceptance of Western's two streams of synthetic crude oil continues to
be high, with these products consistently meeting or exceeding customer
expectations. While Western's upgrading provides synthetic crude oil with
superior qualities for processing, Western's products also lend themselves to
blending and customizing and this flexibility may lead to significant
improvements in refinery efficiencies for Western's customers. A dedicated
pipeline to the Edmonton terminals has ensured the integrity of Western's
product and in order to maintain this quality, Western's products are shipped
in segregated streams.
INSURANCE
The Owners obtained insurance to protect against certain risks of loss during
the construction of the Mine, Extraction Plant and the Upgrader. The insurance
is typical for a project of the nature of the Project.
In addition, Western obtained, for its own account, a $200 million insurance
policy which, throughout the period March 2000 through April 2004, covered
certain costs, expenses and losses of revenue including: (i) costs and
expenses or loss of revenues arising from a delay in achieving the guaranteed
production levels as set out in the feasibility study; (ii) costs and expenses
incurred in connection with the modification, repair or replacement of
equipment or material, which are directly related to achieving the guaranteed
production levels; (iii) escalation in Project costs beyond the budgeted
Project costs, which are
-16-
directly related to achieving the guaranteed production levels; and (iv) debt
service costs related to obligations incurred to finance any of (i), (ii) or
(iii).
Arbitration proceedings under the terms of Section IV of Western's cost
overrun and Project delay insurance policy have been initiated to resolve the
disputes with insurers surrounding the claims for payment pursuant to this
policy. Western has filed insurance claims for the full limit of the policy,
namely $200 million, and will also be seeking interest and punitive and
aggravated damages. The arbitration panel has now been constituted. A number
of procedural motions have been heard to date and further motions are expected
to occur prior to the commencement of the main arbitration hearing. Some of
the decisions relating to the preliminary motions have been appealed and
determined and one is currently under appeal, resulting in delays to the
commencement of the main arbitration hearing, which is now expected to occur
in 2007.
In addition, insurers involved in the dispute with Western have withheld
insurance proceeds payable to Western for damages related to the January 2003
fire and related freezing damage. With the exception of the amounts withheld,
these claims have now been resolved. To date, Western has received $16.1
million from insurers in respect of claims relating to the fire and freeze
damage. See "General Development of the Business - Operating Activities".
During 2005, the Joint Venture announced it had reached a settlement with the
insurers on its loss of profits claim. The final settlement amount totalled
$220 million ($44 million net to Western), of which Western received $19.4
million. Amounts withheld are by those common insurers on Western's start-up
and delay insurance policy which, as discussed above, is currently in
arbitration proceedings. The principal amount of Western's outstanding
insurance claims is $244 million. There can be no assurance that Western will
receive any or all of these outstanding amounts. The potential benefit of
collection of insurance proceeds is not factored into Western's financing
strategy. Should these proceeds, or part thereof, be received, Western would
conduct appropriate analysis to determine where to best deploy the funds.
Western's current insurance is designed to protect its ownership interest
against losses or damage to the Mine, Extraction Plant and Upgrader, to
preserve its operating income and to protect against its risk of loss to third
parties. Western also renewed its property and business interruption insurance
but increased the limit to reflect the significant increase in commodity
prices. Western also maintains other insurance coverages addressing other
parts of our operations to sufficiently guard against unforeseen events and
risks.
AOSP EXPANSIONS
Under the terms of the Joint Venture Agreement, should an Owner wish to
undertake an expansion of a key component of the Project, the mining of the
remaining area of Lease 13 or the construction of a new mine or upgrader, it
must first advise the other Owners and provide a period of time for them to
advise as to whether or not they will participate in the feasibility study for
the proposed expansion. If an Owner does not originally participate in a
feasibility study it may, upon completion of the feasibility study, purchase
the right to participate in the feasibility study and the expansion by paying
twice the cost of its proportionate share of the feasibility study.
If an expansion is to take place, an Owner must satisfy certain conditions
relating to financial capability to undertake the proposed expansion.
Expansion on the eastern portion of Lease 13 or in respect of the Upgrader
prior to five years after Project Start-up may only be undertaken with the
written approval of Shell (provided Shell or an affiliate has an ownership
interest in the Upgrader and is an Owner and operator of the Scotford Refinery
at the time in respect of expansion to the Upgrader). In order to
-17-
participate in an expansion in respect of the east area of Lease 13, each
Owner would be required to pay to Shell an amount based on the share of the
recoverable bitumen reserves to be acquired by such Owner. Owners' interests
will be adjusted to reflect expansions. Expansions may only take place by
Owners with total ownership interest of a minimum of 40% in the key component
of the Project being expanded. If an Owner other than Shell does not
participate in an expansion on the east portion of Lease 13 or in Shell's
other Athabasca Leases it shall have no further expansion rights.
DISPOSITIONS
Owners may not assign or transfer ownership interests in the Project until
three years after Project Start-up unless such dispositions are: (i) a grant
of security and the secured party acknowledges it is subject to the Joint
Venture Agreement and is subordinate to all liens granted thereunder; (ii)
dispositions to affiliates; (iii) to a person meeting certain specified
financial requirements; and (iv) certain limited public or private placement
offerings of securities. Partial assignments are only permissible if all
resulting ownership interests are 10% or greater. The Owners have also granted
each other a right of first refusal in respect of proposed dispositions.
PROPOSED EXPANSIONS AND FEASIBILITY STUDY AGREEMENT
During 2005, the Project adopted an expansion strategy of developing identical
incremental trains of production. It is anticipated that three back-to-back
100,000 barrel per day trains will be added to the Mine with a corresponding
increase in capacity at the Upgrader. This "building-block" strategy has
several competitive advantages including economies of scale in engineering
design, procurement of components and materials and labour retention. The
timing of the current expansion plans contemplates 100,000 barrels per day of
incremental production being added every two years starting in 2009, 2011 and
2013. With the leases known to have resources at the present time, this would
imply an eight to ten year construction period. With significantly more
people, time and effort dedicated to the planning process of the expansion
compared to the first construction initiative, it is believed that
cost-overruns will be largely mitigated. Further expansion efforts may be
conducted as additional leases are included in the AMI. As currently designed,
expansion plans would result in the AOSP's production increasing from 180,000
to 200,000 barrels per day following production optimization initiatives to
500,000 to 600,000 barrels per day by 2015. Initial capital costs for the
first expansion phase have been estimated at up to $200 per annual flowing
barrel. Based on the continuous construction strategy, the first expansion
phase will include items which will be utilized by subsequent phases and,
therefore, the capital intensity of subsequent phases is expected to be
reduced. Capital will be deployed once for permanent personnel facilities,
permanent construction equipment, utilities infrastructure, etc rather than a
strategy of multiple stand-alone expansion efforts. See "Forward-Looking
Information" and "Risks and Uncertainties".
Beyond the first phase of the expansion, the Project's longer term optimization
plan includes:
o development of additional resources located on Leases 88 and 89
with a capacity of approximately 100,000 barrels per day of
bitumen production. Regulatory approval would be received as
part of the omnibus filing;
o development of additional resources on Lease 9 which was
acquired by Shell in 2004. It is estimated that Lease 9 could
result in an additional 200 million barrels net to Western.
Shell also acquired Lease 17 in 2004 but this parcel has not yet
been evaluated;
o evaluation of additional mineable leases acquired recently by
Shell in the Athabasca region. An extensive drilling program on
these leases, together with Lease 17, is planned for the
2006/2007 drilling season. The results will be reviewed over the
balance of 2006 and a mine plan developed accordingly, should
economic resources exist; and
-18-
o analyses of processes and/or equipment that will result in a
reduction of unit operating costs in the extraction process and
the dependency on natural gas.
The timing and details of any expansion will be subject to the outcome of
future evaluations of economics, market needs, regulatory requirements and
sustainable development considerations.
The pre-feasibility phase has been completed and the Owners are now
progressing through the feasibility study which is expected to be completed in
the third quarter of 2006. The scope of the feasibility study is much more
involved and includes such analysis as the location and size of the mine, the
nature, location and extent of the mine facilities, the upgrader facilities
and the third party facilities, a plan for the construction of these
additional facilities in addition to numerous other activities. The
feasibility study will also more narrowly define the capital costs associated
with the expansion initiatives to an estimate within +/- 10%. The interests of
the parties to this agreement are the same as in the Joint Venture Agreement;
however, the terms of the Joint Venture Agreement do not govern this
undertaking. This feasibility study agreement does not add to nor detract from
any of Western's rights under the Joint Venture Agreement. The overall
management has been delegated to the Executive Committee of the Joint Venture,
which delegates certain matters to the project administrator. Western may
withdraw from the feasibility study agreement at any time; however, Western
may be reinstated by paying twice the costs it would have otherwise been
required to pay to preserve its rights to participate in a feasibility study
and expansion pursuant to the Joint Venture Agreement. See "Forward-Looking
Information" and "Risks and Uncertainties".
REGULATORY APPROVALS
On April 23, 2004, Western announced that the AOSP received approval from both
the provincial and federal government cabinet for the first phase of the
Jackpine Mine in the Athabasca oil sands region of northern Alberta. Since
these approvals have been received, the Owners have advanced the continuous
construction scenario and filed a regulatory permit in April 2005 which
included a revision to the existing Mine permit to accommodate the
de-bottlenecking volumes as well as the first phase of the expansion. With
permits in place and those recently filed, the goal is to produce 300,000
barrels per day by the end of 2009. The first expansion phase intends to
extract resources from the east side of Lease 13 in addition to those located
on Lease 90 and includes a mining and extraction facility. It is anticipated
that Western will seek board approval for the first expansion phase in the
latter half of 2006. Approval will be preceded by the substantial completion
of design and appropriate multi-company, multi-disciplinary reviews aimed at
improving the certainty of project execution and reducing the variability on
capital costs to an acceptable level Certain long lead items have already been
ordered with a corresponding capital outlay to ensure these critical items are
delivered on site at the appropriate time. Approval of the first phase of the
expansion this year, combined with Western compliance with certain provisions
under the JVA, will allow the Corporation to recognize its pro rata share of
the reserves associated with this expansion.
In addition, an omnibus regulatory permit is being prepared that, once
submitted and approved, would enable the Project to produce 500,000 barrels
per day. It is envisioned that this permit will be submitted during 2006 with
the expectation that approval will be received in mid-2008.
The timing and receipt of regulatory approvals is subject to certain risks and
uncertainties. See "Forward-Looking Information" and "Risks and
Uncertainties".
RESOURCES
Western is a party to the AOSP Participation and AMI Agreement. The AMI
stipulates that the current Joint Venture parties have rights to participate
in any additional leases that are acquired by any one of the parties in the
Athabasca region. Western is entitled to participate in all future expansions
on Lease 13 and in the
-19-
other oil sands opportunities with Shell and Chevron in respect of Shell's
Other Athabasca leases, and within a defined area of mutual interest.
The following table outlines the independently evaluated resources available
for future expansion opportunities on the remainder of Lease 13 together with
Leases 88, 89, 90, 9 and 17 as verified by Norwest Corporation, an independent
mining and geological consultant. Except in the case of Lease 17, the resource
estimates set forth in the Norwest Report are based on certain limiting
criteria including a minimum bitumen content of 7% to total weight, minimum
mining thickness of 3 metres and maximum total volume to bitumen in place
("TV:BIP") of 12:1.
The volumetric amounts are expressed on a Discovered Resources basis.
Definitions and guidelines which govern the evaluation of reserve and resource
quantities are contained in the Canadian Oil and Gas Evaluation Handbook.
There is considerable difference between the evaluation of reserves versus
resources. Discovered Resources are comprised of recoverable and unrecoverable
resources. Recoverable resources are those quantities of oil and gas
anticipated to be economically recoverable, which may be categorized as
reserves once other conditions such as obtaining regulatory approvals, capital
commitment and ownership of the leases have been satisfied. Western has not
yet satisfied the requirements on these leases. Only the recoverable portion
of the resources listed below will ultimately be booked as reserves.
Evaluations will be conducted in the future to determine these amounts.
TOTAL PROJECT
(MMBBLS)
-------------------------------
FUTURE OPPORTUNITIES (DISCOVERED RESOURCES) High Best Low
Estimate Estimate Estimate
(P10) (P50) (P90)
- ------------------------------------------------------------------------------
Remainder of Lease 13 5,251 5,028 3,194
2,382
Leases 88 and 89 2,038 856
Lease 90 269 253 162
Lease 9 and 17(2) 2,110 899 431
- ------------------------------------------------------------------------------
Total 10,012 8,218 4,643
- ------------------------------------------------------------------------------
(1) Table above represents total Project interest in the leases which are
currently held by Shell. Under the AMI, Western has the right to
participate in these leases to a 20 percent level.
(2) Norwest attributed only inferred resources to Lease 17 (high estimate
only) reflecting a probability of only 10% that the resource equals or
exceeds the estimated amount given the limited amount of data available on
this lease. Major assumptions used in the classification of inferred
resources for Lease 17 were average in-place bitumen content of 10% to
total weight and ore thickness of approximately 15 metres over less than
half the lease area. Due to the level of uncertainty on this lease it
should not be assumed that all or any part of an inferred resource will be
upgraded as a result of continued exploration.
LAND POSITION
During 2005, Shell purchased Leases 15, 351, 352, 631, 632, 309 and 310 at
public land auctions of the Alberta Government which have not been evaluated.
Pursuant to the AMI, Western has the right to participate to its 20 per cent
interest in the development of these leases. Extensive core-hole drilling
programs are planned over the next two years to evaluate the resource
potential of these additional leases.
Western also has the right to participate in the five heavy oil sand leases
that Chevron recently acquired. These in-situ leases cover approximately
30,300 hectares and possess an estimated 7.5 billion barrels of oil in place
(according to Chevron's internal estimates). They have the potential for
bitumen extraction through in-situ recovery methods. Pursuant to the terms of
the AMI, Western has the right to participate to a 20 percent interest upon
Chevron serving notice to the other Joint Venture parties of its recent
purchase followed by certain payments to Chevron.
-20-
Our undeveloped land position also includes an in-situ lease acquired by
Western during 2005 covering 3,329 gross hectares. Both Shell and Chevron have
elected to participate to their 20 percent interest pursuant to the AMI.
Western has significantly increased its internal organizational capabilities
in 2005 with the addition of senior technical staff focused on developing its
in-situ strategy. This strategy includes the ability to make critical
assessments in both the Shell and Chevron property rights in addition to
pursuing the purchase of undeveloped properties directly and offering
reciprocal option rights to Shell and Chevron. The exploration and development
of this significant land and resource base if warranted, both mineable and
in-situ, could involve a substantial and material capital commitment on the
part of Western to develop the underlying resource.
The following table summarizes the gross and net area associated with each of
these Leases together with existing leases.
NET AREA TO
GROSS AREA WESTERN INTEREST WESTERN
(ACRES) (%) (ACRES)
-------------- ----------------- ------------
AOSP/EXPANSIONS
Lease 13 49,872 20 9,974
Lease 88 28,108 20 5,622
Lease 89 14,765 20 2,953
Lease 90 2,881 20 576
Lease 9 14,896 20 2,979
Lease 17 21,508 20 4,302
- ---------------------------------- -------------- ----------------- ------------
132,030 - 26,406
- ---------------------------------- -------------- ----------------- ------------
ADDITIONAL MINEABLE LEASES
Lease 15 3,796 20 759
Lease 351 22,773 20 4,555
Lease 352 16,447 20 3,289
Lease 631/632 6,642 20 1,328
Lease 309 11,387 20 2,277
Lease 310 7,591 20 1,518
- ---------------------------------- -------------- ----------------- ------------
68,636 - 13,726
- ---------------------------------- -------------- ----------------- ------------
IN-SITU LEASES
Chevron Leases 75,000 20 15,000
Lease 353 (Western) 8,225 60 4,935
- ---------------------------------- -------------- ----------------- ------------
83,225 - 19,935
- ---------------------------------- -------------- ----------------- ------------
TOTAL 283,891 - 60,067
-------------- ----------------- ------------
FORWARD CONTRACTS
Western has entered into various commodity pricing agreements designed to
mitigate the exposure to the volatility of crude oil prices in U.S. dollars
with the objective of solidifying the Corporation's balance sheet in the years
where significant capital expenditures are planned. Western no longer holds
fixed priced swap contracts but utilizes a combination of a series of put and
call options in order to provide a floor West Texas Intermediate ("WTI") price
yet maintain upside potential on a portion of the Corporation's base volumes
should commodity prices continue to rise. As at January 1, 2006, the following
positions are in place:
-21-
Period (calendar year)
=======================================
2007 2008 2009
------------ ----------- --------------
Put options purchased (bbls/d) 20,000 20,000 20,000
Avg. put strike price (US$/bbl) 52.50 54.25 50.50
Call options sold (bbls/d) 10,000 15,000 15,000
Avg. call strike price (US$/bbl) 92.50 94.25 90.50
GLJ has not included any effects of ing activities in the GLJ Report.
TAX HORIZON
Western is currently not required to pay cash income taxes. Western estimates
that cash income taxes will become payable within five to seven years,
depending on commodity prices, foreign exchange rates, operating costs,
interest rates, future annual taxable income levels, expansions of the Project
and other business activities. Changes in these factors from estimates used by
Western could result in Western paying income taxes earlier or later than
expected.
DIVIDEND POLICY
No dividends have been paid on any shares of Western since the date of its
incorporation. The Corporation currently intends to retain its earnings to
finance the growth and development of its business and therefore it is not
expected that dividends will be paid on the Common Shares in the immediate or
foreseeable future. In addition, the note indenture governing the Notes
contains restrictions on the Corporation's ability to pay dividends or
distributions of any kind. See "Credit Ratings".
DESCRIPTION OF SHARE CAPITAL
The authorized share capital of the Corporation includes an unlimited number
of Common Shares, an unlimited number of Non-voting Convertible Class B Equity
Shares ("Non-voting Convertible Equity Shares"), an unlimited number of Class
C Preferred Shares ("Class C Shares") and an unlimited number of Class D
Preferred Shares, issuable in series ("Class D Shares").
The following is a brief description of the attributes of the Corporation's
Common Shares, Non-voting Convertible Equity Shares, Class C Shares and Class
D Shares.
COMMON SHARES
The holders of Common Shares are entitled, subject to specified preferences in
favour of holders of Class C Shares and Class D Shares, to dividends if, as
and when declared by the directors and to one vote per share at meetings of
the holders of Common Shares and, upon liquidation, subject to specified
preferences in favour of holders of Class C Shares and Class D Shares, to
share equally share for share with the Non-voting Convertible Equity Shares in
the remaining assets of the Corporation.
-22-
NON-VOTING CONVERTIBLE EQUITY SHARES
The holders of Non-voting Convertible Equity Shares are entitled to dividends
in parity with the Common Shares if, as and when declared by the directors
and, upon liquidation, subject to specified preferences in favour of holders
of Class C Shares and Class D Shares, to share equally share for share with
the Common Shares in the remaining assets of the Corporation. Holders of
Non-voting Convertible Shares are not entitled to receive notice of, attend or
vote at any meetings of shareholders unless otherwise entitled pursuant to
applicable laws.
Each Non-voting Convertible Equity Share shall entitle the holder to acquire
(subject to adjustment), at no additional cost, one Common Share at 4:30 p.m.
(Calgary time) (the "Acquisition Expiry Time") on the earlier of: (i) five (5)
business days following the date upon which a receipt for a prospectus (the
"Qualifying Prospectus") to be filed by Western with respect to the
distribution of the Common Shares upon conversion of the Non-voting
Convertible Equity Shares has been issued by the last of the securities
commissions or similar regulatory authorities in the Province of Alberta and
such other provinces of Canada in which the Corporation files such Qualifying
Prospectus (based upon the residences of Canadian subscribers); and (ii) 12
months from the date of issuance of the Non-voting Convertible Equity Shares.
Non-voting Convertible Equity Shares outstanding at the Acquisition Expiry
Time shall be deemed to be converted by the holder, without any further action
on the part of the holder, at the Acquisition Expiry Time. As at the date
hereof, there are no outstanding securities of this class.
CLASS C SHARES
The Corporation is authorized to make one issuance of Class C Shares. The
holders of Class C Shares shall not be entitled to receive notice of, attend
or vote at any meetings of the shareholders of the Corporation unless
otherwise entitled pursuant to applicable laws but shall be entitled to
receive in respect of each calendar year, if, as and when declared by the
directors, a non-cumulative preferential dividend in the amount (if any)
declared by the directors. No dividends shall be declared or paid in any year
on the Common Shares, Non-voting Convertible Equity Shares, Class D Shares or
any other shares of the Corporation ranking junior to the Class C Shares from
time to time with respect to the payment of dividends, unless all dividends
which shall have been declared and which remain unpaid on the Class C Shares
then issued and outstanding shall have been paid or provided for at the date
of such declaration or payment. Upon liquidation, holders of Class C Shares
shall be entitled to payment of an amount (subject to adjustment) equal to the
amount or value of the consideration paid for such shares (the "Redemption
Amount") in priority to the Common Shares, the Non-voting Convertible Equity
Shares, the Class D Shares and any other shares ranking junior to the Class C
Shares from time to time. The Class C Shares are redeemable by the Corporation
or the holders of Class C for the Redemption Amount. As at the date hereof,
there are no outstanding securities of this class.
CLASS D SHARES
The Class D Shares are entitled to receive notice of, attend and vote at any
meetings of shareholders and are convertible into Common Shares, prior to
redemption, on a one-for-one basis. The Class D Shares are redeemable by the
Corporation at a price equal to their issue price plus a cumulative dividend
of 12% per annum compounded semi-annually until January 1, 2007, from which
date the dividend increases by 3% per quarter to a maximum of 24% per annum.
As at the date hereof, there are no outstanding Class D Shares.
-23-
MARKET FOR SECURITIES
The Common Shares of the Corporation are listed for trading on the Toronto
Stock Exchange ("TSX") under the symbol "WTO". The following table sets for
the high, low and closing trading prices and the volume of Common Shares
traded on the TSX for each monthly of the most recently completed financial
year. The following data has been adjusted to reflect the 3 for 1 Share Split.
MONTH HIGH LOW CLOSING VOLUME
- ---------------- ------------- -------------- --------------- -------------
January 15.19 13.17 14.52 9,053,994
February 21.33 14.51 19.72 14,785,455
March 21.43 17.45 18.67 17,556,693
April 20.00 17.50 18.59 11,899,557
May 24.74 18.50 19.33 11,439,684
June 24.74 18.68 23.79 12,978,115
July 28.99 24.41 28.50 9,443,560
August 33.19 27.00 29.35 19,784,844
September 32.40 27.35 27.55 13,299,253
October 28.30 23.60 25.40 13,604,174
November 29.40 25.20 27.02 16,646,233
December 29.00 25.18 27.81 9,551,977
CREDIT RATINGS
On April 23, 2002, Western completed a private placement offering of US$450
million senior secured Notes. The Notes bear interest at 8.375% per annum,
payable on May 1 and November 1 of each year, beginning on November 1, 2002
and mature on May 1, 2012. Western's Notes are currently rated by two separate
agencies, Standard and Poors ("S&P") and Moody's Investor Service. ("Moody's")
Please refer to the table below for the respective ratings assigned to the
Notes.
- -----------------------------------------------------------------------------
TYPE OF SECURITY S&P MOODY'S
- -----------------------------------------------------------------------------
US$450 Million Senior Secured Notes BB+/Positive Ba2
- -----------------------------------------------------------------------------
S&P Rating Definition - Obligations rated BB are regarded as having
significant speculative characteristics. An obligation rated BB is less
vulnerable to non-payment than other speculative issues. However, it faces
major ongoing uncertainties or exposure to adverse business, financial, or
economic conditions which could lead to the obligor's inadequate capacity to
meet its financial commitment on the obligation. BB+ is one level below that
which is considered "Investment Grade" under the S&P rating system. The (+)
sign is added to show relative standing within the major rating categories.
The ratings outlook for Western by S&P is "Positive" which indicates that a
rating may be raised.
Moody's - Moody's long-term obligation ratings are opinions of the relative
credit risk of fixed-income obligations with an original maturity of one year
or more. They address the possibility that a financial obligation will not be
honoured as promised. Such ratings reflect both the likelihood of default and
any financial loss suffered in the event of default. Obligations rated Ba are
judged to have speculative elements and are subject to substantial credit
risk. Moody's appends numerical modifiers 1, 2, and 3 to
-24-
each generic rating classification from Aa through Caa. The modifier 1
indicates that the obligation ranks in the higher end of its generic rating
category; the modifier 2 indicates a mid-range ranking; and the modifier 3
indicates a ranking in the lower end of that generic rating category.
Investment grade under the Moody's rating system would be Baa3 and higher.
A security rating is not a recommendation to buy, sell or hold securities and
may be subject to revision or withdrawal at any time by the rating
organization.
DIRECTORS AND OFFICERS
The following table lists the names of the directors and officers of Western,
their municipalities of residence, positions and offices with Western and
principal occupations during the preceding five years:
NAME AND MUNICIPALITY OF PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST DIRECTOR SINCE
RESIDENCE AND OFFICE FIVE YEARS
- ----------------------------- ---------------- ------------------------------------------ ----------------
DIRECTORS
David J. Boone(4)(5) Director President of Escavar Energy Inc., a May 2005
Calgary, Alberta; Canada private oil and gas corporation, since
2003. Prior to 2003, Executive
Vice-President of EnCana Corporation and
President of the EnCana Corporation's
Offshore and International Operations and
Executive Vice-President and Chief
Operating Officer of PanCanadian Energy.
Prior to 2001, various executive roles
with Imperial Oil Limited, an integrated
oil and gas company.
Tullio Cedraschi(2)(4) Director President and Chief Executive Officer of October 2000
Montreal, Quebec: Canada CN Investment Division, the entity
responsible for investing the assets of
the Canadian National Railways Pension
Trust Funds.
Geoffrey A. Cumming(3)(5)((7)) Lead Director Managing Director of Zeus Capital October 1999
Auckland, New Zealand Limited, a private New Zealand investment
corporation, since March 2003.
Vice-Chairman of Gardiner Group Capital
Limited, a private Canadian investment
corporation, to June 2003 and prior to
July 2002, Chief Executive Officer of
Gardiner Group Capital Limited.
James C. Houck President, Chief President and Chief Executive Officer of May 2005
Calgary, Alberta; Canada Executive the Corporation since April 2005.
Officer and Previously principal of FrontStreet
Director Partners, a private United States
investment firm, since 2003. President
of ChevronTexaco's Worldwide Power and
Gasification Inc. from 1998 to 2003.
President of Texaco Development
Corporation from 1996 to 2001.
-25-
NAME AND MUNICIPALITY OF PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST DIRECTOR SINCE
RESIDENCE AND OFFICE FIVE YEARS
- ----------------------------- ---------------- ------------------------------------------ ----------------
Oyvind Hushovd(2)(3) Director Chairman and Chief Executive Officer of December 2003
Kristiansand, Norway Gabriel Resources Ltd., a mining
corporation, from March 2003 to May
2005. President and Chief Executive
Officer of Falconbridge Ltd., a mining
corporation, from 1996 to February 2002.
John W. Lill(2)(4) Director Executive Vice President and Chief December 2003
Toronto, Ontario; Canada Operating Officer of Dynatec Corporation,
a mining corporation, since November
2003. President and Chief Operating
Officer (Base Metals) with BHP Billiton,
a mining corporation, from 2001 to 2003
and Chief Operating Officer (Copper) with
BHP Billiton from 2000 to 2001. From 1998
to 2001, Vice President of Mining
Operations for Rio Algom Ltd., a mining
corporation.
Randall Oliphant(1)(5) Director Chairman and Chief Executive Officer of February 2005
Toronto, Ontario; Canada Rockcliff Group Limited, a private
company investing mainly in the mining
sector, since 2003. Prior thereto, served
in various senior financial roles in
Barrick Gold Corporation culminating in
appointment as Chief Executive Officer in
1999 until 2003.
Robert G. Puchniak(1) Director Executive Vice President and Chief October 1999
Winnipeg, Manitoba; Canada Financial Officer of James Richardson &
Sons, Limited ("James Richardson") since
March 2001. Prior thereto,
Vice-President, Finance and Investment,
James Richardson since 1996.
Guy J. Turcotte((7))(9) Chairman and July 1999
Calgary, Alberta; Canada Director Chairman of the Board of Directors.
Prior to April 2005, President and Chief
Executive Officer of Western from July
1999. Also, Chairman of Fort Chicago
Energy Partners, L.P. since September
1997 and Chief Executive Officer until
December 2002.
Mac H. Van Wielingen(1)(3)((6)) Director Co-Chairman of ARC Financial December 1999
Calgary, Alberta; Canada Corporation ("ARC"), a private investment
management company focused on the energy
sector, and Chairman of ARC Energy Trust.
Previously, Chief Executive Officer of
ARC from 1989 until June 2000.
OFFICERS
Steve Reynish ((8)) Executive Executive Vice-President and Chief --
Calgary, Alberta; Canada Vice-President Operating Officer of Western since
and Chief January 1, 2006; prior thereto, Senior
Operating Officer Vice President Mining Operations
including secondment to Albian Sands
Energy as Chief Operating Officer since
2002
-26-
NAME AND MUNICIPALITY OF PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST DIRECTOR SINCE
RESIDENCE AND OFFICE FIVE YEARS
- ----------------------------- ---------------- ------------------------------------------ ----------------
David A. Dyck Senior Vice-President, Finance and Chief --
Calgary, Alberta; Canada Vice-President, Financial Officer of Western since
Finance and April 2000; prior thereto, Senior Vice
Chief Financial President Finance & Administration and
Officer Chief Financial Officer of Summit
Resources Limited ("Summit") since
September 1998; Vice President Finance
and Chief Financial Officer of Summit
from October 1996 to September 1998.
Charles W. Berard Corporate Partner with Macleod Dixon LLP, --
Calgary, Alberta; Canada Secretary Barristers & Solicitors.
NOTES:
(1) Member of the Audit Committee.
(2) Member of the Compensation Committee.
(3) Member of the Governance Committee.
(4) Member of the Health, Safety and Environment Committee.
(5) Member of the Reserves and Business Risk Committee
(6) Mr. Van Wielingen was a director of Gauntlet Energy Corporation
("Gauntlet") from September 1999 to December 2003. On June 17, 2003, an
order was granted under the COMPANIES CREDITORS ARRANGEMENT ACT which
provided creditor protection to Gauntlet to develop a financial
restructuring plan that was approved by its creditors.
(7) Mr. Guy Turcotte resigned as President and Chief Executive Officer
effective April 15, 2005 and assumed the position of Chairman of the Board
and Director. Mr. Geoff Cumming stepped down as Chairman effective April
15, 2005, continuing as the independent Lead Director.
(8) As announced on November 23, 2005, Mr. Frangos decided to step down as
Executive Vice President and Chief Operating Officer effective January 1,
2006 to be replaced by Mr. Steve Reynish, previously Senior Vice President
Mining with Western and prior to that, seconded into Albian Sands Energy
Inc. as its Chief Operating Officer since 2002. Mr. Frangos will stay on
with the Company as Senior Advisor to management and to the Board.
(9) On May 10 1998, Mr. Turcotte resigned as a director of Chauvco
International Ltd. ("Chauvco"). On January 26, 1999, a bankruptcy
receiving order was granted by the Alberta Court of Queen's Bench against
Chauvco and it was susequently ceased traded for failing to file financial
statements and other related documents.
Each director holds office until the next annual meeting of shareholders of
the Corporation or until their successors are duly elected or appointed.
As at March 28, 2006, the directors and officers of the Corporation, together
with their respective spouses, children or corporations controlled by them own
or control, directly or indirectly, an aggregate of 3,368,614 Common Shares or
approximately 2.1% of the issued and outstanding voting securities of the
Corporation. Not included in the amount above is 5,650,781 Common shares owned
by Turcotte Family Holdings Ltd. ("Turcotte Holdings"). Mr. Turcotte is a
discretionary beneficiary under a family trust that exercises voting control
over Turcotte Holdings. Mr. Turcotte does not own, directly or indirectly, or
exercise control or direction over any voting shares of Turcotte Holdings.
Investors should be aware that some of the directors and officers of the
Corporation are directors and officers of other private and public companies.
Some of these private and public companies may, from time to time, be involved
in business transactions or banking relationships which may create situations
in which conflicts might arise. Any such conflicts shall be resolved in
accordance with the procedures and requirements of the relevant provisions of
the BUSINESS CORPORATIONS ACT (Alberta), including the duty of such directors
and officers to act honestly and in good faith with a view to the best
interests of the Corporation.
-27-
AUDIT COMMITTEE
COMPOSITION AND QUALIFICATIONS
The Audit Committee consists of three outside independent directors: Robert G.
Puchniak (Chair), Randall Oliphant and Mac H. Van Wielingen, all of whom are
financially literate.
In considering criteria for the determination of financial literacy, the Board
of Directors looks at the ability to read and understand a balance sheet, an
income statement and a cash flow statement of a public company.
The following is a brief description of the education and experience of each
of the members of the Audit Committee:
ROBERT G. PUCHNIAK, CHAIRMAN AND INDEPENDENT DIRECTOR
Mr. Puchniak was appointed Executive Vice-President and Chief Financial
Officer of James Richardson & Sons, Limited, an investment and holding
corporation, in March 2001 and prior thereto was Vice-President, Finance and
Investment with James Richardson & Sons, Limited since November 1996. Mr.
Puchniak was President and Chief Executive Officer of Tundra Oil and Gas Ltd.,
a private oil and gas corporation, from January 1989 to April 2003. Mr.
Puchniak has also held positions with Gendis Inc. and Richardson Securities
Limited. Mr. Puchniak is a director of a number of public and private
corporations including James Richardson International Limited, Tundra Oil and
Gas Ltd., Opti Canada Inc., Trident Resources Corp, Petrobank Energy and
Resources Ltd., Richardson Partners Financial Holdings Limited and Lombard
Realty Limited. Past involvements include Director, Moffat Communications
Limited, Terraquest Energy Corporation and Richland Petroleum Corporation;
Chairman, Manitoba Teachers' Retirement Fund; Chairman, Council of Examiners,
Institute of Chartered Financial Analysts; and President, Winnipeg Society of
Financial Analysts. Mr. Puchniak holds a Bachelor of Commerce (Honours) degree
from the University of Manitoba and was awarded the University Gold Medal for
his achievements. He earned a Chartered Financial Analyst designation in 1975.
RANDALL OLIPHANT, INDEPENDENT DIRECTOR
Mr. Randall Oliphant is the Chairman and Chief Executive Officer of Rockcliff
Group Limited, a private corporation actively involved in the strategic
planning and corporate development of its investee companies, principally in
the mining sector. He is on the Advisory Board of Metalmark Capital LLC
(formerly Morgan Stanley Capital Partners) and serves on the Boards of a
number of public, private companies and not-for-profit organizations. Until
2003, he was the President and Chief Executive Officer of Barrick Gold
Corporation, and served in senior financial positions since joining the
company in 1987 prior to being appointed Chief Executive Officer in 1999. Mr.
Oliphant holds a B.Comm. from the University of Toronto and is a Chartered
Accountant.
MAC H. VAN WIELINGEN, INDEPENDENT DIRECTOR
Mr. Van Wielingen is a founder and currently Co-Chairman of ARC Financial
Corporation, an investment management corporation focused on the energy sector
in Canada. Mr. Van Wielingen is also a founder and currently Chairman of ARC
Energy Trust. He is a past and a current director of numerous private and
public energy companies in Canada and has 25 years of experience in the
investment business relating to the energy sector in Canada. Mr. Van Wielingen
holds an Honours Business Degree from the University of Western Ontario
Business School and has studied post-graduate Economics at Harvard University.
-28-
RESPONSIBILITIES AND TERMS OF REFERENCE
The following is a summary of the key roles and responsibilities of the Audit
Committee. Full particulars are set out in the Audit Committee Charter which
is attached as Appendix C hereto.
The Audit Committee approves Western's interim unaudited consolidated
financial statements, press releases and reviews the annual audited
consolidated financial statements and certain corporate disclosure documents
including the annual information form, management's discussion and analysis,
offering documents including all prospectuses and other offering memoranda
before they are approved by the Board. The Committee reviews and makes a
recommendation to the Board in respect of the appointment of the external
auditor and it monitors accounting, financial reporting, control and audit
functions. The Audit Committee meets to discuss and review the audit plans of
the external auditors and is directly responsible for overseeing the work of
the external auditor with respect to the preparing or issuing of the auditor's
report or the performance of other audit, review or attest services including
the resolution of disagreements between management and the external auditor
regarding financial reporting. The Committee questions the external auditor
independently of management and reviews a written statement of the external
auditors' independence based on the criteria found in the recommendations of
the Canadian Institute of Chartered Accountants. The Committee considers and
makes a recommendation to the Board as to the compensation of the external
auditor and ensures that fees paid to the external auditor for audit and
non-audit services are publicly disclosed. The Committee must be satisfied
that adequate procedures are in place for the review of the Corporation's
public disclosure of financial information extracted or derived from its
financial statements and it periodically assesses the adequacy of those
procedures. In addition, it reviews the internal control procedures to
determine their effectiveness to ensure compliance with applicable legal
requirements, regulatory requirements and Western's policies. The Audit
Committee reviews the controls in place with respect to officers' expenses and
perquisites, reviews insurance coverage for significant business risks and
uncertainties and reviews material litigation and its impact on financial
reporting. The Committee has established procedures for dealing with
complaints, submissions or concerns on an anonymous and confidential basis
which come to its attention with respect to accounting, internal accounting
controls or audit matters.
The Audit Committee's mandate was modified during 2005 to transfer its roles
and responsibilities concerning the review of the independent qualified
reserves evaluator's report on the Corporation's estimated oil and gas
reserves to the Reserves and Business Risk Committee. The Reserves and
Business Risk Committee was commissioned during 2005 and is also a committee
of the Board.
AUDITOR SERVICE FEES
PricewaterhouseCoopers LLP has served as the auditors of Western since its
incorporation. The following table summarizes the total fees paid to
PricewaterhouseCoopers LLP for the years ended December 31, 2005 and December
31, 2004
2005(1) 2004
----------- ----------
Audit fees $146,396 $131,980
Tax fees $133,108 24,960
- -----------------------------------------------------------------------------
TOTAL $279,504 $156,940
NOTE:
(1) Paid or estimated to be payable for 2005 services.
Audit fees were paid for professional services rendered by the auditors for
the audit of the Corporation's annual financial statements or services
provided in connection with statutory and regulatory filings.
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Audit-related fees were paid for review of quarterly financial statements of
Western, attendance at quarterly audit meetings, and for services provided in
connection with financings. Tax fees were paid for tax advice and assistance
with tax audits, including GST and property tax reviews.
All permissible categories of non-audit services require pre-approval from the
Audit Committee.
RISKS AND UNCERTAINTIES
The Corporation is exposed to a number of risks and uncertainties relating to
its operations.
THE MINE, EXTRACTION PLANT AND UPGRADER MAY NOT PERFORM AS PLANNED.
The Project may encounter interruptions in production or additional costs due
to many factors, including:
o breakdown or failure of equipment or processes;
o design errors;
o operator errors;
o violation of permit requirements;
o disruption in the supply of energy; and
o catastrophic events such as fire, earthquake, storms or
explosions.
The Project consists of multiple facilities, all of which must be run on an
integrated and co-ordinated basis. There can be no assurance that each
component will continuously operate as designed or expected or that the
necessary levels of integration and co-ordination will continuously be
achieved. Some of the mining and extraction processes employed in the Project
represent new applications of established processes, processes that are larger
in scale than other commercial operations, or new processes that are scaled-up
from the pilot plant processes used to test the feasibility of the Mine and
Extraction Plant. There can be no assurance that all components of the mining
and extraction facility will continue to perform as expected or that the costs
to operate this facility will not be significantly higher than expected.
There can be no assurance that the Upgrader will have the same level of
success in upgrading bitumen and purchased feedstocks into products with the
desired specifications. Costs to operate the Upgrader may be significantly
higher than expected.
THIRD-PARTY FACILITIES MAY NOT OPERATE AS PLANNED.
The Project depends upon successful operation of facilities owned and operated
by third parties. The Owners are party to certain agreements with third
parties to provide for, among other things, the following services and
utilities:
o pipeline transportation to be provided through the Corridor
pipeline system;
o electricity and steam to be 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 by the ATCO pipeline;
o hydrogen to be provided to the Upgrader from the HMU and Dow;
and
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o electricity and steam to be provided to the Upgrader from the
Upgrader cogeneration facility.
For the Mine and Extraction Plant, electricity and steam is provided by the
Muskeg River cogeneration facility. If the Muskeg River cogeneration facility
fails to continuously operate in the manner designed, there can be no
assurance that the Owners will be able to obtain alternative sources of
electricity on a timely basis, at prices acceptable to Western, or at all. If
the cogeneration facility does not continuously provide the required steam, it
is unlikely that other sources of steam could be acquired on a timely basis,
at prices acceptable to Western, or at all.
For the Upgrader, the electricity and steam is provided by the Upgrader
cogeneration facility. There can be no assurance that in the event the
Upgrader cogeneration facility fails to continuously operate in the manner
designed, the Owners will be able to secure alternative sources of electricity
and steam on a timely basis, at prices acceptable to Western, or at all.
The HMU is designed to produce approximately 75% of the Upgrader's hydrogen
requirements, with the remainder to be provided by Dow. If the HMU fails to
perform continuously as designed or Dow fails to deliver pursuant to its
contract, respectively, there can be no assurance that the Project will be
able to obtain its hydrogen requirements on a timely basis, at prices
acceptable to Western, or at all.
The Project relies on transportation of bitumen and upgrader output from a
pipeline system owned and operated by Kinder Morgan. If the Corridor pipeline
system is unavailable for any reason, Western will have to find alternatives
to the Corridor pipeline system which may not be available on a timely basis,
at prices acceptable to Western, or at all.
Under the terms of certain third-party agreements, the Owners are committed to
pay for utilities and services on a long-term "take-or-pay" basis, regardless
of the extent that such utilities and services are actually used. In addition,
under the terms of the agreement with Kinder Morgan, Western must make
scheduled payments to them even if the Corridor pipeline system has diminished
capacity or is unavailable. If, due to Project delays, suspensions, shut-downs
or other reasons, the Owners fail to meet their commitments under these
long-term agreements, the Owners may incur substantial costs and may, in some
circumstances, be obligated to purchase the facilities constructed by the
third parties to provide the services and utilities for a purchase price in
excess of the fair market value of the facilities. There can be no assurance
that Western will have sufficient funds to satisfy these obligations.
Most of the contracts with third-party operators do not contain provisions for
the payment of liquidated damages. Accordingly, if certain of the third-party
facilities do not operate as planned, Western will not have a direct financial
claim against the third-party operators.
THE PRICE OF CRUDE OIL AND NATURAL GAS MAY FLUCTUATE AND NEGATIVELY IMPACT
FINANCIAL RESULTS.
Western's financial results are dependent upon the prevailing price of crude
oil and natural gas. Oil and natural gas prices fluctuate significantly in
response to supply and demand factors beyond Western's control. Political
developments, especially in the Middle East, can affect world oil supply and
oil prices. As a result of the relatively higher operating costs of the
Project compared to some conventional crude oil production operations,
Western's operating margin is more sensitive to oil prices than that of some
conventional crude oil producers.
Any prolonged period of low oil prices could result in a decision by the
Owners to suspend or reduce production. Any such suspension or reduction of
production would result in a corresponding substantial decrease in Western's
revenues and earnings and could expose Western to significant additional
expense
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as a result of certain long-term contracts. If the Owners did not decide to
suspend or reduce production, the sale of product at reduced prices would
lower revenues.
In addition, because natural gas comprises a substantial part of Western's
operating costs, any prolonged period of high natural gas prices will
negatively impact Western's financial results.
WESTERN MAY EXPERIENCE PRICING PRESSURE ON ITS SHARE OF THE PROJECT'S
SYNTHETIC CRUDE OIL PRODUCTION DUE TO OVERSUPPLY AND COMPETITION.
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. There exist other suppliers of synthetic crude oil and
there are several additional projects being contemplated. If undertaken and
completed, these projects will result in a significant increase in the supply
of synthetic crude oil to the market. In addition, not all refineries are able
to process or refine synthetic crude oil. There can be no assurance that
sufficient market demand will exist at all times to absorb Western's share of
the Project's synthetic crude oil production.
WESTERN MAY NOT BE ABLE TO PRODUCE A HIGH VALUE SINGLE STREAM BLEND.
Western expects that concurrent with expansion initiatives it will be in a
position to market a single stream blend of synthetic crude oil which has a
greater value than the heavy and light streams currently marketed. There is a
risk that Western will be unable to create a single stream with a higher value
than the heavy and light streams. There is also a risk that the price per
barrel from selling two synthetic crude oil streams and vacuum gas oil could
be significantly less than the price per barrel from selling a single
synthetic crude oil stream and vacuum gas oil.
FLUCTUATIONS IN THE US AND CANADIAN DOLLAR EXCHANGE RATE MAY CAUSE WESTERN'S
OPERATING COSTS TO RISE.
Crude oil prices are generally based on a US dollar market price, while
Western's operating costs are primarily denominated in Canadian dollars.
Adverse fluctuations in the US and Canadian dollar exchange rate may cause
Western's operating costs to rise in relation to Western's revenues. Western
undertakes minor hedging activities against currency fluctuations. There can
be no assurance that current activities or more expansive hedging programs in
the future that Western may adopt are or would be successful.
WESTERN COMPETES WITH LARGER COMPANIES AND ALTERNATIVE FUELS WHEN IT SELLS ITS
SHARE OF THE PROJECT'S PRODUCTION.
The Canadian and international petroleum industry is highly competitive in all
aspects, including the distribution and marketing of petroleum products.
Western competes with established oil sands operators which have established
operating histories and greater financial and other resources than Western. In
addition, Western competes with other producers of synthetic crude oil blends
and producers of conventional crude oil, including Shell and Chevron, some of
whom have lower operating costs and many of whom have extensive marketing
networks. The crude oil industry also competes with other industries and
alternative energy sources in supplying energy, fuel and related products to
consumers.
FEEDSTOCK SUPPLY FOR THE UPGRADER MAY NOT ALWAYS BE AVAILABLE.
The Upgrader will require certain additional feedstocks to produce its output.
Western has entered into contracts for required feedstocks for terms of
between one and five years. There can be no assurance that
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feedstocks of the desired quality will be available on a timely basis after
these contracts expire, at prices acceptable to Western, or at all.
Unavailability of required feedstocks could have an adverse effect on the rate
and quality of Upgrader output.
THE PROJECTIONS AND ASSUMPTIONS ABOUT WESTERN'S FUTURE PERFORMANCE MAY PROVE
TO BE INACCURATE.
Western has only a few years of operating results. Western's long-term
financing plan is based upon certain assumptions and financial projections
regarding its share of revenues and of operating, maintenance and capital
costs of the Project. These projections and assumptions may prove to be
inaccurate.
DEBT LEVELS COULD LIMIT FUTURE FLEXIBILITY IN OBTAINING ADDITIONAL DEBT
FINANCING AND IN PURSUING BUSINESS OPPORTUNITIES.
As at December 31, 2005, Western had approximately $707 million of debt
(including obligations under the HMU lease and net option premiums deferred
associated with Western's strategic crude oil hedging program implemented
during the third quarter of 2005). Western may also incur significant
additional indebtedness for various purposes, including expansions. Western's
debt level and restrictive covenants will have an important effect on its
future operations.
In addition, Western's ability to make scheduled payments or to refinance its
debt obligations will depend upon its financial and operating performance,
which in turn, will depend upon prevailing industry and general economic
conditions beyond Western's control. There can be no assurance that Western's
operating performance, cash flow and capital resources will be sufficient to
repay its debt in the future.
FINANCING ARRANGEMENTS CONTAIN COVENANTS LIMITING OUR DISCRETION TO OPERATE
OUR BUSINESS.
Western's financing arrangements contain provisions that limit its discretion to
operate its business. If Western fails to comply with the restrictions set forth
in its current or future financing agreements, Western will be in default and
the principal and accrued interest may become due and payable.
THE PROJECT MAY EXPERIENCE EQUIPMENT FAILURES FOR WHICH WESTERN DOES NOT HAVE
SUFFICIENT INSURANCE.
The Upgrader processes large volumes of hydrocarbons at high pressure and
temperatures in equipment with fine tolerances. Equipment failures could
result in damage to the Extraction Plant and the Upgrader and liability to
third parties against which Western may not be able to fully insure or may
elect not to insure for various reasons, including high premium costs. Even
with adequate insurance, delays in realizing on claims and replacing damaged
equipment could adversely affect Western's operations and revenues.
HEDGING ACTIVITIES COULD RESULT IN LOSSES OR LIMIT THE BENEFIT OF CERTAIN
COMMODITY PRICE INCREASES.
The nature of Western's operations results in exposure to fluctuations in
commodity prices. Western has initiated a hedging program to use financial
instruments and physical delivery contracts to hedge its exposure to these
risks. When engaging in hedging Western will be exposed to credit-related
losses in the event of non-performance by counterparties to the financial
instruments. From time to time Western may enter into additional hedging
activities in an effort to mitigate the potential impact of declining oil
prices. These activities may consist of, but may not be limited to:
o buying a price floor under which Western will receive a minimum
price for its oil production;
-33-
o buying a collar under which Western will receive a price within
a specified range for its oil production;
o entering into fixed contracts for oil production; and
o entering into a contract to fix the differential between the
price for Western's outputs and either the West Texas
Intermediate or the Edmonton Par crude oil pricing benchmarks.
If product prices increase above those levels specified in any future hedging
agreements, Western could lose the cost of floors or ceilings or a fixed price
could limit Western from receiving the full benefit of commodity price
increases. In addition, by entering into these hedging activities, Western may
suffer financial loss if it is unable to produce sufficient quantities of oil
to fulfil its obligations.
Western may hedge its exposure to the costs of various inputs to the Project,
such as natural gas or feedstocks. If the prices of these inputs falls below
the levels specified in any future hedging agreements, Western could lose the
cost of ceilings or a fixed price could limit Western from receiving the full
benefit of commodity price decreases.
RESERVE AND RESOURCE ESTIMATES ARE UNCERTAIN.
There are numerous uncertainties inherent in estimating quantities of reserves
and resources, including many factors beyond Western's control. Western's
reserve and resource data represent estimates only. The usefulness of such
estimates is highly dependent upon the accuracy of the assumptions on which
they are based, the quality of the information available and the ability to
compare such information against industry standards.
Fluctuations of oil prices may render the mining of oil sands reserves
uneconomical. Other factors relating to the oil sands reserves, such as the
need for orderly development of ore bodies or the processing of new or
different grades of ore, may impair Western's profitability.
In general, estimates of economically recoverable bitumen reserves and the
related future net pretax cash flows of the Project are based upon a number of
variable factors and assumptions, such as:
o historical production from similar properties which are owned by
other operators;
o limited production and operating history of the Project;
o the assumed effects of regulation by governmental agencies;
o estimated future operating costs; and
o the availability of enhanced recovery techniques,
all of which may vary considerably from actual results of the Project.
There is a limited history of production from Western's properties. All such
estimates are to some degree speculative, and classifications of reserves are
only attempts to define the degree of speculation involved. Western's reserve
figures have been determined based upon assumed oil prices and operating
costs. For those reasons, estimates of the economically recoverable bitumen
reserves attributable to any particular group of properties, classification of
such reserves based on risk of recovery and estimates of future net revenues
expected from them, prepared by different engineers or by the same engineers
at different times,
-34-
may vary substantially. Western's actual production, revenues, taxes and
development and operating expenditures with respect to Western's reserves will
vary from such estimates, and such variances could be material. Reserve
estimates may require revision based on actual production experience.
INDEPENDENT REVIEWS MAY BE INACCURATE.
Although independent and qualified third parties have prepared reviews,
reports and projections relating to the viability and expected performance of
the Project, there can be no assurance that these reports, reviews and
projections and the assumptions on which they are based will, over time, prove
to be accurate.
SHELL AND CHEVRON MAY NOT AGREE WITH WESTERN ON MATTERS RELATED TO THE PROJECT.
The Project is a joint venture among Shell, Chevron and Western. Future plans
of the Project, including decisions related to levels of production, will
depend on agreement among the Owners and will depend on the financial strength
and views of Shell and Chevron. There can be no assurance that the Owners will
agree on all matters relating to the Project.
Under the Joint Venture Agreement, ordinary resolutions of the Executive
Committee may be passed without Western's consent and there can be no
assurance that such resolutions may not adversely affect Western.
In addition, if Western's voting interest in any functional units falls below
15%, Western's consent will not be required for an extraordinary resolution of
the Executive Committee relating to that functional unit and such resolutions
may adversely affect Western.
SHELL AND CHEVRON MAY NOT MEET THEIR OBLIGATIONS TO THE PROJECT.
Western is subject to the risk of non-payment by Shell or Chevron in meeting
their payment obligations to the Project. To the extent any Owner does not
meet its obligations to fund its costs in respect of the Joint Venture
Agreement and related agreements, Western, together with any other performing
Owners, would be required to fund those obligations.
IF WESTERN DEFAULTS ON ITS OBLIGATIONS UNDER THE JOINT VENTURE AGREEMENT,
SHELL AND CHEVRON WILL HAVE THE RIGHT TO PURCHASE WESTERN'S INTEREST IN THE
JOINT VENTURE AT A DISCOUNT.
If Western fails to meet all or part of our obligations under the Joint
Venture Agreement, including by failing to participate in any expansion of an
existing mine which does not require an expansion of the Extraction Plant,
Upgrader, major shared facilities or third party facilities (which expansions
can be carried out pursuant to an ordinary resolution of the Executive
Committee), the other Owners will have an option to purchase Western's entire
ownership interest in the Joint Venture and related assets at a discount. The
amount at which they could purchase Western's ownership interest would be
equal to 80% of the capital costs incurred..
SHELL MAY NOT FULFIL ITS OBLIGATIONS TO WESTERN UNDER OUR LONG-TERM SALES
CONTRACT.
Western sells its share of vacuum gas oil produced by the Project to an
affiliate of Shell on a long-term basis. Since a large portion of our revenues
will be received from an affiliate of Shell, Western will have a concentration
of credit risk. Furthermore, if the Shell affiliate does not have the capacity
at the Scotford Refinery to physically process Western's share of vacuum gas
oil produced by the Project after using its commercially reasonable efforts to
maintain such capacity, it will not be required to purchase Western's
-35-
share of vacuum gas oil until the Refinery regains such capacity.
Modifications to the Scotford Refinery were undertaken to permit it to take
the expected vacuum gas oil output. If the affiliate of Shell were to default
on, or not be required to fulfil its obligations to Western, or if the
Scotford Refinery is not capable of processing the vacuum gas oil, there can
be no assurance that Western could sell its share of vacuum gas oil to other
purchasers at a price equal to or greater than that provided for in its
contract with the Shell affiliate, or at all.
Additionally, the price Western receives for products sold to the affiliate of
Shell may vary depending on the characteristics of the products sold. To the
extent the characteristics of the products fail to meet agreed upon
specifications, the purchase price for such products will be adjusted
downward. If the characteristics of the products are significantly below
specifications the affiliate of Shell is entitled to reject such products.
Downward adjustment of the purchase price or rejection of the products could
have an adverse effect on Western's operations and revenues, and there can be
no assurance that we could sell any rejected products elsewhere.
IF WESTERN DOES NOT PARTICIPATE IN CERTAIN EXPANSIONS, WESTERN WILL LOSE
VOTING OR SIGNIFICANT EXPANSION RIGHTS.
If Western does not participate in expansions on the western portion of Lease
13, in certain circumstances Western's voting interest will be diluted and
Western's consent will no longer be required for extraordinary resolutions of
the Executive Committee. In addition, if Western does not participate in an
expansion on the remainder of Lease 13 or Shell's Other Athabasca Leases, or
if Western no longer has an ownership interest in each functional unit
comprising the Project, Western will lose its right to participate in any
further expansions, lose any rights to share in the resources contained on
Leases 88 and 89 and Shell's Other Athabasca Leases and lose any rights to
participate in an area of mutual interest with the other Owners. Shell and
Chevron, have significantly greater capital resources than that of Western. If
the other Owners decide to undertake expansions, including expansions on the
eastern portion of Lease 13 and on Leases 88 and 89, there can be no assurance
that Western will be able to fund its share of the expansion. Western's
participation would be subject to several conditions, including Western's
satisfaction with feasibility studies and Western's access to the necessary
capital resources.
IF WESTERN PARTICIPATES IN CERTAIN EXPANSIONS, THOSE EXPANSIONS WILL BE
SUBJECT TO MANY OF THE SAME RISKS AS THE PROJECT.
Western may participate in expansions on the western portion of Lease 13, on
the remainder of Lease 13 or on Shell's Other Athabasca Leases. The Owners are
evaluating potential long-term development opportunities relating to resources
contained within Lease 13 and on Shell's Other Athabasca Leases. If Western
were to participate in any expansion, Western will require additional
financing in order to fund its share of costs associated with an expansion.
Additionally, Western's participation in expansions will be subject to many of
the same risks as the Project.
EXPANSIONS MAY NOT PROCEED AS PLANNED
The expansion strategy and configuration currently envisioned may not proceed
as planned with respect to scope, timing and execution. This may directly
impact the volume, quality and timing of producing marketable materials.
WESTERN MAY NOT BE ABLE TO EFFECTIVELY MANAGE ITS GROWTH.
The Joint Venture Agreement permits participation in certain expansion
opportunities. Participation in any expansion opportunities would
significantly increase the demands on Western's management
-36-
resources. Western may not be able to effectively manage these expansions, and
any failure to do so could have a material adverse effect on Western's
business, financial condition or results of operations.
THE PROJECT MAY NOT BE ABLE TO HIRE AND RETAIN THE SKILLED EMPLOYEES IT
REQUIRES.
The Project requires experienced employees with particular areas of expertise.
There are other oil sands and other industrial projects and expansions in
Alberta that compete with the Project for skilled employees, and such
competition may result in increases to the compensation paid to such employees
and shortages of skilled tradespersons. The Project has already experienced
increased costs as a result of such competition and decreases in productivity.
There can be no assurances that all of the required employees with the
necessary expertise will be available.
VARIOUS HAZARDS INHERENT IN WESTERN'S OPERATIONS COULD RESULT IN LOSS OF
EQUIPMENT OR LIFE.
The operation of the Project is subject to the customary hazards of mining,
extracting, transporting and processing hydrocarbons, including the risk of
catastrophic events such as fire, earthquake, storms or explosions. A casualty
occurrence might result in the loss of equipment or life, as well as injury or
property damage. Western does not carry insurance with respect to all casualty
occurrences and disruptions. There is no assurance that Western's insurance
will be sufficient to cover any such casualty occurrences or disruptions,
including with respect to the damage caused by the fire at the Mine. Losses
and liabilities arising from uninsured or under-insured events could have a
material adverse effect on the Project and on Western's business, financial
condition and results of operations.
THE ABANDONMENT AND RECLAMATION COSTS RELATING TO THE PROJECT MAY BE HIGHER
THAN ANTICIPATED.
Western will be responsible for compliance with terms and conditions set forth
in the environmental and regulatory approvals for the Project and all present
and future laws and regulations regarding the decommissioning and abandonment
of the Project and the 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 by the prescribed time period, Western must
establish and fund a reclamation trust fund. Western currently does not hold
the minimum credit rating. Even if Western does hold the minimum credit
rating, in the future Western may determine that it is prudent or that Western
is 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 Western concludes that the
establishment of such a fund is prudent or required, Western may lack the
financial resources to do so. Western may also be required by future
regulatory requirements to establish a fund or place funds in trust with
regulators for the decommissioning and abandonment of the Project and the
reclamation of its lands.
THE PROJECT MAY FAIL TO COMPLY WITH VARIOUS ENVIRONMENTAL APPROVALS WHICH MAY
EITHER CAUSE THE WITHDRAWAL OF THESE APPROVALS OR IMPOSE OTHER COSTS.
The operation and decommissioning of the Project and reclamation of the
Project's lands are conditional upon various environmental and regulatory
approvals issued by governmental authorities. Further, the operation and
decommissioning of the Project and reclamation of the Project's lands will be
subject to approvals and present and future laws and regulations relating to
environmental protection and operational safety. Risks of substantial costs
and liabilities are inherent in oil sands operations, and there can be no
assurance that substantial costs and liabilities will not be incurred or that
the Project will be permitted by regulators to carry on its operations. Other
developments, such as increasingly strict environmental and safety laws,
regulations and enforcement policies thereunder, and claims for damages
-37-
to property or persons resulting from the Project's operations, could also
result in substantial costs and liabilities to Western, delays in operations
or abandonment of the Project.
Canada is a signatory to the United Nations Framework Convention on Climate
Change and has ratified the Kyoto Protocol established thereunder to set
legally binding targets to reduce nation-wide emissions of carbon dioxide,
methane, nitrous oxide and other so-called "greenhouse gases". The Project
will be a significant producer of some greenhouse gases covered by the treaty.
The Government of Canada 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.
CHANGES IN THE WESTERN'S OIL SANDS CROWN ROYALTIES POSITION AND OIL SANDS
TAXATION MAY NEGATIVELY IMPACT FINANCIAL RESULTS.
Western, through its 20 per cent undivided interest in the Project, currently
benefits from both a favourable royalty and income tax regime in terms of the
determination royalty payments until the Project has recovered the costs
associated with Mine and in terms of certain accelerated deductions for income
tax purposes. However, there can be no assurance that this royalty or income
tax regime will not change in a manner that would adversely affect Western,
either through changes in law or through further interpretation of law. The
classification of future expansions for both royalty calculations and
accelerated deductions, and the availability of these expenditures for
allowable costs for royalty purposes or as accelerated deductions for income
tax purposes, can have a significant impact on Western's royalty and income
tax expenses and payments.
CHANGES IN GOVERNMENT REGULATION OF WESTERN'S OPERATIONS MAY HARM WESTERN.
Western's mining, extraction and upgrading operations and the operations of
third-party contractors are subject to extensive Canadian federal, provincial
and local laws and regulations governing exploration, development,
transportation, production, exports, labour standards, occupational health,
waste disposal, protection and remediation of the environment, mine safety,
hazardous materials, toxic substances and other matters. Amendments to current
laws and regulations and the introduction of new laws and regulations
governing operations and activities of mining corporations and more stringent
application of such laws and regulations are actively considered from time to
time and could affect the viability of the Project.
There can be no assurance that the various government licenses and approvals
or amendments thereto that from time to time may be sought will be granted to
the Project at all or with conditions satisfactory to Western or, if granted,
will not be cancelled or will be renewed upon expiry or that income tax laws
and government incentive programs relating to the Project, and the mining, oil
sands and oil and gas industries generally, will not be changed in a manner
which may adversely affect Western.
Currently, Western benefits from a favourable royalty regime; however, there
can be no assurance that this royalty regime will not change in a manner that
would adversely affect Western.
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Lease 13 is subject to the OIL SANDS TENURE REGULATION (Alberta) which was
introduced in 2000. This legislation deems Lease 13 to continue beyond its
primary term to the extent that the lessee has attained the minimum level of
evaluation of the oil sands in Lease 13 or Lease 13 is producing. There can be
no assurance that the Owners will be able to comply with the requirements of
the OIL SANDS TENURE REGULATION (Alberta). In addition, the Minister, in
certain circumstances, may change the designation of any lease subject to the
legislation and provide notice requiring the Owners to commence production or
recovery of, or to increase existing production or recovery of bitumen or
other oil sands products within the time specified in such notice. There can
be no assurance that if such a notice is given, the Owners will be able to
comply with its terms to maintain Lease 13. Additionally, the OIL SANDS TENURE
REGULATION (Alberta) expires on December 1, 2008 and, if such legislation is
not renewed in its present or similarly favourable form, the status of Lease
13 may be in question.
CANADA REVENUE AGENCY ("CRA") MAY RULE NEGATIVELY ON EXTENT OF QUALIFYING
EXPENDITURE AS IT RELATES TO RENUNCIATION ON 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,
individuals shareholders can reduce their income subject to personal income
taxes. During the fourth quarter of 2005, discussions were held between the
AOSP and CRA regarding the proper characterization of certain expenditures
included in the Canadian exploration expenses in those years. If 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 these 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).
ABORIGINAL PEOPLES MAY MAKE CLAIMS AGAINST WESTERN OR THE PROJECT REGARDING
THE LANDS ON WHICH THE PROJECT IS LOCATED.
Aboriginal peoples have claimed aboriginal title and rights to a substantial
portion of western Canada. Certain aboriginal peoples have filed a claim
against the Government of Canada, certain governmental entities and the City
of Fort McMurray, Alberta claiming, among other things, that the plaintiffs
have aboriginal title to large areas of lands surrounding Fort McMurray,
including the lands on which the Project and most of the other oil sands
operations in Alberta are located. Such claims, if successful, could have an
adverse effect on the Project.
RISKS ASSOCIATED WITH EXPLORATION AND DEVELOPMENT OF HYDROCARBON RESOURCES MAY
NEGATIVELY IMPACT WESTERN
The energy industry is highly competitive in all aspects, including the
exploration for and the development of new sources of hydrocarbon resource.
Western will compete for the exploration and the development of new sources of
hydrocarbon resource with major integrated oil and gas companies, as well as
various independent oil and gas companies. Western will do so through its 20
per cent ownership interest in the AOSP and also through direct investments
made by Western into oil sands and other ventures with significant long-life
hydrocarbon resource potential.
Western's 20 per cent ownership interest in the AOSP gives Western the option,
upon satisfying certain provisions of the Joint Venture Agreement, to earn a
working interest in additional leases in the Athabasca region of Alberta that
Shell or Chevron may purchase. Western may also make certain of its
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investments involved in the exploration and development of new sources of
hydrocarbon resource in domestic or international jurisdictions. Investments
in international jurisdictions have various inherent risks, including but not
limited to political, economical, legal, regulatory and foreign exchange
risks. The exploration and development of new sources of hydrocarbon resource
can have various inherent risks, including but not limited to encountering
unexpected formations or pressures, blow-outs, equipment failures,
uncontrollable flows of oil, natural gas or well fluid, and various
environmental risks. Western will assess and mitigate to the extent possible
these inherent risks of international jurisdictions and the inherent risks of
exploration and development as these investments are evaluated and pursued.
Western will also compete in the highly competitive energy industry for any
downstream initiatives it pursues, including the acquisition of upgrading and
refining capacity for heavy crude oil. There can be no assurance that Western
will be able to secure such opportunities and, if secured, will be able to
finance the complete such opportunities.
INVESTMENTS IN BUSINESS DEVELOPMENT ACTIVITIES UNRELATED TO THE OIL SANDS
INDUSTRY
Western has previously announced its business strategy of investigating, at
any one time, several separate projects which could significantly enhance
shareholder value. These projects may be domiciled outside Canada. These
potential investments may involve such risks as uncertain political, economic,
legal, regulatory and tax environments. They may also include, among other
things, currency restrictions and exchange rate fluctuations, risk of loss of
revenue, property and equipment as a result of hazards such as expropriation,
nationalization, war, insurrection and other political risks, risks of
increases in taxes and governmental royalties, renegotiation of contracts with
governmental entities and quasi-governmental agencies, changes in laws and
policies governing operations of foreign-based companies and other
uncertainties arising out of foreign government sovereignty over an investment
that Western may make abroad.
TRANSFER AGENTS AND REGISTRAR
Valiant Trust Company at its principal office in Calgary, Alberta is the
transfer agent and registrar of the Common Shares of the Corporation and BNY
Trust Company of Canada at its principal office in Toronto, Ontario is the
co-agent and registrar of the Common Shares of the Corporation.
INTEREST OF EXPERTS
Norwest Corporation, independent mining consultants to the Corporation,
prepared the Norwest Report and GLJ Petroleum Consultants Ltd., independent
petroleum consultants to the Corporation, prepared the GLJ Report, both
referenced herein. As at the date of the respective reports, the principals of
each of Norwest and GLJ, as respective groups, owned beneficially, directly or
indirectly, less than 1% of the outstanding Common Shares. Neither Norwest nor
GLJ received or will receive any interest, direct or indirect, in any
securities or other property of Western or its affiliates in connection with
the preparation of its report.
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LEGAL PROCEEDINGS
There are no legal proceedings which Western is a party to that involve a
claim for damages that exceed ten per cent of the current assets of Western.
Western is however involved in arbitration proceedings arising from insurance
claims. See "Narrative Description of the Business - Insurance".
ADDITIONAL INFORMATION
Additional information relating to the Corporation may be found on SEDAR at
www.sedar.com.
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Additional information including directors' and officers' remuneration and
indebtedness, principal holders of the Corporation's securities and securities
authorized for issuance under equity compensation plans, if applicable, is
contained in the Corporation's information circular for its most recent annual
meeting of shareholders that involved the election of directors, and additional
financial information is provided in the Corporation's comparative financial
statements and MD&A for its most recently completed financial year.
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GLOSSARY
IN THIS ANNUAL INFORMATION FORM, THE FOLLOWING TERMS SHALL HAVE THE MEANINGS
SET FORTH BELOW, UNLESS OTHERWISE INDICATED:
"ALBIAN" Albian Sands Energy Inc., a corporation owned by the Owners in
proportion to their ownership interest, which was incorporated for the
purposes of acting as the operator of the Mine and the Extraction Plant;
"AOSP" or the "PROJECT" The design and construction of facilities and
implementation of operations of the Mine, the Extraction Plant, the Upgrader
and all other facilities necessary to mine, extract, transport and upgrade
crude bitumen from the oil sands deposits on the western portion of Lease 13;
"ATCO" ATCO Power Canada Limited;
"BBLS" Barrels. One barrel equals 0.15891 cubic metres at 15(0) Celsius;
"CHEVRON" Chevron Canada Limited;
"COMMON SHARES" The Class A shares of Western;
"DISCOVERED RESOURCES" Are those quantities of oil and gas estimated on a
given date to be remaining in, plus those quantities already produced from,
known accumulations. Discovered resources are divided into economic and
uneconomic categories, with the estimated future recoverable portion
classified as reserves and contingent resources, respectively. (Source:
Canadian Oil and Gas Evaluation Handbook, Volume 1, Section 5.2.2)
"DOW" Dow Chemicals Canada Inc.;
"EXECUTIVE COMMITTEE" The executive committee appointed under the Joint
Venture Agreement which has the responsibility for managing the Project and
which is comprised of two representatives of each of the Owners;
"EXTRACTION PLANT" The extraction facilities are located on the western
portion of Lease 13 which are designed to separate crude bitumen from the oil
sands and process such crude bitumen so that it may be transported by pipeline
to the Scotford Upgrader;
"EXTRACTION PLANT START-UP" That time when the Extraction Plant has operated
at not less than 85% of its design capacity for a period of 30 consecutive
days and any construction deficiencies and defects have been rectified to the
satisfaction of the Owners;
"GLJ" GLJ Petroleum Consultants Ltd., independent petroleum consultants;
"GLJ REPORT" The report prepared by GLJ dated February 13, 2006 evaluating the
reserves attributable to Western as of December 31, 2005;
"HMU" The hydrogen manufacturing unit which supplies hydrogen to the Upgrader;
"JACKPINE MINE" The first planned expansion area to be developed by the Joint
Venture physically located on the east side of the Muskeg River;
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"JOINT VENTURE" The unincorporated joint venture created by the Owners
pursuant to the Joint Venture Agreement to undertake the Project;
"JOINT VENTURE AGREEMENT" or "JVA" The Joint Venture Agreement dated December
6, 1999, among the Owners, as amended;
"LEASE 13" Bituminous Sands Lease No. 7277080T13 and all renewals, extensions,
replacements and amendments thereto, granted to Shell by the Government of
Alberta, and transferred to Albian Sands Energy Inc., the western portion of
which is the site for the mining and extraction operations of the Project;
"MD&A" Management Discussion & Analysis;
"MM$" Millions of dollars and "M$" thousands of dollars;
"MMBBLS" Millions of barrels;
"MINE" The open pit mine located on the western portion of Lease 13 and all
equipment, machinery, vehicles and facilities used in connection therewith;
"NON-VOTING CONVERTIBLE EQUITY SHARES" The non-voting convertible Class B
equity shares of Western each convertible into one Common Share in certain
circumstances subject to adjustment, at no additional cost;
"NORWEST" Norwest Corporation, independent mining consultants;
"NORWEST REPORT" The report prepared by Norwest dated March 15, 2006,
effective as of December 31, 2005, that considered available drilling data on
Leases 13(east), 88, 89, 90, 9 and 17;
"NOTES" Western's senior secured notes having a principal amount of US$450
Million bearing interest at a rate of 8.375% per annum and maturing on May 1,
2012;
"OWNERS" The owners of undivided ownership interests in the Project which
include Shell, as to a 60% undivided ownership interest, Chevron, as to a 20%
undivided ownership interest, and Western, as to a 20% undivided ownership
interest;
"PROJECT START-UP" That time when the main Project facilities have operated at
not less than 85% of their design capacity for a period of 30 consecutive days
and any construction deficiencies and defects have been rectified to the
satisfaction of the Owners;
"SCOTFORD REFINERY" The oil refinery owned by Shell Products Canada Limited
which is located near Fort Saskatchewan, Alberta and which is adjacent to the
location of the Scotford Upgrader;
"SCOTFORD UPGRADER" or "UPGRADER" The oil sands bitumen upgrader which
processes diluted bitumen product from the Extraction Plant to produce
refinery feed stocks for sale to Shell Products Canada Limited at the Scotford
Refinery and synthetic crude oil for shipment to other North American
refineries;
"SENIOR CREDIT FACILITY" The credit facility between the Corporation and
certain lending institutions which, prior to repayment, provided a portion of
the capital costs of the Project and which facility also included debt service
and cost overrun facilities;
"SHELL" Shell Canada Limited; and
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"SHELL'S OTHER ATHABASCA LEASES" Alberta Crown Oil Sands Lease Nos.
7288080T88, 7288080T89, 7288080T90, 7280050T26, 7281010T93, 7281030T53,
7281030T45, 7280080T28, 7400120009, 7401100017, 7405080351, 7405080352,
74058090631, 7405090632, 7405120015, 7405120309, 7405120310 and all renewals,
extensions, replacements and amendments in respect of same, granted to Shell
by the Government of Alberta.
APPENDIX A
REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
To the board of directors of Western Oil Sands Inc. (the "Corporation"):
1. We have prepared an evaluation of the Corporation's reserves data as at
December 31, 2005. The reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas
reserves estimated as at December 31, 2005, using
forecast prices and costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at
December 31, 2005, using constant prices and costs;
and
(ii) the related estimated future net revenue.
2. The reserves data are the responsibility of the Corporation's management.
Our responsibility is to express an opinion on the reserves data based on
our evaluation.
We carried out our evaluation in accordance with standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary
Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum
(Petroleum Society).
3. Those standards require that we plan and perform an evaluation to obtain
reasonable assurance as to whether the reserves data are free of material
misstatement. An evaluation also includes assessing whether the reserves
data are in accordance with principles and definitions in the COGE
Handbook.
4. The following table sets forth the estimated future net revenue (before
deduction of income taxes) attributed to proved plus probable reserves,
estimated using forecast prices and costs and calculated using a discount
rate of 10 percent, included in the reserves data of the Corporation
evaluated by us for the year ended December 31, 2005, and identifies the
respective portions thereof that we have audited, evaluated and reviewed
and reported on to the Corporation's board of directors:
LOCATION OF
RESERVES
DESCRIPTION AND (COUNTRY OR NET PRESENT VALUE OF FUTURE NET REVENUE
PREPARATION DATE OF FOREIGN (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
EVALUATION GEOGRAPHIC -------------------------------------------------
REPORT AREA) AUDITED EVALUATED REVIEWED TOTAL
------ ----- ------- --------- -------- -----
Feb 13, 2006 Canada 0 2,685 MM$ 0 2,685 MM$
5. In our opinion, the reserves data respectively evaluated by us have, in
all material respects, been determined and are in accordance with the
COGE Handbook.
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6. We have no responsibility to update the evaluation referred to in
paragraph 4 for events and circumstances occurring after the preparation
dates.
7. Because the reserves data are based on judgements regarding future
events, actual results will vary and the variations may be material.
Executed as to our report referred to above:
GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada Dated: February 13, 2006
ORIGINALLY SIGNED BY
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James H. Willmon, P. Eng.
Vice-President
APPENDIX B
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Management of Western Oil Sands Inc. (the "Corporation") are responsible for
the preparation and disclosure of information with respect to the
Corporation's oil and gas activities in accordance with securities regulatory
requirements. This information includes reserves data, which consist of the
following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2005 using forecast prices and
costs; and
(ii) the related estimated future net revenue; and
(b) (i) proved oil and gas reserves estimated as at December 31,
2005 using constant prices and costs; and
(ii) the related estimated future net revenue.
An independent qualified reserves evaluator has evaluated the Corporation's
reserves data. The report of the independent qualified reserves evaluator is
presented in Appendix A to this Annual Information Form.
The Reserves and Business Risk Committee of the Board of Directors of the
Corporation has:
(a) reviewed the Corporation's procedures for providing
information to the independent qualified reserves evaluator;
(b) met with the independent qualified reserves evaluator to
determine whether any restrictions affected the ability of the
independent qualified reserves evaluator to report without
reservation; and
(c) reviewed the reserves data with management and the independent
qualified reserves evaluator.
The Reserves and Business Risk Committee of the Board of Directors has
reviewed the Corporation's procedures for assembling and reporting other
information associated with oil and gas activities and has reviewed that
information with management. The Board of Directors has, on the recommendation
of the Reserves and Business Risk Committee, approved:
(a) the content and filing with securities regulatory authorities
of the reserves data and other oil and gas information;
(b) the filing of the report of the independent qualified reserves
evaluator on the reserves data; and
(c) the content and filing of this report.
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Because the reserves data are based on judgements regarding future events,
actual results will vary and the variations may be material.
(signed) James C. Houck, President and Chief Executive Officer
(signed) Steve Reynish, Executive Vice President and Chief Operating Officer
(signed) Randall Oliphant, Director
(signed) David J. Boone, Director
(signed) Geoff Cumming, Lead Director
March 28, 2006
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APPENDIX C
AUDIT COMMITTEE CHARTER
PURPOSE
The purpose of the Audit Committee of the Board is to assist the Board in
fulfilling its oversight responsibilities in relation to the review and
approval of the financial statements and financial reporting of the
Corporation and the assessment of internal control and management information
of the Corporation. The Audit Committee shall also be directly responsible for
overseeing all audit processes and the relationship of the external auditors
with the Corporation and the external auditors shall report directly, and be
accountable, to the Audit Committee.
The role of the Audit Committee is one of supervision, stewardship and
oversight. Management is responsible for preparing the financial statements
and financial reporting of the Corporation and for maintaining internal
control and management information. The external auditors are responsible for
the audit or review of the financial statements and other services they
provide.
MANDATE
1. FINANCIAL STATEMENTS AND FINANCIAL REPORTING.
The Audit Committee shall:
(a) review with management and the external auditors, and recommend to
the Board for approval, the annual financial statements of the
Corporation, the reports of the external auditors thereon and
related financial reporting, including Management's Discussion and
Analysis and earnings press releases prior to the public disclosure
of such information;
(b) review with management and the external auditors, and recommend to
the Board for approval, the interim financial statements of the
Corporation and related financial reporting, including Management's
Discussion and Analysis and earnings press releases prior to the
public disclosure of such information;
(c) review with management and recommend to the Board for approval, the
Corporation's Annual Information Form;
(d) review with management and recommend to the Board for approval, any
financial statements of the Corporation which have not previously
been approved by the Board and which are to be included in a
prospectus of the Corporation;
(e) consider and be satisfied that adequate procedures are in place for
the review of the Corporation's public disclosure of financial
information extracted or derived from the Corporation's financial
statements (other than disclosure referred to in clauses (a) and
(b) above), and periodically assess the adequacy of such
procedures;
(f) review with management, the external auditors and, if necessary,
legal counsel, any litigation, claim or contingency, including tax
assessments, that could have a material effect upon the financial
position of the Corporation, and the manner in which these matters
may be, or have been, disclosed in the financial statements;
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(g) review the appropriateness of the accounting practices and policies
of the Corporation and review any proposed changes thereto;
(h) review and discuss any new or pending developments in accounting
and reporting standards that may affect the Corporation; and
(i) review accounting, tax and financial aspects of the operations of
the Corporation as the Audit Committee considers appropriate.
2. RELATIONSHIP WITH EXTERNAL AUDITORS.
The Audit Committee shall:
(a) consider and make a recommendation to the Board as to the
appointment or re-appointment of the external auditors, ensuring
that such auditors are participants in good standing pursuant to
applicable securities laws;
(b) consider and make a recommendation to the Board as to the
compensation of the external auditors;
(c) review and approve the annual audit plan of the external auditors
(including without limitation, engagement letters, objectives and
scope of the external audit word, procedures for quarterly review
of financial statements, materiality limits, areas of audit risk,
staffing, timetables and proposed fees);
(d) oversee the work of the external auditors in performing their audit
or review services and oversee the resolution of any disagreements
between management and the external auditors;
(e) review and discuss with the external auditors all significant
relationships that the external auditors and their affiliates have
with the Corporation and its affiliates in order to determine the
external auditors' independence, including, without limitation, (A)
requesting, receiving and reviewing, on a periodic basis, a formal
written statement from the external auditors delineating all
relationships that may reasonably be thought to bear on the
independence of the external auditors with respect to the
Corporation, (B) discussing with the external auditors any
disclosed relationships or services that the external auditors
believe may affect the objectivity and independence of the external
auditors, and (C) recommending that the Board take appropriate
action in response to the external auditors' report to satisfy
itself of the external auditors' independence;
(f) as may be required by applicable securities laws, rules and
guidelines, either:
(i) pre-approve all non-audit services to be provided by the
external auditors to the Corporation (or its subsidiaries,
if any), or, in the case of DE MINIMUS non-audit services,
approve such non-audit services prior to the completion of
the audit; or
(ii) adopt specific policies and procedures for the engagement
of the external auditors for the purpose of the provision
of non-audit services;
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(g) be satisfied that the fees paid by the Corporation to the external
auditors for audit and non-audit services are publicly disclosed;
and
(h) review and approve the hiring policies of the Corporation regarding
partners, former partners, employees and former employees of the
present and former external auditors of the Corporation.
3. INTERNAL CONTROLS.
The Audit Committee shall:
(a) review with management and the external auditors, the adequacy and
effectiveness of the internal control and management information
systems and procedures of the Corporation (with particular
attention given to accounting, financial statements and financial
reporting matters and to being satisfied that such systems are
reliable and that they operate effectively to produce accurate,
appropriate and timely management and financial information) and
determine whether the Corporation is in compliance with applicable
legal and regulatory requirements and with the Corporation's
policies;
(b) provide the Board with an independent mechanism for reviewing
reserves;
(c) review the external auditors' recommendations regarding any
matters, including internal control and management information
systems and procedures, and management's responses thereto;
(d) establish procedures for the receipt, retention and treatment of
complaints, submissions and concerns regarding accounting, internal
accounting controls or auditing matters on an anonymous and
confidential basis;
(e) review policies and practices concerning the expenses and
perquisites of the Chairman, including the use of the assets of the
Corporation;
(f) review with external auditors any corporate transactions in which
directors or officers of the Corporation have a personal interest;
(g) review insurance coverage of significant business risks and
uncertainties;
(h) review material litigation and its impact on financial reporting;
and
(i) review policies and procedures for the review and approval of
officers' expenses and perquisites.
COMPOSITION AND PROCEDURES
1. COMPOSITION OF COMMITTEE.
The Audit Committee shall consist of not less than three directors, none
of whom shall be an officer or employee of the Corporation or any of its
subsidiaries or any affiliate thereof. Each Audit Committee member shall
satisfy the independence and financial literacy requirements of
applicable securities laws, rules or guidelines, any applicable stock
exchange requirements or guidelines and any other applicable regulatory
rules. In addition, the Chair shall have "accounting
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or related financial expertise". The Board has defined "financial
literacy" as the ability to understand a balance sheet, income statement
and a cash flow statement in accordance with Canadian GAAP and the Board
has defined "accounting or financial expertise" as the ability to analyze
and understand a full set of financial statements, including the notes
attached thereto in accordance with Canadian GAAP. Each member of the
Audit Committee shall have no direct or indirect material relationship
with the Corporation or any affiliate thereof which could reasonably be
expected to interfere with the exercise of the member's independent
judgment, other than interests and relationships arising from the
holdings of shares of the Corporation. Determinations as to whether a
particular director satisfies the requirements for membership on the
Audit Committee shall be made by the full Board.
2. APPOINTMENT OF COMMITTEE MEMBERS
Members of the Audit Committee shall be appointed from time to time and
shall hold office at the pleasure of the Board. Where a vacancy occurs at
any time in the membership of the Audit Committee, it may be filled by
the Board. The Board shall fill any vacancy if the membership of the
Audit Committee is less than three directors.
3. ABSENCE OF COMMITTEE CHAIR
If the Chair of the Audit Committee is not present at any meeting of the
Audit Committee, one of the other members of the Audit Committee who is
present at the meeting shall be chosen by the Audit Committee to preside
at the meeting.
4. AUTHORITY TO ENGAGE EXPERTS
The Audit Committee has the authority to engage independent counsel and
other advisors as it determines necessary to carry out its duties and to
set the compensation for any such counsel and advisors, such engagement
to be at the Corporation's expense.
5. MEETINGS
The Audit Committee shall meet at least four times per year and shall
meet at such other times during each year as it deems appropriate. In
addition, the Chair of the Audit Committee may call a special meeting of
the Audit Committee at any time. The Audit Committee shall meet with the
external auditors on a regular basis in the absence of management and, if
so requested by a member of the Audit Committee, the external auditor
shall attend every meeting of the Audit Committee held during the term of
office of the external auditor. The Chair of the Audit Committee, the
Chairman of the Board, any two members of the Audit Committee or the
external auditors may call a meeting of the Audit Committee. The external
auditors shall be provided with notice of every meeting of the Audit
Committee and, at the expense of the Corporation, shall be entitled to
attend and be heard thereat. The Chair of the Audit Committee shall hold
IN CAMERA meetings of the Audit Committee, without management present, at
every Audit Committee meeting.
6. QUORUM
A majority of the members of the Audit Committee shall constitute a
quorum.
7. PROCEDURE, RECORDS AND REPORTING
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Subject to any statute or the articles and by-laws of the Corporation,
the Audit Committee shall fix its own procedures at meetings, keep
records of its proceedings and report to the Board when the Audit
Committee may deem appropriate (but not later than the next meeting of
the Board).
8. DELEGATION
The Audit Committee may delegate from time to time to any person or
committee of persons any of the Audit Committee's responsibilities that
lawfully may be delegated.
9. REVIEW OF TERMS OF REFERENCE
The Audit Committee shall review and reassess the adequacy of its Terms
of Reference at least annually, and otherwise as it deems appropriate,
and recommend changes to the Board. Such review shall include the
evaluation of the performance of the Audit Committee against criteria
defined in the Audit Committee mandate as well as the Directors' Charter.