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[OBJECT OMITTED]
[LOGO-WESTERN OIL SANDS]
ANNUAL INFORMATION FORM
March 30, 2005
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TABLE OF CONTENTS
Page
INTRODUCTORY INFORMATION.........................................................................................i
FORWARD LOOKING INFORMATION......................................................................................i
CORPORATE STRUCTURE..............................................................................................1
GENERAL DEVELOPMENT OF THE BUSINESS..............................................................................1
Operating Activities....................................................................................2
NARRATIVE DESCRIPTION OF THE BUSINESS............................................................................4
Project Overview........................................................................................4
Resource Base...........................................................................................5
Third Party Facilities..................................................................................6
Marketing and Sales.....................................................................................6
Regulatory Approvals....................................................................................7
Insurance...............................................................................................7
Proposed Expansions and Feasibility Study Agreement.....................................................8
Reserves Data...........................................................................................9
Other Oil and Gas Information..........................................................................13
Land Tenure............................................................................................15
Royalties..............................................................................................15
Environmental Considerations...........................................................................16
Joint Venture Agreement................................................................................16
DIVIDEND POLICY.................................................................................................18
DESCRIPTION OF SHARE CAPITAL....................................................................................18
MARKET FOR SECURITIES...........................................................................................20
RATINGS ........................................................................................................20
DIRECTORS AND OFFICERS..........................................................................................21
AUDIT COMMITTEE.................................................................................................24
RISKS AND UNCERTAINTIES.........................................................................................26
TRANSFER AGENTS AND REGISTRAR...................................................................................35
INTEREST OF EXPERTS.............................................................................................35
ADDITIONAL INFORMATION..........................................................................................35
GLOSSARY .......................................................................................................36
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 Finance Inc., and Western
Oil Sands L.P., 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.
Readers are cautioned to not place undue reliance on forward-looking information
because it is possible that predictions, forecasts, projections and other forms
of forward-looking information will not be achieved by Western. By its nature,
forward-looking information involves numerous assumptions, inherent risks and
uncertainties. A change in any one of these factors could cause actual events or
results to differ materially from those projected in the forward-looking
information. These factors include, but are not limited to, the following:
market conditions, law or government policy, operating conditions and costs,
project schedules, operating performance, demand for oil, gas and related
products, price and exchange rate fluctuations, commercial negotiations or other
technical and economic factors. For additional information relating to risk
factors please refer to "Risks and Uncertainties".
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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.,
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.
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 Sands Finance Inc., as shown below:
[GRAPPHIC OMITTED]
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.
GENERAL DEVELOPMENT OF THE BUSINESS
Western is a Canadian oil sands corporation that holds a 20 percent undivided
ownership interest in a 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. 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 other oil sands and related business
opportunities.
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OPERATING ACTIVITIES
The Project achieved a major milestone on December 29, 2002 with first bitumen
production at the Mine. Deliveries of diluted bitumen into the dedicated
Corridor pipeline system for delivery to the Upgrader located at Scotford,
Alberta commenced before the end of 2002. At the Upgrader, the primary
distillation units were successfully tested during the fourth quarter of 2002
and commissioning and testing of the synthetic crude units was well underway at
the end of 2002.
Activities leading up to this point were financed through a series of offerings
by the Corporation of a combination of debt and equity and available credit
pursuant to the Corporation's credit facilities. Prior to 2004, these offerings
included:
o A private placement offering of US$450 million senior secured Notes
completed on April 23, 2002. 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. Of the net proceeds from
this offering, $508 million was used to repay the Senior Credit
Facility and all amounts owed to Shell. The $535 million Senior Credit
Facility was cancelled in conjunction with its repayment;
o Concurrent with the completion of the offering of Notes, the
Corporation entered into a senior credit facility with a syndicate of
banks in the aggregate amount of $100 million comprised of a revolving
$75 million debt service/completion facility to be used primarily to
finance interest payable on the Notes with the surplus to be available
to fund Project construction costs and a revolving $25 million
facility for working capital purposes and for letter of credit
requirements;
o On November 19, 2002, the Corporation entered into a $50 million
credit facility (the "Working Capital Facility") with a syndicate of
Canadian chartered banks to fund the Corporation's working capital
requirements. The Working Capital Facility was amended on January 30,
2003 to increase the maximum amount of such facility to $75 million
and to add an additional Canadian chartered bank to the syndicate of
lenders. This was further amended on May 1, 2003 to increase the
maximum amount of such facility to $110 million;
o A public offering of Common Shares at $24.50 per share 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 the Working Capital
Facility and 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.
On January 6, 2003, a fire occurred in the froth cleaning circuit at the Mine
resulting in limited damage, primarily to electrical cables, instrumentation and
insulation in the solvent recovery area of the froth treatment plant. However,
severe weather conditions caused broader freeze damage and impeded progress in
making repairs. Repairs were completed in an expedited manner. Start-up
recommenced on April 4, and the Project achieved fully integrated operations
between the Mine and the Scotford Upgrader on April 19, 2003.
On June 1, 2003, Western commenced 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. The Mine achieved a ramp up approaching design levels by
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year-end, averaging 138,000 barrels per day in December 2003, resulting in an
average 118,000 barrels per day in 2003. By the end of 2003, nine months after
start-up, the Project was operating at 89 percent of design capacity.
Fiscal 2004 represented the first complete year of commercial operations for the
Project. The Project continued to ramp-up production at times achieving levels
that met or exceeded design capacities. A few noteworthy milestones in 2004
include:
o record monthly production in August 2004 averaging 182,000 barrels per
day of bitumen;
o record daily production of approximately 197,000 barrels of bitumen in
August 2004; and
o 40 days over 155,000 barrels of bitumen during the third quarter of
2004.
These milestones evidence the ability of the Project to 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. During the course of 2004, two such unplanned operational
events occurred. At the Mine site, the froth settlers for Train 2 malfunctioned
in July 2004 and repairs were required to bring them to design specifications.
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. With the froth settlers not operating to specifications, the
recovery factor of clean bitumen was reduced. Under normal operating conditions,
this circuit recovers approximately 99% of the bitumen. As a result of this
malfunction, a lower grade of bitumen was transported to the Upgrader resulting
in operational challenges, as optimal Upgrader performance requires a consistent
supply of high grade quality of bitumen. As operations were brought to full
capacity at both the Mine and Upgrader upon completion of these repairs,
additional operational issues surfaced at the Upgrader. The extent of this
unforeseen event and the associated events that followed resulted in fourth
quarter production far below the Corporation's expectations. Though disappointed
in the results of the fourth quarter, steps were taken to avoid a recurrence of
these events in the future. Important information was obtained which will only
serve to promote further production reliability. These events, together with
other minor operational issues associated with a start-up, have been
systematically addressed and resolved in order of priority. Full production at
both the Mine and Upgrader re-commenced on January 30, 2005. The Project's
average daily production of dry bitumen for 2004 was 135,542 barrels per day, or
87% of design rate. Up to the beginning of the fourth quarter, the Project
delivered sequential gains in production and sequential reductions in per barrel
unit operating costs. For the nine months ended September 30, 2004, production
was 144,135 barrels per day (28,827 barrels net to Western) with an operating
cost of $19.32 per processed barrel. Operating costs for the duration of 2004
escalated to $21.17 per processed barrel due to operating costs of $28.22 per
processed barrel in the fourth quarter. Repairs associated with the unplanned
maintenance are expensed as incurred as opposed to capitalized on the balance
sheet .
The necessity for additional financing during fiscal 2004 substantially
diminished as the Project reached a certain level of production reliability, in
turn providing a relatively stable cash flow. Financing and credit activities
were limited to the following:
o A $68 million bought-deal equity offering consisting of 2,000,000
Common Shares at a price of $34.00 per share completed on April 8,
2004;
o During March 2005, Western successfully refinanced its $100 million
senior 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 will be subject
to the same terms and conditions as those contained in the Revolving
Credit Facility; and
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o Repayment of $63 million in credit facilities during the course of
fiscal 2004. Operations during the fourth quarter of 2004 impeded the
ability to reduce the banking facilities further.
The Project has also initiated a three year de-bottlenecking program. Once
completed, production volumes are expected to increase to between 180,000 and
200,000 barrels per day by the end of fiscal 2007. The Project participants are
also looking at initiatives that will enable the processing of the heavier crude
streams into lighter, higher volume crude blend components. De-bottlenecking, as
well as these other initiatives, does not require significant amounts of capital
to complete. Therefore, substantial additional volumes can be achieved with
minor capital investment.
Plans were also announced on September 21, 2004 to expand the Mine such that an
additional 90,000 to 100,000 barrels of bitumen per day can be processed
bringing total dry bitumen production to between 270,000 to 300,000 barrels per
day. Total project costs are estimated at $4 to $4.5 billion (approximately $800
to 900 million, net to Western). Based on an expanded mining plan, capital would
be deployed to purchase mining equipment to recover resources from additional
areas located on Lease 13 and from Lease 90, an additional train for bitumen
extraction and froth treatment processing and to construct a third
hydro-conversion unit and associated utilities at the Scotford Upgrader.
Western announced on April 23, 2004 that both provincial and federal government
cabinet approvals were received by the Joint Venture for the first phase of the
Jackpine Mine in the Athabasca oil sands region of northern Alberta. It is
forecasted that this expansion project will add an additional 200,000 barrels of
bitumen per day by 2013.
NARRATIVE DESCRIPTION OF THE BUSINESS
Western is a Canadian oil sands 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 located on the
western portion of Lease 13. Lease 13 is located in northern Alberta
approximately 70 km north of Fort McMurray, Alberta, abutting the Athabasca
River and the integrated Upgrader is situated near Shell's existing refinery
near Fort Saskatchewan, Alberta. Shell and Chevron hold the remaining 60 percent
and 20 percent undivided ownership interest in the Joint Venture, respectively.
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 other oil sands and related business opportunities.
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). Production of
bitumen commenced at the Mine in January 2003, reaching commercial levels in
June 2003. Ramp up of production at the Project has continued, with average
production during 2004 of approximately 135,542 barrels per day (87 percent of
design capacity). The focus of the Project during 2005 is to improve on the
reliability and efficiency of the operations by ensuring certain
de-bottlenecking initiatives are seen to fruition and constant project
management.
Western provides certain management services including the full and part time
services of certain of its employees to Albian. As at December 31, 2004, Western
had 31 employees. Since completion of construction in December 2002, Western's
main role is to provide operating expertise for the Mine.
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
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sand and extraction plant rejects can be mined from the Mine. 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 pursuant to 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.
RESOURCE BASE
Lease 13 lies within the mineable oil sands area of the Athabasca deposits. The
49,872 acres of Lease 13 are estimated by Western to contain 4.8 billion bbls of
in-place mineable bitumen resources at an average grade of 11.6% bitumen and a
strip ratio of less than 1.5:1. Norwest has verified these estimates in the
Norwest Report.
The Mine covers a 121 square kilometre portion of the western portion of Lease
13. According to GLJ, the western portion of Lease 13 contains approximately 1.0
billion bbls of proved and 0.6 billion bbls of probable reserves. Based on the
Project's design capacity, the Mine's total reserves, both proved and probable,
has a reserve life index of 27 years. This has been verified by Norwest in the
Norwest Report based on consideration of the geology of the mine plan area,
integrity of the exploration data base, the model used to represent the geology
of the mine plan area and the model used to estimate ore characteristics.
Norwest also considered specific geology-related risks.
The current mine reserve is one of the six potentially mineable ore deposits
that have been identified on Lease 13 and Shell's Other Athabasca Leases.
Western is entitled to participate in all future expansions on Lease 13 and in
the 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 Joint Venture's proved and probable reserves on the
western portion of Lease 13, as estimated by GLJ, and the resources available
for future expansion opportunities on the remainder of Lease 13 and Leases 88
and 89, as verified by Norwest. It also includes resources estimated on Lease 9
which was recently acquired by Shell from EnCana Corporation ("EnCana"):
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Western's
Total Share
(MMbbls) (MMbbls)
-------- --------
Joint Venture
Reserves on western portion of Lease 13.............. 1,586 317
Future Opportunities
Resources on remainder of Lease 13................... 3,200 640
Resources on Leases 88 and 89........................ 3,900 780
Resources on Lease 9 1,000 200
8,100 1,620
Lease 17 which was also acquired by Shell from EnCana has not been evaluated.
Hence, no statement is made with respect to its potential. The Joint Venture
intends to evaluate this lease during the course of 2005.
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"), a subsidiary of Terasen
Inc., constructed and owns the dual pipeline systems that connect the Mine to
the Scotford Upgrader and the Scotford Upgrader to certain third party
pipelines. Terasen 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), and are
anticipated to form a single stream blend concurrent with the first expansion of
the Mine, totalling approximately 130,000 barrels per day (26,000 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
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integrity of Western's product and in order to maintain this quality, Western's
products are shipped in segregated streams.
REGULATORY APPROVALS
The Project has all of the material regulatory approvals and permits that it
requires for the operation of the Project. On April 23, 2004, Western announced
that the Joint Venture received both provincial and federal government cabinet
approval for the first phase of its Jackpine Mine. Phase 1 includes a mining and
extraction facility on the eastern portion of Lease 13 with a planned capacity
of approximately 200,000 barrels per day of bitumen.
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 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 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, being $200 million, and will
also be seeking interest and punitive and aggravated damages. The arbitration
panel has now been constituted and Western anticipates hearings to commence in
the fall of 2005. The arbitration involves a number of insurers. Certain
insurers have notified Western that they intend to commence distinct arbitration
proceedings on coverage or jurisdiction issues which they believe are unique to
them. Western will seek to consolidate these into a single arbitration
proceeding.
In order to preserve Western's rights with regard to the cost overrun and
project delay insurance claim, Western has also filed, but not served, a
Statement of Claim in the Court of Queen's Bench of Alberta which includes
claims for aggravated and punitive damages totaling $650 million.
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. Shell continues to pursue claims on behalf
of the Joint Venture for lost profits resulting from production delays caused by
the fire. To date, Western has received $16.1 million from insurers in respect
of claims relating to the fire and freeze damage.
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 U.S. $500 million of property and business interruption
insurance and U.S. $100 million of general liability insurance.
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PROPOSED EXPANSIONS AND FEASIBILITY STUDY AGREEMENT
Western intends to expand its production basis through the development of
certain long-term development opportunities relating to the resources contained
within Lease 13 and on Shell's Other Athabasca Leases. These opportunities
include:
o optimization and expansion of the western portion of Lease 13 and
development of Lease 90, which is one of Shell's Other Athabasca
Leases, to increase total bitumen production from the current design
of 155,000 barrels per day to 245,000 barrels per day. This
development would likely be complete before 2010;
o development of a new mine and extraction facility, known as the
Jackpine Mine, Phase One, to be located on the eastern portion of
Lease 13 with a capacity of 200,000 barrels per day of bitumen
production. The development of this new mine is covered by recent
regulatory approvals from the provincial and federal governments;
o development of additional resources located on Leases 88 and 89, known
as the Jackpine Mine, Phase Two, with a capacity of approximately
100,000 barrels per day of bitumen production. This development
requires additional regulatory approval; and
o development of additional resources on Lease 9 which has recently been
acquired from EnCana. It is estimated that Lease 9 could result in an
additional 200 million barrels net to Western. The Project also
acquired Lease 17 from EnCana but this parcel has not yet been
evaluated.
The Owners are evaluating other de-bottlenecking and expansion scenarios on an
ongoing basis which may alter the volumes and time frames for these
opportunities. One such scenario now in the planning stage involves continuing
with the de-bottlenecking program as originally contemplated, but undertaking
the expansions that follow, one train at a time. This would involve an initial
expansion on the east side of Lease 13 on the Jackpine lease with output at
90,000 to 100,000 barrels per day followed by three identical trains
back-to-back using a program of continuous expansion over approximately 10
years, commencing in 2006. Total production is expected to reach 500,000 to
600,000 barrels per day and will come from Leases 13, 88, 89 and 90. Each of
these expansions will be completed with matching upgrading trains adjacent to
the existing plant at Scotford.
Western, Shell and Chevron entered into a pre-feasibility study agreement in
respect of the development of the Jackpine Mine, Phase One. The objective of the
agreement was to obtain primary regulatory approvals, licenses, permits and
authorizations for the construction of the Jackpine Mine, Phase One mine and
extraction plant and may also in certain circumstances incorporate the resources
for Leases 88, 89 and/or Lease 90. The pre-feasibility phase has now been
completed and the Owners are now progressing through the feasibility study which
is expected to be completed in mid 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.
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The Owners received approval from the joint review panel of the Alberta Energy
and Utilities Board and the federal government for the Jackpine Mine, Phase One
development of the eastern portion of Lease 13. The application is subject to
certain conditions and has been approved by the Cabinets of both the provincial
and federal governments. Since these approvals have been received, the Owners
are now advancing a different scenario as outlined above, and will file an
amendment to the Jackpine permit in early 2005 which will include revision to
the existing Mine permit to accommodate the de-bottlenecking volumes. 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.
RESERVES DATA
GLJ prepared the GLJ Report as at March 11, 2005 which evaluated the reserves
attributable to Western as of December 31, 2004. 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.
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 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, 2004
Constant Prices and Costs Forecast Prices and Costs
----------------------------------- ----------------------------------
Upgraded Bitumen Upgraded Bitumen
----------------------------------- ----------------------------------
Gross(1) Net(1) Gross(1) Net(1)
(MMbbl) (MMbbl) (MMbbl) (MMbbl)
----------------- ----------------- ----------------- ----------------
Proved Developed Producing 199 197 199 179
Proved Developed Non-Producing 5 5 5 4
----------------- ----------------- ----------------- ----------------
Total Proved 204 202 204 183
Total Probable 113 112 113 97
----------------- ----------------- ----------------- ----------------
Total Proved Plus Probable 317 314 317 280
-10-
Net Present Values of Future Net Revenue
Based on Constant Prices and Costs
Before Deducting Incomes Taxes After Deducting Income Taxes
---------------------------------------- -------------------------------------
Undiscounted Discounted at 10% Undiscounted Discounted at
(MM$) (MM$) (MM$) (MM$)
------------------ -------------------- ------------------- -----------------
Proved Developed Producing 4,228 1,991 3,379 1,721
Proved Developed Non-Producing 172 167 111 111
------------------ -------------------- ------------------- -----------------
Total Proved 4,400 2,159 3,490 1,832
Total Probable 3,045 672 2,026 452
------------------ -------------------- ------------------- -----------------
Total Proved Plus Probable 7,445 2,831 5,516 2,285
------------------ -------------------- ------------------- -----------------
The following tables present the estimated future net revenue attributable to
Western, as set forth in the GLJ Report:
Total Future Net Revenue (Undiscounted)
Based on Constant Prices and Costs
Future
Abandonment Future Net
and Net Revenue Revenue
Royalties Operating Development Reclamation Before Income After
Revenue Royalties Costs Costs Costs Income Taxes Taxes Income Taxes
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
--------- --------- ----------- ------------- --------------- ------------- --------- -------------
Total Proved 7,981 25 3,164 393 - 4,399 909 3,490
--------- --------- ----------- ------------- --------------- ------------- --------- -------------
Total Proved
Plus Probable 12,405 39 4,334 587 - 7,445 1,929 5,516
--------- --------- ----------- ------------- --------------- ------------- --------- -------------
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, 2004 are $2,159 million and $2,831 million, in each case based on
constant prices and costs.
NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON FORECAST PRICES AND COSTS
Before Deducting Income Taxes After Deducting Income Taxes
Discounted At Discounted At
------------------------------------------ ------------------------------------------
0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
Proved Developed Producing 3,194 2,203 1,641 1,298 1,073 2,672 1,924 1,485 1,206 1,018
Proved Developed
Non-producing 138 148 125 97 73 111 114 95 73 55
------- ------- -------- ------- ------- ------- ------- ------- ------- -------
Total Proved 3,332 2,351 1,766 1,395 1,146 2,783 2,038 1,579 1,280 1,073
Total Probable 2,563 1,138 565 315 197 1,705 761 383 219 141
------- ------- -------- ------- ------- ------- ------- ------- ------- -------
Total Proved Plus Probable 5,895 3,489 2,331 1,710 1,343 4,488 2,799 1,962 1,499 1,214
======= ======= ======== ======= ======= ======= ======= ======= ======= =======
-11-
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
BASED ON FORECAST PRICES AND COSTS
Future
Net Net
Abandonment Revenue Revenue
and Before After
Operating Development Reclamation Income Income Income
Revenue Royalties Costs Costs Costs Taxes Taxes Taxes
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
Total Proved 7,902 558 3,562 451 - 3,332 549 2,783
Total Proved
Plus Probable 12,890 1,066 5,208 722 - 5,895 1,407 4,488
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, 2004 are $1,766 million and $2,331 million, in each case based on
forecast prices and costs.
RECONCILIATION OF NET RESERVES BY PRINCIPAL PRODUCT TYPE
BASED ON CONSTANT PRICES AND COSTS
Fiscal 2004 represented a full fiscal year of production whereas fiscal 2003
consisted of seven months of commercial operations, commencing on June 1, 2003.
The following table sets forth a reconciliation of the changes in Western's
bitumen reserves as at December 31, 2004 against such reserves as at December
31, 2003 based on the constant price and cost assumptions set forth in Note 9
below:
Upgraded Bitumen
--------------------------------------------------------
Net Probable Net Proved Plus
Net Proved Probable Probable
(MMbbl) (MMbbl) (MMbbl)
-------------- ----------------- -------------------
At December 31, 2003 195 82 277
-------------- ----------------- -------------------
Extensions - - -
Improved Recovery - - -
Technical Revisions - 16 16
Discoveries - - -
Acquisitions - - -
Dispositions - - -
Economic Factors 17 14 31
Production (10) - (10)
-------------- ----------------- -------------------
At December 31, 2004 202 112 314
RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% BASED ON CONSTANT PRICES AND COSTS
The following table sets forth changes between future net revenue estimates
attributable to net proved reserves as at December 31, 2004 against such
reserves as at December 31, 2003:
-12-
2004
(MM$)
---------------------
Estimated Future Net Revenue at December 31, 2003 1,429
---------------------
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (105)
Net Change in Prices, Production Costs and Royalties Related to Future Production 611
Changes in Previously Estimated Development Costs Incurred During the Period 46
Changes in Estimated Future Development Costs (161)
Extensions and Improved Recovery -
Discoveries -
Acquisitions of Reserves -
Dispositions of Reserves -
Net Change Resulting from Revisions in Quantity Estimates -
Accretion of Discount Pre Tax 143
Net Change in Income Taxes (131)
Other changes, including Hedging -
---------------------
Estimated Future Net Revenue at December 31, 2004 1,832
=====================
Notes:
(1) Columns may not add due to rounding.
(2) Reserve definitions consistent with National Instrument 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
"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.
(3) 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 nonproducing reserves as undeveloped is not
considered appropriate for this mining project.
(4) Reserves have not been attributed to Western for the bitumen deposits
present in the eastern portion of Lease 13 or Leases 88 and 89. Western
does not does not currently hold a working interest position in these
expansion opportunities. In addition, no reserves have been attributed
to Leases 90, 9 and 17.
(5) Oil volumes correspond to upgraded bitumen on the basis of 1.03
bbls/bbl of undiluted bitumen. Production from the Upgrader includes
volumes attributable to off-lease feedstock purchases that cannot be
booked as Project reserves.
(6) 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, 2004
Edmonton Par less $8.10/bbl in 2005 and $7.65/bbl thereafter,
reflecting the average December 2004 offset to Edmonton Par for each
feedstock product and marketable product stream, and Western's budgeted
compositions of feedstock and sales. In the forecast price case, GLJ
estimates the oil pricing to be Edmonton Par less $5.50/bbl in 2005,
$5.00/bbl in 2006 and $4.00/bbl thereafter.
(7) Bitumen production has been forecast by GLJ to be 150,000 barrels per
day in 2005 in the proved category growing to 175,000 barrels per day
by 2008 in the total proved category. In the proved plus probable case,
production is forecast to grow from a rate of 155,000 barrels per day
in 2005 to an average rate of 190,000 barrels per day by 2009. The
incremental probable reserves reflect the current mine plan as well as
improved extraction recovery relative to the proved category.
(8) Royalties are paid at the Mine boundary using a deemed bitumen revenue.
For purposes of this evaluation, GLJ has added $0.50/bbl to GLJ's price
for 12 degree heavy oil at Hardisty to reflect historic royalties
calculations. The capital expense base incurred at December 31, 2004 is
estimated at $2,600 million.
(9) The constant price reflects December 31, 2004 prices of $46.54/bbl
Edmonton Par oil, $25.92/bbl Bow River Blend at Hardisty, $6.54/MMBTU
gas and zero inflation. In the forecast price assumptions, the
following GLJ price forecast was used:
-13-
Project Exchange WTI Crude Oil at Light, Sweet Crude Oil at Heavy Crude Oil Alberta Plant
Year Inflation Rate Cushing Oklahoma Edmonton (40 API, 0.3% S) (12 API) at Hardisty Spot Gas
(%) ($US/$Cdn) ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($/MMBTU)
- ---------------------------------------------------------------------------------------------------------------------
2005 2.0 0.82 42.00 50.25 27.50 6.35
2006 2.0 0.82 40.00 47.75 28.50 6.10
2007 2.0 0.82 38.00 45.50 28.75 5.90
2008 2.0 0.82 36.00 43.25 27.25 5.75
2009 2.0 0.82 34.00 40.75 25.50 5.75
2010 2.0 0.82 33.00 39.50 24.75 5.75
2011 2.0 0.82 33.00 39.50 24.75 5.75
2012 2.0 0.82 33.00 39.50 24.75 5.75
2013 2.0 0.82 33.50 40.00 24.75 5.85
2014 2.0 0.82 34.00 40.75 25.50 5.95
2015 2.0 0.82 34.50 41.25 25.75 6.05
2016+ 2.0 0.82 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Western's weighted average historical realized price for 2004 was $34.60 per
synthetic barrel sold , $44.52 per synthetic barrel sold excluding the effects
of hedging activities.
FUTURE DEVELOPMENT COSTS
The following table sets forth the future development costs associated with the
development of Western's reserves as set forth in the GLJ Report.
Total Proved Total Proved Total Proved Plus
Estimated Using Estimated Using Probable Estimated
Constant Prices and Forecast Prices and Using Forecast
Costs Costs Prices and Costs
(MM$) (MM$) (MM$)
------------------- ------------------- --------------
2005 97.4 100.1 103.4
2006 46.4 48.9 55.9
2007 37.6 40.6 59.4
2008 19.2 21.3 28.3
2009 19.2 21.9 23.7
------------------- ------------------- --------------
Total for all years undiscounted 392.6 450.9 721.8
------------------- ------------------- --------------
Total for all years discounted at 10%/year 261.0 289.1 367.7
=================== =================== ==============
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 done at similar rates that have been incurred in the prior years.
OTHER OIL AND GAS INFORMATION
COSTS INCURRED
The following table sets forth costs incurred by Western in respect of the
Project for the year ended December 31, 2004:
Property Acquisition Costs Exploration Costs Development Costs
(MM$) (MM$) (MM$)
- -----------------------------------------------------------------------------------------------------------------
Proved Properties Unproved Properties
- -------------------- -------------------
Nil Nil $38.0 $46.3
-14-
PROPERTIES WITH NO ATTRIBUTED RESERVES
During 2004, Shell purchased Lease 9 and 17 from EnCana. Pursuant to the Joint
Venture Agreement, Western has the right to participate to its 20% Project
interest in these additional leases. The following table summarizes the gross
and net area associated with each of these Leases together with existing leases.
Gross Area Net Area to Western
(hectares) (hectares)
---------------------------- ----------------------------
Lease 88 11,375 2,275
Lease 89 5,975 1,195
Lease 90 1,166 233
Lease 9 6,028 1,206
Lease 17 8,704 1,741
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. As
at January 1, 2005, the following transactions are in place:
Notional Volume Hedge Period Average Price Received
-------------------------------------------------------------------------------
WTI Swaps 14,000 bbls/d January to March 2005 U.S. $26.06
WTI Swaps 7,000 bbls/d April to December 2005 U.S. $26.87
GLJ has not included any effects of hedging activities in the GLJ Report.
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
-15-
TAX HORIZON
Western is currently not required to pay cash income taxes. Western estimates
that cash income taxes will become payable within six to eight 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.
PRODUCTION ESTIMATES
Western estimates that its production of synthetic crude oil will be between 11
MMbls and 13 MMbls for 2005. Production from the Project accounts for 100% of
Western's estimated production in 2005.
PRODUCTION HISTORY
The following table sets forth certain information in respect of production,
product prices received, royalties, production costs and netbacks received by
the Corporation for its synthetic crude oil for each quarter of its most
recently completed financial year: Three Months Ended March 31, 2004 June 30,
2004 September 30, 2004 December 31, 2004 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, 2004 is $8.0
million ($192.5 million undiscounted). These liabilities relate to Western's 20%
working interest in the Project's future dismantlement costs and site
restoration costs for the Mine, Upgrader and related facilities. GLJ has not
included any abandonment and reclamation costs in the GLJ Report. Western does
not anticipate any material expenditures relating to abandonment and reclamation
during the next three years as the current mine plan contemplates development
over 30 years.
Three Monts Ended
---------------------------------------------------------------------------
March 31, 2004 June 30, 2004 September 30, 2004 December 31, 2004
-------------- ------------- ------------------ -----------------
Average Daily Production
(kbpd) 27,197 28,400 30,862 21,990
Average Net Prices Received
($Cdn/bbl) 34.61 36.07 38.63 27.33
Royalties ($000s) 680 768 1,019 486
Operating Expenses ($000s) 51,825 52,828 50,766 57,574
Feedstocks ($000s) 29,701 23,926 47,339 36,844
Netback Received ($Cdn/bbl) 12.33 15.30 18.34 (8.58)
Notes:
(1) Netback is calculated as oil sands revenue less royalties, operating
expenses and feedstocks on a per barrel of production basis.
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
-16-
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.
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
50 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.
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.
-17-
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
dealt with.
The JVA 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 JVA 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 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 eight employees
working directly for the Joint Venture, three of which are operational in nature
including the Chief Operating Officer of Albian while five are based in Calgary
whose 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.
-18-
EXPANSIONS
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, 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 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.
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.
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.
-19-
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.
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%
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per quarter to a maximum of 24% per annum. As of December 31, 2004, all 666,667
Class D Shares were converted into Common shares for no additional
consideration. Consequently, as at the date hereof, there are no outstanding
securities of this class.
-21-
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:
MONTH HIGH LOW CLOSING VOLUME
- ---------------------------------------------------------------------------------------------------------------
January 31.56 28.70 29.49 3,555,084
February 33.40 29.50 33.40 1,751,884
March 35.35 32.21 33.60 3,180,792
April 34.50 31.00 31.25 2,308,909
May 32.74 30.05 31.34 2,939,697
June 33.88 30.35 33.75 3,466,351
July 34.50 33.11 33.78 2,243,037
August 34.10 31.95 33.62 3,597,272
September 37.75 33.31 37.74 5,101,079
October 42.36 37.35 38.90 3,879,521
November 43.50 38.25 42.86 3,093,040
December 43.24 39.01 41.85 2,263,065
RATINGS
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 Western.
- ----------------------------- ------------------------ -------------------------
TYPE OF SECURITY S&P Moody's
- ----------------------------- ------------------------ -------------------------
US$450 Million 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
-22-
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 and Principal Occupation During the Last Director Since
Residence Office Five Years
- ----------------------------------------------------------------------------------------------------------------
Directors
Glen F. Andrews(2)(4)(8) Director Retired businessman. Previously October 1999
President of BHP Copper North America
Bainbridge Island, until June 1999. Prior thereto,
Washington Executive Vice-President and General
Manager, BHP Copper of the South America
and Pacific regions from 1996 to 1998 and
North American region in 1998.
Tullio Cedraschi(4) Director President and Chief Executive Officer of October 2000
Montreal, Quebec CN Investment Division, the entity
responsible for investing the assets of
the Canadian National Railways Pension
Trust Funds.
Geoffrey A. Cumming(2)(3(7) Chairman and Managing Director of Zeus Capital October 1999
Auckland, New Zealand Director 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.
Oyvind Hushovd(4) Director Chairman and Chief Executive Officer of December 2003
Oakville, Ontario Gabriel Resources Ltd., a mining
corporation, since March 2003. President
and Chief Executive Officer of
Falconbridge Ltd., a mining corporation,
from 1996 to February 2002.
-23-
Name and Municipality of Present Position and Principal Occupation During the Last Director Since
Residence Office Five Years
- ----------------------------------------------------------------------------------------------------------------
John W. Lill(2) Director Executive Vice President and Chief December 2003
Toronto, Ontario 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) Director Chairman and Chief Executive Officer of February 2005
Toronto, Ontario 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. Director of Adolph
Coors Company
Robert G. Puchniak(1) Director Executive Vice President and Chief October 1999
Winnipeg, Manitoba 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) President, Chief President of Western since January 2002 July 1999
Calgary, Alberta Executive Officer and Chief Executive Officer of Western
and Director since July 1999; Chairman of Fort Chicago
Energy Partners, L.P. since September
1997 and Chief Executive Officer until
December 2002.
Mac H. Van Director Co-Chairman of ARC Financial December 1999
Wielingen(1)(3)(6) Corporation ("ARC"), a private investment
Calgary, Alberta management company focused on the energy
sector, and Chairman of ARC Energy Trust.
Previously, President of ARC since 1989.
-24-
Name and Municipality of Present Position and Principal Occupation During the Last Director Since
Residence Office Five Years
- ----------------------------------------------------------------------------------------------------------------
Officers
John Frangos Executive Executive Vice-President and Chief --
Calgary, Alberta Vice-President and Operating Officer of Western since
Chief Operating January 2002; prior thereto Corporate
Officer Development, Western since October 1999;
previously Vice-President International
Business Development of BHP Minerals from
April 1996 to September 1999.
David A. Dyck Vice-President, Vice-President, Finance and Chief --
Calgary, Alberta Finance and Chief Financial Officer of Western since
Financial Officer April 2000; prior thereto, Senior Vice
President Finance & Administration and
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 Secretary Partner with Macleod Dixon llp, --
Calgary, Alberta 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) The Corporation does not have an Executive 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 will be resigning as President and Chief Executive
Officer effective April 15, 2005 and will assume the position of
Chairman of the Board and Director. Mr. Geoff Cumming, the current
Chairman, will be stepping down as Chairman effective April 15, 2005,
continuing as an independent Director.
(8) It is anticipated that Mr. Andrews will be retiring from the Board and
the various sub-committees at the Annual and Special Meeting on May 11,
2005.
As announced on February 24, 2005, Messrs Brian MacNeill and Walter Grist
retired from the Board. Also announced at this time was the appointment of Mr.
Randall Oliphant. Mr. Randall Oliphant is the Chairman and Chief Executive
Officer of Rockcliff Group Limited, a private investment corporation actively
involved in the strategic planning and corporate development of its investee
companies, principally in the mining sector. 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. He is on the Advisory Board of Metalmark
Capital LLC (formerly Morgan Stanley Capital Partners) and has served on the
Board of the Adolph Coors Company. He also serves on the Boards of a number of
private companies and not-for-profit organizations. Mr. Oliphant holds a B.Comm.
from the University of Toronto and is a Chartered Accountant.
As disclosed in the Corporation's Information Circular, Mr. David Boone is
proposed to become a director at the Corporation's Annual and Special Meeting to
be held on May 11, 2005. Mr. Boone is a Professional Engineer and has more than
25 years of oil and gas industry experience with significant producing companies
in the Canadian industry. He began his career with Imperial Oil holding various
positions and joined PanCanadian Petroleum in 2000 as Executive Vice-President
and Chief Operating
-25-
Officer. He was named Executive Vice-President of EnCana Corporation upon its
founding in early 2002 and President of the company's Offshore and International
Operations Division. In 2003, he founded a new oil and gas company, Escavar
Energy Inc. and is currently President of that company.
On March 30, 2005, the Corporation announced the appointment of Mr. James C.
Houck as President and Chief Executive Officer effective April 15, 2005. Mr.
Houck will also be nominated to the Board at the Corporation's Annual and
Special Meeting. Mr. Houck spent most of his career with ChevronTexaco Inc. and
held various senior positions within the Texaco organization in global gas and
power, business development, production operations, research & development and
finance & strategic planning. From 1998 to 2003, Mr. Houck was the President of
ChevronTexaco's Worldwide Power and Gasification Inc. Most recently, Mr. Houck
has been a Principal of FrontStreet Partners, a US based privately held
investment firm.
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 30, 2005, 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 1,744,103 Common Shares or
approximately 3.27% of the issued and outstanding voting securities of the
Corporation. Not included the amount above is 1,887,377 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.
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
-26-
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, 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 investment corporation actively involved in the
strategic planning and corporate development of its investee companies,
principally in the mining sector. 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. He is on the Advisory Board of Metalmark Capital LLC
(formerly Morgan Stanley Capital Partners) and has served on the Board of the
Adolph Coors Company. He also serves on the Boards of a number of private
companies and not-for-profit organizations. 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. He also chairs the Significant Gift Division of the
United Way of Calgary and area. 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.
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 reviews Western's interim unaudited consolidated financial
statements, press releases and 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
-27-
procedures. In addition, it reviews and reports to the Board on Western's risk
management policies and procedures and 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 is also charged with reviewing the report of the independent
qualified reserves evaluator relating to the Corporation's estimated oil and gas
reserves. The Committee meets with the independent qualified reserves evaluator
to review the evaluation report, the corporate summary of the reserves and
future net revenues of the oil sands properties and other related matters. In
addition, it reviews the selection and qualifications of the independent
engineering firm, the scope of its work and the consistency of its practices,
standards and definitions
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, 2004 and December
31, 2003:
2004(1) 2003
-------------------------- -----------------------------------
Audit fees $131,980 $66,900
Audit-related fees -- --
Tax fees 24,960 5,720
All other fees -- --
- --------------------------------------------------------------------------------------------------------------------
TOTAL $156,940 $72,620
- --------------------------------------------------------------------------------------------------------------------
Note:
(1) Paid or estimated to be payable for 2004 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. 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;
-28-
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
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.
-29-
The Project relies on transportation of bitumen and upgrader output from a
pipeline system owned and operated by Terasen. 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 Terasen, 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 as a result
of certain long-term contracts. If the Owners did not decide to suspend or
reduce production, the sale of our product at reduced prices would lower our
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
-30-
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 nor 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 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 provide to be inaccurate.
DEBT LEVELS COULD LIMIT FUTURE FLEXIBILITY IN OBTAINING ADDITIONAL DEBT
FINANCING AND IN PURSUING BUSINESS OPPORTUNITIES.
As at December 31, 2004, Western had approximately $812 million of debt
(including obligations under the HMU lease). 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.
-31-
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;
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
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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 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
therefrom, prepared by different engineers or by the same engineers at different
times, 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 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.
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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 if default occurs prior to final completion, or 80% of fair
market value if default occurs after final completion.
SHELL MAY NOT FULFIL ITS OBLIGATIONS TO WESTERN UNDER OUR LONG-TERM SALES
CONTRACT.
Western expects to sell 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
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
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other Owners. Shell and Chevron, have significantly greater capital resources
than Western has. 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.
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 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.
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
-35-
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 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 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
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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.
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.
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.
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 Equity
Transfer Services Inc. at its principal office in Toronto, Ontario is the
co-agent and registrar of the Common Shares of the Corporation.
INTEREST OF EXPERTS
Norwest, independent mining consultants to the Corporation, prepared the Norwest
Report and GLJ, 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.
ADDITIONAL INFORMATION
Additional information relating to the Corporation may be found on SEDAR at
www.sedar.com.
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.
-37
- -
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;
"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;
"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" Gilbert Laustsen Jung Associates Ltd., independent petroleum consultants;
"GLJ Report" The report prepared by GLJ dated March 24, 2005 evaluating the
reserves attributable to Western as of December 31, 2004;
"HMU" The hydrogen manufacturing unit which supplies hydrogen to the Upgrader;
"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;
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"MMbbls" Millions of barrels;
"Mine" The open pit mine is 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 January 18, 2000 and
confirmed by a further report dated March 6, 2001 that considered additional
exploration data and geological information acquired after August 1, 1999;
"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" 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;
"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
"Shell's Other Athabasca Leases" Alberta Crown Oil Sands Lease Nos. 7288080T88,
7288080T89, 7288080T90, 7280050T26, 7281010T93, 7281030T53, 7281030T45,
7280080T28, 7400120009, 7401100017 and all renewals, extensions, replacements
and amendments in respect of same, granted to Shell by the Government of
Alberta.
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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, 2004. The reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2004, 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,
2004, 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, 2004, 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
Description and Reservesr
Preparation Date of (Country or
Evaluation Foreign Net Present Value of Future Net Revenue
Geographic (before income taxes, 10% discount rate)
-----------------------------------------------------------
Report Area) Audited Evaluated Reviewed Total
------ ----- ------- --------- -------- -----
March 11, 2005 Canada 0 2,331.2 MM$ 0 2,331.2 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.
6. We have no responsibility to update the evaluation referred to in
paragraph 4 for events and circumstances occurring after the
preparation dates.
-40-
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:
Gilbert Laustsen Jung Associates Ltd.,
Calgary, Alberta, Canada Dated March 29, 2005
/s/ James H. Willmon, P. Eng.
- -----------------------------
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, 2004 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,
2004 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 Audit 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 Audit 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 Audit 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.
/s/ Guy J. Turcotte, President and Chief Executive Officer
/s/ John Frangos, Executive Vice President and Chief Operating Officer
/s/ Robert G. Puchniak,, Director
/s/ Mac H. Van Wielingen, Director
March 30, 2005
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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 and the risk
management systems and procedures 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 and risk management systems and procedures. 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;
(g) review the appropriateness of the accounting practices and
policies of the Corporation and review any proposed changes
thereto;
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(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;
(g) be satisfied that the fees paid by the Corporation to the
external auditors for audit and non-audit services are
publicly disclosed; and
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(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. Relationship with Independent Reserve Engineers.
The Audit Committee shall:
(a) review the selection and qualifications of the independent
engineering firm responsible for estimation of reserves (the
"Reserves Engineers"), the scope of the Reserves Engineers'
work and ensure the consistency of its practices, standards
and definitions;
(b) review directly with the independent engineering firm the
evaluation report and corporate summary of the reserves and
future cash flows of the properties owned by the Corporation;
(c) review externally disclosed oil and gas reserve estimates and
ensure they meet the requirements of the Alberta Securities
Commission and/or any other relevant regulatory body;
(d) review the Corporation's practices against the Petroleum
Society and Petroleum Evaluation Engineers' Definitions and
Guidelines of Estimating and Classifying Oils and Gas Reserves
and any relevant "best practice" guidelines and make
recommendations to the Board as required;
(e) periodically review the Corporation's relationship with the
Reserves Engineers
(f) maintain direct communication with the Reserves Engineers and
the Corporation's senior reserve personnel; and
(g) assist the Board in respect of matters related to evaluations
of petroleum and natural gas reserves.
4. 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;
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(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.
5. Financial Risk Management.
The Committee shall:
(a) review with management and the external auditors their
assessment of significant financial risks and exposures;
(b) review and assess the steps that management has taken to
mitigate such risks; and
(c) report the results of such reviews to the Board for the
purpose of assisting the Board in identifying the principal
business risks associated with the businesses of the
Corporation.
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 or related financial expertise". The Board has defined
"financial literacy" as the ability to understand a balance sheet,
income statement and a cash flow statements 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
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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
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.