EXHIBIT 1
---------
[LOGO OMITTED]
WESTERN OIL SANDS
ANNUAL INFORMATION FORM
April 27, 2004
TABLE OF CONTENTS
PAGE
INTRODUCTORY INFORMATION.......................................................i
FORWARD LOOKING INFORMATION....................................................i
CORPORATE STRUCTURE............................................................1
GENERAL DEVELOPMENT OF THE BUSINESS............................................1
Financing Activities..................................................2
Operating Activities..................................................3
NARRATIVE DESCRIPTION OF THE BUSINESS..........................................4
Project Overview......................................................4
Resource Base.........................................................5
Third Party Facilities................................................5
Marketing and Sales...................................................6
Regulatory Approvals..................................................6
Insurance.............................................................6
Proposed Expansions and Pre-Feasibility Study Agreement...............7
Reserves Data.........................................................8
Other Oil and Gas Information........................................12
Land Tenure..........................................................14
Royalties............................................................14
Environmental Considerations.........................................14
Joint Venture Agreement..............................................15
SELECTED CONSOLIDATED FINANCIAL INFORMATION...................................17
DIVIDEND POLICY...............................................................18
DESCRIPTION OF SHARE CAPITAL..................................................18
MANAGEMENT DISCUSSION AND ANALYSIS............................................19
MARKET FOR SECURITIES.........................................................19
DIRECTORS AND OFFICERS........................................................20
AUDIT COMMITTEE...............................................................22
RISKS AND UNCERTAINTIES.......................................................25
TRANSFER AGENTS AND REGISTRAR.................................................34
INTEREST OF EXPERTS...........................................................34
ADDITIONAL INFORMATION........................................................34
GLOSSARY......................................................................35
APPENDIX A - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED
RESERVES EVALUATOR
APPENDIX B - REPORT OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION
-i-
INTRODUCTORY INFORMATION
References in this Annual Information Form to Western Oil Sands Inc. ("Western"
or the "Corporation") includes Western and its wholly-owned subsidiaries, 852006
Alberta Ltd., Western Oil Sands Finance Inc., Western Oil Sands USA 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".
-i-
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 three wholly-owned subsidiaries; 852006 Alberta Ltd. (which together
with Western holds a 20% undivided interest in the Project), Western Oil Sands
Finance Inc. and Western Oil Sands USA Inc., as shown below:
[GRAPHIC OMITTED - ORGANIZATIONAL CHART]
______________________
/ | | ----- \
100% / | Western | \ 100%
/ | (Alberta) | \ 100% \
/ |_____________________| \ \
_____________________ / | \ \ _______________________
|852006 Alberta Ltd. | General | \ \ | Western Oil Sands |
| (Alberta) | Partner | \ \ | USA Inc. |
| |\ | \ \ | (Delaware) |
|____________________| \ 1% Limited | \ | (inactive) |
\ Partnership Units | \ |_____________________|
\ | \
99% Limited \ | ________________________
Partnership Units \ | | Western Oil Sands |
_________________________ | Finance Inc. |
| Western Oil Sands L.P. | | (Alberta) |
| (Alberta) | |______________________|
|_________________________|
|
20% |
/ \
/ \
/ \
/Project \
/ \
/____________\
Western's head office is located at 2400 Ernst & Young Tower, 440 - Second
Avenue S.W., Calgary, Alberta T2P 5E9 and its registered office is located at
Suite 3700, 400 Third Avenue S.W., Calgary, Alberta T2P 4H2.
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 ChevronTexaco 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.
-2-
FINANCING ACTIVITIES
During the construction phase of the Project, Western was involved in a series
of financings, including those described below, to fund Western's 20 percent
share of the capital costs of the Project and related expenses and to provide
for working capital following start-up of operations. Western's share of Project
construction costs (excluding costs of repair due to the fire described below)
were $1.14 billion.
On March 14, 2001, the Corporation completed a private placement for the
issuance of Class D Preferred Shares, Series A at a price of $18.00 per share
for gross proceeds of $12 million. The Corporation also entered into a $90
million bridge facility with a Canadian chartered bank. The $90 million bridge
facility was secured by an undertaking by Western to raise funds from other
sources including future bond offerings and/or equity offerings. This facility
was subsequently repaid and cancelled on October 25, 2001.
On April 27, 2001, the Corporation completed a private placement of Common
Shares issued on a flow-through basis at a price of $16.00 per share, for gross
proceeds of $10 million.
In June 2001, the Corporation entered into an additional $30 million bridge
facility with a Canadian chartered bank, that was also secured by an undertaking
by Western to raise funds from other sources including future bond offerings
and/or equity offerings and was subsequently repaid and cancelled on October 25,
2001. Also in June 2001, the Corporation commenced drawdowns under its $535
million Senior Credit Facility to meet its ongoing commitments to the
construction of the Project.
In July 2001, the Corporation completed a further private placement to certain
of its existing shareholders of Non-voting Convertible Equity Shares at $13.00
and $14.00 per share, together with Non-voting Convertible Equity Shares issued
on a flow-through basis at $15.60 per share, for aggregate gross proceeds of
$57.9 million. At this time, certain shareholders also undertook to subscribe
for additional Non-voting Convertible Equity Shares on a flow-through basis at
$15.60 per share, which were subsequently subscribed for and issued in November
2001, for gross proceeds of $11.3 million. In conjunction with these offerings
2,589,641 Call Obligations were issued to certain subscribers, whereby each Call
Obligation was exercisable into one Non-voting Convertible Equity Share and one
Warrant to purchase a Non-voting Convertible Equity Share upon the payment of
$13.00 per Call Obligation. These Call Obligations expired March 31, 2003.
On October 25, 2001, the Corporation completed a rights offering to existing
shareholders, of Common Shares at a price of $14.00 per share for gross proceeds
of $47.4 million. On October 25, 2001, Western established a new $88 million
two-year bridge note purchase facility ("Bridge Facility") with a Canadian
chartered bank. The notes issuable pursuant to draws under the Bridge Facility
were convertible, at maturity at Western's option and in the event of a default
at the option of the bank, into Common Shares at 95% of the then current market
price. This Bridge Facility was repaid in full and cancelled on October 23,
2003.
In November 2001, the Corporation completed a private placement of Non-voting
Convertible Equity Shares issued on a flow-through basis at $17.30 per share for
gross proceeds of $2.6 million.
On April 23, 2002, the Corporation completed a private placement offering of
US$450 million senior secured Notes. The Notes bear interest at 8.375% per
annum, payable on May 1 and November 1 of each year, beginning on November 1,
2002 and mature on May 1, 2012. 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.
-3-
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.
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.
On February 7, 2003 the Corporation completed a public offering of Common Shares
at $24.50 per share for gross proceeds of $50.225 million.
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 the Bridge Facility, the Working Capital
Facility and to provide for working capital during operations.
On April 8, 2004, the Corporation completed a public offering of Common Shares
at $34.00 per share for gross proceeds of $68 million.
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 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.
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.
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 the year, with production
increases each quarter. The Upgrader, which is among the largest of its type in
the world, has operated for periods at and above design capacity. Mining
operations and extraction, by their very nature, encounter many variables. These
variables were addressed and the Mine achieved a ramp up approaching design
levels by year-end, averaging 138,000 barrels per day in December, resulting in
an average 118,000 barrels per day in 2003. Issues such as ore variability,
equipment reliability and robustness, flow velocities, wear and indication and
control have all been addressed and are being resolved in order of priority. By
year-end, nine months after start-up, the Project was operating at 89 percent of
design capacity.
-4-
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 ChevronTexaco 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 production
during the fourth quarter of 2003 averaging approximately 138,000 barrels per
day (89 percent of design capacity). The focus of the Project during 2004 is the
continuous improvement in production to the design capacity of 155,000 barrels
per day.
Western provides certain management services including the full and part time
services of certain of its employees to Albian. As at December 31, 2003, Western
had 27 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 sand and extraction plant rejects can be mined from the Mine.
Approximately 155,000 bbls per day of bitumen is extracted from this ore in the
Extraction Plant and with the addition of non-bitumen feedstocks approximately
190,000 bbls 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.
-5-
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 4.9 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 1.1
billion bbls of proved and 0.5 billion bbls of probable reserves and is
sufficient for approximately 25 years of non-declining bitumen production at
155,000 bbls/d. 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 five potentially mineable ore deposits
that have been identified on Lease 13 and Shell's Other Athabasca Leases.
Western is entitled to participate in future expansions on Lease 13 and to
participate in the other oil sands opportunities with Shell and ChevronTexaco 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:
WESTERN'S
TOTAL SHARE
(MMbbls) (MMbbls)
JOINT VENTURE
Reserves on western portion of Lease 13........... 1,556 311
===== ===
FUTURE OPPORTUNITIES
Resources on remainder of Lease 13................ 3,200 640
Resources on Leases 88 and 89..................... 3,900 780
----- ---
7,100 1,420
===== =====
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 BC Gas
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.
-6-
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
bbls 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, totalling approximately 130,000 bbls
per day (26,000 bbls 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 was 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 has been high,
with these products consistently meeting or exceeding customer expectations.
While Western's upgrading provides synthetic crude oil with superior qualities
for processing, Western's products also lend themselves to blending and
customizing and this flexibility may lead to significant improvements in
refinery efficiencies for Western's customers. A dedicated pipeline to the
Edmonton terminals has ensured the integrity of Western's product and in order
to maintain this quality, Western's products are shipped in segregated streams.
REGULATORY APPROVALS
The Project has all of the material regulatory approvals and permits that it
requires for the operation of the Project.
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, covers
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 that proceedings will
commence shortly. 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.
-7-
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 these 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 $14.3 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 obtained U.S. $500 million of property and business interruption
insurance and U.S. $100 million of general liability insurance.
PROPOSED EXPANSIONS AND PRE-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 bbls/d to 225,000 bbls/d. 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 bbls/d of
bitumen production. The development of this new mine is
covered by recent regulatory approvals from the provincial and
federal governments; and
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 bbls/d of bitumen production. This
development requires additional regulatory approval.
The Owners are evaluating other debottlenecking and expansion scenarios on an
ongoing basis which may alter the volumes and time frames for these
opportunities.
Western, Shell and ChevronTexaco entered into a pre-feasibility study agreement
in respect of the development of the Jackpine Mine, Phase One. The objective of
the agreement is 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 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. The budgeted cost of
these activities to the Owners is approximately $21.6 million, of which
Western's share is approximately $4.3 million. This agreement is not an
amendment to the Joint Venture Agreement and is not considered a feasibility
study or an expansion pursuant to the Joint Venture Agreement, nor will it
trigger any rights for notices for proposed expansions under the Joint Venture
Agreement. This 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
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.
-8-
The Owners received conditional 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 must now be approved by the Cabinets of
both the provincial and federal governments. Once approvals are received, the
Owners will proceed with the project development phase, which includes
feasibility studies and continued community dialogue. This expansion project has
the potential to add 200,000 bbls/d (40,000 bbls/d net to Western) of bitumen
production. A potential expansion to include Phase Two of the Jackpine Mine
expansion could contribute further 100,000 bbls/d (20,000 bbls/d net to
Western). 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 23, 2004 which evaluated the reserves
attributable to Western as of December 31, 2003. 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 revenue 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, 2003
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 214 195 214 196
-------- --------- -------- --------
Total Proved 214 195 214 196
Total Probable 97 82 97 83
-------- --------- -------- --------
Total Proved Plus Probable 311 277 311 279
======== ========= ======== ========
-9-
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 10%
(MM$) (MM$) (MM$) (MM$)
------------------- -------------------- ------------------- -----------------
Proved Developed Producing 3,469 1,626 2,795 1,429
------------------- -------------------- ------------------- -----------------
Total Proved 3,469 1,626 2,795 1,429
------------------- -------------------- ------------------- -----------------
Total Probable 1,825 429 1,198 295
------------------- -------------------- ------------------- -----------------
Total Proved Plus Probable 5,294 2,055 3,993 1,724
=================== ==================== =================== =================
The following tables present the estimated future net revenue attributable to
Western, as set forth in the GLJ Report:
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
BASED ON CONSTANT PRICES AND COSTS
FUTURE FUTURE
NET NET
ABANDONMENT REVENUE REVENUE
AND BEFORE AFTER
OPERATING DEVELOPMENT RECLAMATION INCOME INCOME INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES TAXES TAXES
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
<c>
Total Proved 7,756 472 3,499 316 - 3,469 674 2,795
Total Proved 11,261 814 4,673 480 - 5,294 1,301 3,993
Plus Probable
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 upgraded bitumen reserves attributable to Western's
ownership interest in the Project as at December 31, 2003 is $1,626 million,
based on constant prices and costs.
NET PRESENT VALUES OF FUTURE NET REVENUE
BASED ON FORECAST PRICES AND COSTS
BEFORE DEDUCTING INCOME TAXES AFTER DEDUCTING INCOME TAXES
DISCOUNTED AT DISCOUNTED AT
------------------------------------------ ------------------------------------------
0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
------- ------- -------- ------- ------- -------- ------- ------- -------- -------
Proved Developed
Producing 2,522 1,696 1,242 971 798 2,172 1,526 1,155 925 772
------- ------- -------- ------- ------- -------- ------- ------- -------- -------
Total Proved 2,522 1,696 1,242 971 798 2,172 1,526 1,155 925 772
Total Probable 1,518 687 363 221 151 996 464 257 166 120
------- ------- -------- ------- ------- -------- ------- ------- -------- -------
Total Proved Plus
Probable 4,040 2,383 1,605 1,192 949 3,168 1,990 1,412 1,091 892
======= ======= ======== ======= ======= ======== ======= ======= ======== =======
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
BASED ON FORECAST PRICES AND COSTS
FUTURE FUTURE
NET NET
ABANDONMENT REVENUE REVENUE
AND BEFORE AFTER
OPERATING DEVELOPMENT RECLAMATION INCOME INCOME INCOME
REVENUE ROYALTIES COSTS COSTS COSTS TAXES TAXES TAXES
(MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)
----------- ----------- ----------- ----------- ------------ ----------- ----------- -----------
<c>
Total Proved 7,201 450 3,866 363 - 2,522 350 2,172
Total Proved Plus
Probable 10,818 841 5,365 572 - 4,040 872 3,168
-10-
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 upgraded bitumen reserves attributable to Western's
ownership interest in the Project as at December 31, 2003 is $1,242 million
based on forecast prices and costs.
RECONCILIATION OF NET RESERVES BY PRINCIPAL PRODUCT TYPE
BASED ON CONSTANT PRICES AND COSTS
Commercial production in respect of Western's share of the Project commenced in
June 2003 following the completion of construction and start-up operations. The
following table sets forth a reconciliation of the changes in Western's bitumen
reserves as at December 31, 2003 against such reserves as at December 31, 2002
based on the constant price and cost assumptions set forth in Note 9 below:
UPGRADED BITUMEN
-----------------------------------------------------------
NET PROVED PLUS
NET PROVED NET PROBABLE PROBABLE
(MMbbl) (MMbbl) (MMbbl)
--------------- --------------- -----------------
At December 31, 2002 189 93 282
--------------- --------------- -----------------
Extensions - - -
Improved Recovery - - -
Technical Revisions (1) (14) (15)
Discoveries - - -
Acquisitions - - -
Dispositions - - -
Economic Factors 12 3 15
Production (5) - (5)
--------------- --------------- -----------------
At December 31, 2003 195 82 277
RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% BASED ON CONSTANT PRICES AND COSTS
The following table sets forth changes between future net revenue estimates
attributable to net proved reserves as at December 31, 2003 against such
reserves as at December 31, 2002:
2003
(MM$)
-------------
Estimated Future Net Revenue at December 31, 2002 2,063
-------------
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and (56)
Royalties
Net Change in Prices, Production Costs and Royalties Related to Future Production (743)
Development Costs During the Period 92
Changes in Estimated Future Development Costs (56)
Extensions and Improved Recovery -
Discoveries -
Acquisitions of Reserves -
Dispositions of Reserves -
Net Change Resulting from Revisions in Quantity Estimates (5)
Accretion of Discount Pre Tax 235
Net Change in Income Taxes 87
Other changes, including Hedging (188)
-------------
Estimated Future Net Revenue at December 31, 2003 1,429
=============
-11-
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. It is likely that the actual
remaining quantities recovered will exceed the estimated proved
reserves.
"Probable" reserves are those additional reserves that are less certain
to be recovered than proved reserves. It is equally likely that the
actual remaining quantities recovered will be greater or less than the
sum of the estimated proved plus probable reserves.
"Developed" reserves are those reserves that are expected to be
recovered from existing wells and installed facilities or, if
facilities have not been installed, that would involve a low
expenditure (e.g. when compared to the cost of drilling a well) to put
the reserves on production.
"Developed Producing" reserves are those reserves that are expected to
be recovered from completion intervals open at the time of the
estimate. These reserves may be currently producing or, if shut-in,
they must have previously been on production, and the date of
resumption of production must be known with reasonable certainty.
(3) The Project reserves are developed. No reserves have been attributed to
the bitumen deposits present in the eastern portion of Lease 13 or
Leases 88 and 89 because of the current uncertainty of their
development.
(4) Oil volumes correspond to upgraded bitumen on the basis of 1.03
bbls/bbl of undiluted bitumen. Production from the Upgrader will
include volumes that are attributable to off-lease feedstock purchases
that cannot be booked as Project reserves. In the forecast price case,
GLJ estimates the oil pricing to be Edmonton Par less $4.00/bbl in
2004, $3.00/bbl in 2005 and $2.00/bbl thereafter. In the constant price
case, GLJ estimates the oil pricing to be Edmonton Par less $4.65/bbl
in 2004 and $4.50/bbl thereafter. These pricing forecasts reflect total
revenues associated with the output from the Upgrader less the purchase
costs associated with feedstock.
(5) Bitumen production has been forecast by GLJ to be 150,000 bbls per day
in 2004 in the proved category, with a remaining mine life of 19 years.
The 150,000 bbls per day rate and 19 years of operation is consistent
with the regulatory applications. In the proved plus probable case,
production is forecast to grow from a rate of 155,000 bbls per day in
2004 to an average rate of 170,000 bbls per day by 2006. The reserves
recovered in the proved plus probable category reflect a remaining mine
life of approximately 25 years. The incremental probable reserves
reflect additional ore within the designated pits as well as an
improved extraction recovery relative to the proved category.
(6) Operating costs over the Project life will fluctuate, with an average
of approximately $15.472/bbl (2004 $) undiluted bitumen forecast in the
proved plus probable category. Sustaining capital of approximately
$1.55/bbl (2004 $) bitumen is forecast in the proved plus probable
category. The evaluation recognizes that a component of operating costs
is tied to the price of natural gas; $5.83/MMBTU was used in the above
estimate. A range of operating costs are used by GLJ, with higher
estimates being used in the proved category and lower estimates used in
the proved plus probable category. The probable category includes
capital related to debottlenecking activities.
(7) While the production, operating and capital costs were prepared with an
understanding as to the feasibility study prepared in connection with
the Project, due diligence reports obtained by Western and actual
results achieved in 2003, these forecasts reflect GLJ's judgment and
interpretations and should not be construed as corresponding to Owner
expectation.
(8) Royalties are anticipated to be paid at the Mine boundary using a
deemed bitumen revenue. The basis for determining the bitumen price has
not been determined. 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 royalties correspond to the
generic oil sand royalty regime recently enacted. An initial royalty of
1% on gross revenue is paid until 100% of the Project capital,
including a return on capital, has been recovered. The royalty
subsequently becomes 25% of net deemed bitumen revenue. The return
allowance is set at the monthly federal long-term bond rate, which is
forecast to be 4% real. The capital expense base incurred and the Crown
royalty base accumulated to December 31, 2003 are estimated at $2,950
million and $210 million, respectively.
(9) The constant price reflects December 31, 2003 prices of $40.81/bbl
Edmonton Par oil, $23.31/bbl 12 degree crude at Hardisty, $5.83/MMBTU
gas and zero inflation. In the forecast price assumptions, the
following GLJ price forecast was used:
-12-
HEAVY CRUDE OIL
PROJECT EXCHANGE WTI CRUDE OIL AT LIGHT, SWEET CRUDE OIL AT (12 API) AT ALBERTA PLANT
YEAR INFLATION RATE CUSHING OKLAHOMA EDMONTON (40 API, 0.3% S) HARDISTY SPOT GAS
(%) ($US/$CDN) ($US/BBL) ($CDN/BBL) ($CDN/BBL) ($/MMBTU)
- ---------------------------------------------------------------------------------------------------------------------
2004 1.5 0.75 34.25 44.75 29.00 6.40
2005 1.5 0.75 29.00 37.75 25.00 5.30
2006 1.5 0.75 27.00 35.25 23.75 4.95
2007 1.5 0.75 25.00 32.50 21.00 4.75
2008 1.5 0.75 25.00 32.50 21.00 4.75
2009 1.5 0.75 25.00 32.50 21.00 4.75
2010 1.5 0.75 25.50 33.00 21.50 4.85
2011 1.5 0.75 25.75 33.50 22.00 4.95
2012 1.5 0.75 26.25 34.00 22.50 5.05
2013 1.5 0.75 26.50 34.50 23.00 5.15
2014 1.5 0.75 27.00 35.00 23.50 5.20
2015 1.5 0.75 +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr
FUTURE DEVELOPMENT COSTS
The following table sets forth the future development costs associated with the
development of Western's reserves as set forth in the GLJ Report. Development
costs will be funded from cashflow from operations.
TOTAL PROVED PLUS
TOTAL PROVED TOTAL PROVED PROBABLE
ESTIMATED USING ESTIMATED USING ESTIMATED USING
CONSTANT PRICES AND FORECAST PRICES AND FORECAST PRICES
COSTS COSTS AND COSTS
(M$) (M$) (M$)
------------------- ------------------- ---------------
2004 16,646 16,646 27,405
2005 16,646 16,896 28,228
2006 16,646 17,149 19,450
2007 16,646 17,406 19,741
2008 16,646 17,667 20,037
------------------- ------------------- ---------------
Total for all years undiscounted 316,274 362,828 571,803
------------------- ------------------- ---------------
Total for all years discounted at 10%/year 146,039 160,830 216,447
=================== =================== ===============
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, 2003:
PROPERTY ACQUISITION COSTS EXPLORATION COSTS DEVELOPMENT COSTS
(MM$) (MM$) (MM$)
------------------------------------------- ----------------- -----------------
PROVED PROPERTIES UNPROVED PROPERTIES
----------------- -------------------
Nil Nil 1.3 55.9 (1)
NOTE:
(1) Does not include the costs related to repairing damage from the January
6, 2003 fire at the Mine.
FORWARD CONTRACTS
The Corporation has entered into various commodity pricing agreements designed
to mitigate the exposure to the volatility of crude oil prices in U.S. dollars.
The agreements are summarized as follows:
-13-
NOTIONAL VOLUME HEDGE PERIOD AVERAGE PRICE RECEIVED
------------------------------------------------------------------------------
WTI Swaps 20,000 bbls/d Fiscal 2004 U.S.$27.37
WTI Swaps 16,000 bbls/d January to March 2005 U.S.$26.17
WTI Swaps 7,000 bbls/d April to December 2005 U.S.$26.87
ABANDONMENT AND RECLAMATION COSTS
Western has abandonment and reclamation liabilities relating to the Mine,
Upgrader and related facilities. Western estimates the abandonment liability,
net of salvage, for these assets with consideration given to the expected cost
to abandon and reclaim the lands and facilities. These estimates are based on
prevailing industry conditions, regulatory requirements and past experience. The
value is determined by Western first estimating the anticipated timing and
amount of net cash outflows using third party costs for future dismantlement and
site restoration. These future payments are then present valued using a credit
adjusted risk free rate appropriate for Western.
The liability is estimated in the period in which the liability is incurred.
These estimates are prepared annually and adjustments are made quarterly for
material changes in the amount of the liability or the timing of abandonment.
Where material differences are identified, adjustments to the liabilities or
accretion expense are made on a prospective basis.
Western's share of the present value of abandonment and reclamation costs that
require recognition in its financial statements at December 31, 2003 is $7.1
million. These liabilities relate to Western's 20% working interest in the
Project's future dismantlement costs and site restoration costs for the Mine,
Upgrader and related facilities. GLJ has not included any abandonment and
reclamation costs in the GLJ Report. Western does not anticipate any material
expenditures relating to abandonment and reclamation during the next three years
as the current mine plan contemplates development over 30 years.
TAX HORIZON
Western is currently not required to pay cash income taxes. The Corporation
estimates that cash income taxes will become payable within six to eight years,
depending on commodity prices, foreign exchange rates, operating costs, interest
rates, future annual taxable income levels, expansions of the Project and other
business activities. Changes in these factors from estimates used by Western
could result in Western paying income taxes earlier or later than expected.
PRODUCTION ESTIMATES
Western estimates that its production of synthetic crude oil will be between 13
MMbls and 15 MMbls for 2004. Production from the Project accounts for 100% of
Western's estimated production in 2004.
PRODUCTION HISTORY
The following table sets forth certain information in respect of production,
product prices received, royalties, production costs and netbacks received by
the Corporation for each quarter of its most recently completed financial year:
-14-
THREE MONTHS ENDED
-------------------------------------------------------------------------------
MARCH 31, 2003 JUNE 30, 2003 (1) SEPTEMBER 30, 2003 DECEMBER 31, 2003
-------------- ----------------- ------------------ -----------------
Average Daily Production Nil 17,138 23,260 26,034
(kbpd)
Average Net Prices Received Nil 35.26 34.14 31.30
($Cdn/bbl)
Royalties ($000s) Nil 138 513 500
Operating Expenses ($000s) Nil 12,881 44,121 49,823
Feedstocks ($000s) Nil 3,599 25,212 33,626
Netback Received ($Cdn/bbl) Nil 5.97 13.43 9.98
NOTES:
(1) The three months ended June 30, 2003 represent Western's operations
from June 1, 2003 only, being the date that commercial operations
commenced.
(2) Netback is calculated as 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 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.
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.
-15-
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
ChevronTexaco to participate in mining operations on the east area of Lease 13
and in Shell's Other Athabasca Leases; (v) an area of mutual interest for
expansion of operations of the Joint Venture; (vi) the disposition of the
Upgrader products; and (vii) the construction operations relating to the
foregoing.
The Joint Venture has been established pursuant to a number of agreements among
the Owners and is the subject of other agreements between the Owners and third
parties.
JOINT VENTURE AND RELATED AGREEMENTS
The principal agreement, which established the Joint Venture and governs the
relationship of the Owners, is the Joint Venture Agreement. This agreement also
sets out the manner in which certain of the other Project agreements will be
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.
-16-
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 ensure 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. Certain Western personnel will
be dedicated to the Project until three years after Extraction Plant Start-up
while others, whose functions relate solely to construction, are dedicated to
the Project through to six months after Extraction Plant Start-up. The Mining
and Extraction Services Agreement may be terminated three years after Extraction
Plant Start-up. 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.
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.
-17-
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.
SELECTED CONSOLIDATED FINANCIAL INFORMATION
The following table sets forth selected financial information for Western for
the periods indicated.
YEAR ENDED DECEMBER 31
----------------------------------------------------------------
2003 2002 2001
------------------ ------------------ --------------------
($ thousands, except per share amounts)
Revenues 281,093 -- --
Earnings (Loss) Attributable to Common
Shareholders 15,003 (10,286) (7,015)
Earnings (Loss) Per Share
- - basic 0.30 (0.21) (0.17)
- - diluted 0.29 (0.21) (0.17)
Total Assets 1,458,424 1,359,638 854,394
Total Long Term Liabilities 921,910 827,133 368,306
Total Shareholders' Equity 469,225 487,497 434,866
Cash Dividends Nil Nil Nil
THREE MONTHS ENDED
---------------------------------------------------------------------------------------------------------
MAR 31, JUNE 30, SEPT 30, DEC 31, MAR 31, JUNE 30, SEPT 30, DEC 31,
2003 2003 2003 2003 2002 2002 2002 2002
----------- ---------- ----------- ---------- ---------- ----------- ---------- ---------
($ in
thousands,
except amounts
per share)
Revenues -- 24,930 122,496 133,667 -- -- -- --
Net earnings (2,376) 1,276 (1,515) 17,618 (1,755) (24,681) (1,821) 17,971
(loss)(1)
Earnings (Loss)
per share
- - (basic) (0.05) 0.03 (0.03) 0.35 (0.04) (0.51) (0.04) 0.38
- - (diluted) (0.05) 0.02 (0.03) 0.35 (0.04) (0.51) (0.04) 0.38
NOTES:
(1) Represents Earnings (loss) Attributable to Common Shareholders.
-18-
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 or Class D Preferred
Shares, Series A 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.
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.
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
-19-
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.
CLASS D SHARES
The Class D Shares are entitled to receive notice of, attend and vote at any
meetings of shareholders and are convertible into Common Shares, prior to
redemption, on a one-for-one basis. The Class D Shares are redeemable by the
Corporation at a price equal to their issue price plus a cumulative dividend of
12% per annum compounded semi-annually until January 1, 2007, from which date
the dividend increases by 3% per quarter to a maximum of 24% per annum.
MANAGEMENT DISCUSSION AND ANALYSIS
Reference is made to the section entitled "Management's Discussion and Analysis"
of the Corporation's 2003 Annual Report to Shareholders, which section is
incorporated herein by reference.
MARKET FOR SECURITIES
The Common Shares of the Corporation are listed for trading on the Toronto Stock
Exchange 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 Toronto
Stock Exchange for each monthly of the most recently completed financial year:
MONTH HIGH LOW CLOSING VOLUME
- --------------------------------------------------------------------------------
January $26.50 $23.20 $23.85 2,298,925
February $25.91 $21.95 $25.63 1,941,520
March $25.85 $23.00 $23.99 1,240,243
April $25.38 $24.00 $24.70 2,855,042
May $26.00 $24.15 $25.70 1,538,977
June $28.29 $24.50 $27.75 1,781,463
July $27.90 $25.75 $26.50 2,004,852
August $27.75 $26.02 $27.25 2,773,401
September $28.32 $26.50 $27.00 1,684,091
October $28.50 $26.85 $27.01 2,599,433
November $27.45 $26.00 $27.27 2,514,956
December $30.00 $26.50 $29.50 2,986,551
-20-
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 PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST
OF RESIDENCE AND OFFICE FIVE YEARS DIRECTOR SINCE
- --------------------------------------------------------------------------------------------------------------------------
DIRECTORS
Glen F. Andrews (2)(4) Director Retired businessman. Previously President of October 1999
Bainbridge Island, BHP Copper North America until June 1999.
Washington Prior thereto, 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 CN October 2000
Montreal, Quebec Investment Division, the entity responsible
for investing the assets of the Canadian
National Railways Pension Trust Funds.
Geoffrey A. Cumming (2)(3) Chairman and Managing Director of Zeus Capital Limited, a October 1999
Auckland, New Zealand Director 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.
Walter W. Grist (4) Director Managing Director, Brown Brothers Harriman & December 1999
New York, New York Co., a private investment management and
banking partnership which is general partner
of The 1818 Fund III, L.P.
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.
-21-
- --------------------------------------------------------------------------------------------------------------------------
NAME AND MUNICIPALITY PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST
OF RESIDENCE AND OFFICE FIVE YEARS DIRECTOR SINCE
- --------------------------------------------------------------------------------------------------------------------------
John W. Lill (2) Director Executive Vice President and Chief December December 2003
Toronto, Ontario 2003 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.
Brian F. MacNeill (1)(3) Director Chairman of Petro-Canada since 2000. October 1999
Calgary, Alberta President and Chief Executive Officer of
Enbridge Inc., an energy transportation,
distribution and services corporation, from
1991 to September 1 2000.
Robert G. Puchniak (1) Director Executive Vice President and Chief Financial October 1999
Winnipeg, Manitoba 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 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 Wielingen Director Co-Chairman of ARC Financial December 1999
(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.
OFFICERS
Charles W. Berard Corporate Secretary Partner with Macleod Dixon LLP, --
Calgary, Alberta Barristers & Solicitors.
-22-
- --------------------------------------------------------------------------------------------------------------------------
NAME AND MUNICIPALITY PRESENT POSITION PRINCIPAL OCCUPATION DURING THE LAST
OF RESIDENCE AND OFFICE FIVE YEARS DIRECTOR SINCE
- --------------------------------------------------------------------------------------------------------------------------
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.
John Frangos Executive Vice- Vice-President and Operating Officer of --
Calgary, Alberta President and Chief Western since Chief Operating January 2002;
Operating Officer prior thereto Corporate Officer Development,
Western since October 1999; previously
Vice-President International Business
Development of BHP Minerals from April 1996
to September 1999.
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
("G3auntlet") 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.
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 April 27, 2004, the directors and officers of the Corporation, together
with their respective spouses, children or corporations controlled by them own
or control, directly or indirectly, an aggregate of 3,866,334 Common Shares and
no Class D Preferred Shares, Series A or approximately 7.3% of the issued and
outstanding voting securities of the Corporation.
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), Brian F. MacNeill and Mac H. Van Wielingen, all of whom are
financially literate.
-23-
In considering criteria for the determination of financial literacy, the Board
of Directors looks at the ability to read and understand a balance sheet, an
income statement and a cash flow statement of a public company.
The following is a brief description of the education and experience of each of
the members of the Audit Committee:
ROBERT G. PUCHNIAK, CHAIRMAN AND INDEPENDENT DIRECTOR
Mr. Puchniak was appointed Executive Vice-President and Chief Financial Officer
of James Richardson & Sons, Limited, an investment and holding corporation, in
March 2001 and prior thereto was Vice-President, Finance and Investment with
James Richardson & Sons, Limited since November 1996. Mr. Puchniak was President
and Chief Executive Officer of Tundra Oil and Gas Ltd., a private oil and gas
corporation, from January 1989 to April 2003. Mr. Puchniak has also held
positions with Gendis Inc. and Richardson Securities Limited. Mr. Puchniak is a
director of a number of public and private corporations including James
Richardson International Limited, Tundra Oil and Gas Ltd., Opti Canada Inc.,
Canstar Exploration 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.
BRIAN F. MACNEILL, INDEPENDENT DIRECTOR
Mr. MacNeill was President and Chief Executive Officer of Enbridge Inc., an
energy, transportation, distribution and services corporation, from 1991 to
2001. Mr. MacNeill is currently Chairman of the Board of Directors of
Petro-Canada and Chairman of the Board of Governors of the University of
Calgary. Mr. MacNeill is a Director of The Toronto-Dominion Bank, Dofasco Inc.,
Sears Canada Inc., Telus Corporation, Veritas DGC Inc., Western Oil Sands Inc.,
West Fraser Timber Co. Ltd. Mr. MacNeill is a member of the Alberta and Ontario
Institutes of Chartered Accountants and the Financial Executives Institute. Mr.
MacNeill holds a Bachelor of Commerce degree from Montana State University and
is a C.P.A. He is a fellow of the Canadian Institute of Chartered Accountants.
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 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
-24-
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 its independence based on the
criteria found in the recommendations of the Canadian Institute of Chartered
Accountants. The Committee must be satisfied that adequate procedures are in
place for the review of the Corporation's public disclosure of financial
information extracted or derived from its financial statements and it
periodically assesses the adequacy of those procedures. In addition, it reviews
and reports to the Board on Western's risk management policies and procedures
and reviews the internal control procedures to determine their effectiveness and
to ensure compliance with Western's policies and avoidance of conflicts of
interest. The Committee has established procedures for dealing with complaints
or confidential submissions 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 reserves. The
Committee meets independently of management 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 Corporation's relationship with the
independent consulting firm and makes a recommendation to the Board in respect
of the appointment of the independent qualified reserves evaluator.
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, 2003 and December
31, 2002:
2003(1) 2002
---------- ---------
Audit fees 41,900 35,000
Audit-related fees 25,000 27,115
Tax fees 5,720 43,420
All other fees -- --
- --------------------------------------------------------------------------------
TOTAL $72,620 $105,535
- --------------------------------------------------------------------------------
NOTE:
(1) Paid or estimated to be payable for 2003 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.
-25-
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 delays or additional costs due to many factors,
including:
o breakdown or failure of equipment or processes;
o design errors;
o operator errors;
o violation of permit requirements;
o disruption in the supply of energy; and
o catastrophic events such as fire, earthquake, storms or
explosions.
The Project consists of multiple facilities, all of which must be
successfully integrated and co-ordinated. There can be no assurance that each
component will operate as designed or expected or that the necessary levels of
integration and co-ordination will 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 hydrogen
manufacturing unit 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 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
-26-
prices acceptable to Western, or at all. If the cogeneration facility does not
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 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 unit fails to
perform as designed or Dow fails to deliver pursuant to its contract,
respectively, there can be no assurance that the Project will be able to obtain
its hydrogen requirements on a timely basis, at prices acceptable to Western, or
at all.
The Project relies on transportation of bitumen and upgrader output from a
pipeline system owned and operated by 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.
PRODUCTION DURING RAMP-UP MAY NOT MEET THE PLANNED SCHEDULE OR BUDGET.
There is a risk that production from the Project may not increase as quickly as
planned, or at the costs anticipated. Many factors in addition to the risks
described above under "Risk Factors - The Mine, Extraction Plant and Upgrader
may not perform as planned" could impact the pace of Project Start-Up and
economic efficiency of production including:
o the operation of any part of the Project (Mine, Extraction
Plant, Upgrader or third-party facilities) falling below
expected levels of performance, output or efficiency; and
o unanticipated or unplanned shutdowns or curtailments of any
component of the Project.
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.
-27-
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 within the near future 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 to be marketed initially. There is a risk that Western
will be unable to create a single stream with a higher value than the heavy and
light streams. There is also a risk that the price per barrel from selling two
synthetic crude oil streams and vacuum gas oil could be significantly less than
the price per barrel from selling a single synthetic crude oil stream and vacuum
gas oil.
FLUCTUATIONS IN THE US AND CANADIAN DOLLAR EXCHANGE RATE MAY CAUSE WESTERN'S
OPERATING COSTS TO RISE.
Crude oil prices are generally based on a US dollar market price, while
Western's operating costs are primarily denominated in Canadian dollars. Adverse
fluctuations in the US and Canadian dollar exchange rate may cause Western's
operating costs to rise in relation to Western's revenues. Western does not
currently hedge against currency fluctuations and there can be no assurance that
any hedging policy Western may adopt 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 ChevronTexaco, 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
-28
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 limited historical operating results. Western's 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, 2003, Western had approximately $914 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.
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;
-29-
o entering into fixed contracts for oil production; and
o entering into a contract to fix the differential between the
price for Western's outputs and either the West Texas
Intermediate or the Edmonton Par crude oil pricing benchmarks.
If product prices increase above those levels specified in any future hedging
agreements, Western could lose the cost of floors or ceilings or a fixed price
could limit Western from receiving the full benefit of commodity price
increases. In addition, by entering into these hedging activities, Western may
suffer financial loss if it is unable to produce sufficient quantities of oil to
fulfil its obligations.
Western may hedge its exposure to the costs of various inputs to the Project,
such as natural gas or feedstocks. If the prices of these inputs falls below the
levels specified in any future hedging agreements, Western could lose the cost
of ceilings or a fixed price could limit Western from receiving the full benefit
of commodity price decreases.
RESERVE AND RESOURCE ESTIMATES ARE UNCERTAIN.
There are numerous uncertainties inherent in estimating quantities of reserves
and resources, including many factors beyond Western's control. Western's
reserve and resource data represent estimates only. The usefulness of such
estimates is highly dependent upon the accuracy of the assumptions on which they
are based, the quality of the information available and the ability to compare
such information against industry standards.
Fluctuations of oil prices may render the mining of oil sands reserves
uneconomical. Other factors relating to the oil sands reserves, such as the need
for orderly development of ore bodies or the processing of new or different
grades of ore, may impair Western's profitability.
In general, estimates of economically recoverable bitumen reserves and the
related future net pretax cash flows of the Project are based upon a number of
variable factors and assumptions, such as:
o historical production from similar properties which are owned
by other operators;
o 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 no 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.
-30-
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 CHEVRONTEXACO MAY NOT AGREE WITH WESTERN ON MATTERS RELATED TO THE
PROJECT.
The Project is a joint venture among Shell, ChevronTexaco 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 ChevronTexaco. 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 effect Western.
SHELL AND CHEVRONTEXACO MAY NOT MEET THEIR OBLIGATIONS TO THE PROJECT.
Western is subject to the risk of non-payment by Shell or ChevronTexaco 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 CHEVRONTEXACO 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
-31-
sell its share of vacuum gas oil to other purchasers at a price equal to or
greater than that provided for in its contract with the Shell affiliate, or at
all.
Additionally, the price Western receives for products sold to the affiliate of
Shell may vary depending on the characteristics of the products sold. To the
extent the characteristics of the products fail to meet agreed upon
specifications, the purchase price for such products will be adjusted downward.
If the characteristics of the products are significantly below specifications
the affiliate of Shell is entitled to reject such products. Downward adjustment
of the purchase price or rejection of the products could have an adverse effect
on Western's operations and revenues, and there can be no assurance that we
could sell any rejected products elsewhere.
IF WESTERN DOES NOT PARTICIPATE IN CERTAIN EXPANSIONS, WESTERN WILL LOSE VOTING
OR SIGNIFICANT EXPANSION RIGHTS.
If Western does not participate in expansions on the western portion of Lease
13, in certain circumstances Western's voting interest will be diluted and
Western's consent will no longer be required for extraordinary resolutions of
the Executive Committee. In addition, if Western does not participate in an
expansion on the remainder of Lease 13 or Shell's Other Athabasca Leases, or if
Western no longer has an ownership interest in each functional unit comprising
the Project, Western will lose its right to participate in any further
expansions, lose any rights to share in the resources contained on Leases 88 and
89 and Shell's Other Athabasca Leases and lose any rights to participate in an
area of mutual interest with the other Owners. Shell and ChevronTexaco, 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 incurred 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.
-32-
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, Western must establish and fund a reclamation trust
fund. Western currently does not hold the minimum credit rating. Even if Western
does hold the minimum credit rating, in the future Western may determine that it
is prudent or that Western is required by applicable laws or regulations to
establish and fund one or more additional funds to provide for payment of future
decommissioning, abandonment and reclamation costs. Even if Western concludes
that the establishment of such a fund is prudent or required, Western may lack
the financial resources to do so. Western may also be required by future
regulatory requirements to establish a fund or place funds in trust with
regulators for the decommissioning and abandonment of the Project and the
reclamation of its lands.
THE PROJECT MAY FAIL TO COMPLY WITH VARIOUS ENVIRONMENTAL APPROVALS WHICH MAY
EITHER CAUSE THE WITHDRAWAL OF THESE APPROVALS OR IMPOSE OTHER COSTS.
The operation and decommissioning of the Project and reclamation of the
Project's lands are conditional upon various environmental and regulatory
approvals issued by governmental authorities. Further, the operation and
decommissioning of the Project and reclamation of the Project's lands will be
subject to approvals and present and future laws and regulations relating to
environmental protection and operational safety. Risks of substantial costs and
liabilities are inherent in oil sands operations, and there can be no assurance
that substantial costs and liabilities will not be incurred or that the Project
will be permitted by regulators to carry on its operations. Other developments,
such as increasingly strict environmental and safety laws, regulations and
enforcement policies thereunder, and claims for damages 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
-33-
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, labor standards, occupational health, waste
disposal, protection and remediation of the environment, mine safety, hazardous
materials, toxic substances and other matters. Amendments to current laws and
regulations and the introduction of new laws and regulations governing
operations and activities of mining corporations and more stringent application
of such laws and regulations are actively considered from time to time and could
affect the viability of the Project.
There can be no assurance that the various government licenses and approvals or
amendments thereto that from time to time may be sought will be granted to the
Project at all or with conditions satisfactory to Western or, if granted, will
not be cancelled or will be renewed upon expiry or that income tax laws and
government incentive programs relating to the Project, and the mining, oil sands
and oil and gas industries generally, will not be changed in a manner which may
adversely affect Western.
Currently, Western benefits from a favourable royalty regime; however, there can
be no assurance that this royalty regime will not change in a manner that would
adversely affect Western.
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.
-34-
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. The Corporation, upon request to the Chief Financial Officer of
the Corporation, will provide to any person or company:
(a) when the securities of the Corporation are in the course of a
distribution under a preliminary short form prospectus or a
short form prospectus,
(i) one copy of the Annual Information Form of the
Corporation, together with one copy of any document,
or the pertinent pages of any document, incorporated
by reference in the Annual Information Form,
(ii) one copy of the comparative financial statements of
the Corporation for its most recently completed
financial year for which financial statements have
been filed together with the accompanying report of
the auditor and one copy of the most recent interim
financial statements of the Corporation that have
been filed, if any, for any period after the end of
its most recently completed financial year,
(iii) one copy of the information circular of the
Corporation in respect of its most recent annual
meeting of shareholders that involved the election of
directors,
(iv) one copy of any other documents that are incorporated
by reference into the preliminary short form
prospectus or the short form prospectus and are not
required to be provided under clauses (i), (ii) or
(iii); or
(b) at any other time, one copy of any documents referred to in
clauses (a)(i), (ii) and (iii), provided that the Corporation
may require the payment of a reasonable charge if the request
is made by a person or company who is not a security holder of
the Corporation.
Additional information including directors' and officers' remuneration and
indebtedness, principal holders of the Corporation's securities, options to
purchase securities and interests of insiders in material transactions, 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 for its most recently completed financial year.
-35-
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;
"CHEVRONTEXACO" 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 to be constructed 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 26, 2004 evaluating the
reserves attributable to Western as of December 31, 2003;
"HMU" The hydrogen manufacturing unit which will supply 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;
"MM$" Millions of dollars and "M$" thousands of dollars;
"MMBBLS" Millions of barrels;
-36-
"MINE" The open pit mine to be constructed 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 Mine Services Inc., 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" Senior secured notes of Western 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, ChevronTexaco, 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 will
process 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 and all renewals, extensions, replacements and amendments in respect
of same, granted to Shell by the Government of Alberta.
APPENDIX A
REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR
To the board of directors of Western Oil Sands Inc. (the "Corporation"):
1. We have prepared an evaluation of the Corporation's reserves data as at
December 31, 2003. The reserves data consist of the following:
(a) (i) proved and proved plus probable oil and gas reserves
estimated as at December 31, 2003, 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, 2003, 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, 2003, and
identifies the respective portions thereof that we have audited,
evaluated and reviewed and reported on to the Corporation's board of
directors:
Location of
Reserves
Description and (Country or Net Present Value of Future Net Revenue
Preparation Date of Foreign (before income taxes, 10% discount rate)
Evaluation Geographic -------------------------------------------------------
Report Area) AUDITED EVALUATED REVIEWED TOTAL
----------- ----------- ------- --------- -------- -----
March 23, 2004 Canada 0 1,604.8 MM$ 0 1,604.8 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 this evaluation for events and
circumstances occurring after the preparation dates.
-2-
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., Dated March 26, 2004
Calgary, Alberta, Canada --------------
ORIGINALLY SIGNED BY
- --------------------
James H. Willmon, P. Eng.
Vice-President
APPENDIX B
REPORT OF MANAGEMENT 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, 2003 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, 2003 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.
-2-
Because the reserves data are based on judgements regarding future events,
actual results will vary and the variations may be material.
(signed) Guy J. Turcotte, President and Chief Executive Officer
(signed) John Frangos, Executive Vice President and Chief Operating Officer
(signed)Robert G. Puchniak,, Director
(signed) Mac H. Van Wielingen, Director
April 27, 2004