EX-99 2 ex1form40f_2004.txt EXHIBIT 1 ================================================================================ [OBJECT OMITTED] [LOGO-WESTERN OIL SANDS] ANNUAL INFORMATION FORM March 30, 2005 ================================================================================
TABLE OF CONTENTS Page INTRODUCTORY INFORMATION.........................................................................................i FORWARD LOOKING INFORMATION......................................................................................i CORPORATE STRUCTURE..............................................................................................1 GENERAL DEVELOPMENT OF THE BUSINESS..............................................................................1 Operating Activities....................................................................................2 NARRATIVE DESCRIPTION OF THE BUSINESS............................................................................4 Project Overview........................................................................................4 Resource Base...........................................................................................5 Third Party Facilities..................................................................................6 Marketing and Sales.....................................................................................6 Regulatory Approvals....................................................................................7 Insurance...............................................................................................7 Proposed Expansions and Feasibility Study Agreement.....................................................8 Reserves Data...........................................................................................9 Other Oil and Gas Information..........................................................................13 Land Tenure............................................................................................15 Royalties..............................................................................................15 Environmental Considerations...........................................................................16 Joint Venture Agreement................................................................................16 DIVIDEND POLICY.................................................................................................18 DESCRIPTION OF SHARE CAPITAL....................................................................................18 MARKET FOR SECURITIES...........................................................................................20 RATINGS ........................................................................................................20 DIRECTORS AND OFFICERS..........................................................................................21 AUDIT COMMITTEE.................................................................................................24 RISKS AND UNCERTAINTIES.........................................................................................26 TRANSFER AGENTS AND REGISTRAR...................................................................................35 INTEREST OF EXPERTS.............................................................................................35 ADDITIONAL INFORMATION..........................................................................................35 GLOSSARY .......................................................................................................36 APPENDIX A - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR APPENDIX B - REPORT OF MANAGEMENT ON RESERVES DATA AND OTHER INFORMATION APPENDIX C - AUDIT COMMITTEE CHARTER
INTRODUCTORY INFORMATION References in this Annual Information Form to Western Oil Sands Inc. ("Western" or the "Corporation") includes Western and its material wholly-owned subsidiaries, 852006 Alberta Ltd. Western Oil Sands Finance Inc., and Western Oil Sands L.P., unless the context otherwise requires. INITIALLY CAPITALIZED TERMS USED HEREIN AND NOT OTHERWISE DEFINED HAVE THE MEANINGS ASCRIBED THERETO IN THE GLOSSARY. Unless otherwise indicated, all financial information included and incorporated by reference in this Annual Information Form is determined using Canadian generally accepted accounting principles ("Canadian GAAP''), which differs from generally accepted accounting principles in the United States ("U.S. GAAP''). The notes to Western's audited consolidated financial statements contain a discussion of the principal differences between Western's financial results calculated under Canadian GAAP and under U.S. GAAP. UNLESS OTHERWISE SPECIFIED, ALL DOLLAR AMOUNTS ARE EXPRESSED IN CANADIAN DOLLARS, ALL REFERENCES TO "DOLLARS'' OR "$'' ARE TO CANADIAN DOLLARS AND ALL REFERENCES TO "US$'' ARE TO UNITED STATES DOLLARS. FORWARD LOOKING INFORMATION This Annual Information Form contains certain forward-looking statements relating but not limited to Western's operations, anticipated financial performance, business prospects and strategies. Forward-looking information typically contains statements with words such as "anticipate", "estimate", "expect", "potential", "could" or similar words suggesting future outcomes. Readers are cautioned to not place undue reliance on forward-looking information because it is possible that predictions, forecasts, projections and other forms of forward-looking information will not be achieved by Western. By its nature, forward-looking information involves numerous assumptions, inherent risks and uncertainties. A change in any one of these factors could cause actual events or results to differ materially from those projected in the forward-looking information. These factors include, but are not limited to, the following: market conditions, law or government policy, operating conditions and costs, project schedules, operating performance, demand for oil, gas and related products, price and exchange rate fluctuations, commercial negotiations or other technical and economic factors. For additional information relating to risk factors please refer to "Risks and Uncertainties". -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 the following material wholly-owned subsidiaries; 852006 Alberta Ltd. (which together with Western holds a 20% undivided interest in the Project) and Western Oil Sands Finance Inc., as shown below: [GRAPPHIC OMITTED] Western's head office is located at 2400 Ernst & Young Tower, 440 - Second Avenue S.W., Calgary, Alberta T2P 5E9 and its registered office is located at Suite 3700, 400 Third Avenue S.W., Calgary, Alberta T2P 4H2. GENERAL DEVELOPMENT OF THE BUSINESS Western is a Canadian oil sands corporation that holds a 20 percent undivided ownership interest in a multibillion dollar Joint Venture that is exploiting the recoverable bitumen reserves and resources found in certain oil sands deposits located in the Athabasca region of Alberta. Shell and Chevron hold the remaining 60 percent and 20 percent undivided ownership interest in the Joint Venture, respectively. The Project, which includes facilities owned by the Joint Venture and third parties, uses established processes to mine oil sands deposits, extract and upgrade the bitumen into synthetic crude oil and vacuum gas oil, or VGO. Western is also actively pursuing other oil sands and related business opportunities. -2- OPERATING ACTIVITIES The Project achieved a major milestone on December 29, 2002 with first bitumen production at the Mine. Deliveries of diluted bitumen into the dedicated Corridor pipeline system for delivery to the Upgrader located at Scotford, Alberta commenced before the end of 2002. At the Upgrader, the primary distillation units were successfully tested during the fourth quarter of 2002 and commissioning and testing of the synthetic crude units was well underway at the end of 2002. Activities leading up to this point were financed through a series of offerings by the Corporation of a combination of debt and equity and available credit pursuant to the Corporation's credit facilities. Prior to 2004, these offerings included: o A private placement offering of US$450 million senior secured Notes completed on April 23, 2002. The Notes bear interest at 8.375% per annum, payable on May 1 and November 1 of each year, beginning on November 1, 2002 and mature on May 1, 2012. Of the net proceeds from this offering, $508 million was used to repay the Senior Credit Facility and all amounts owed to Shell. The $535 million Senior Credit Facility was cancelled in conjunction with its repayment; o Concurrent with the completion of the offering of Notes, the Corporation entered into a senior credit facility with a syndicate of banks in the aggregate amount of $100 million comprised of a revolving $75 million debt service/completion facility to be used primarily to finance interest payable on the Notes with the surplus to be available to fund Project construction costs and a revolving $25 million facility for working capital purposes and for letter of credit requirements; o On November 19, 2002, the Corporation entered into a $50 million credit facility (the "Working Capital Facility") with a syndicate of Canadian chartered banks to fund the Corporation's working capital requirements. The Working Capital Facility was amended on January 30, 2003 to increase the maximum amount of such facility to $75 million and to add an additional Canadian chartered bank to the syndicate of lenders. This was further amended on May 1, 2003 to increase the maximum amount of such facility to $110 million; o A public offering of Common Shares at $24.50 per share for gross proceeds of $50.225 million completed on February 7, 2003; o On October 16, 2003, the Corporation entered into a $240 million credit facility (the "Revolving Credit Facility") with a syndicate of Canadian chartered banks. This facility replaced the Working Capital Facility and the proceeds were used to repay amounts outstanding under a bridge facility entered into in October 2001, the Working Capital Facility and to provide for working capital during operations. On January 6, 2003, a fire occurred in the froth cleaning circuit at the Mine resulting in limited damage, primarily to electrical cables, instrumentation and insulation in the solvent recovery area of the froth treatment plant. However, severe weather conditions caused broader freeze damage and impeded progress in making repairs. Repairs were completed in an expedited manner. Start-up recommenced on April 4, and the Project achieved fully integrated operations between the Mine and the Scotford Upgrader on April 19, 2003. On June 1, 2003, Western commenced commercial operations as all aspects of the facilities became fully operational and the Project achieved 50 percent of the stated design capacity of 155,000 barrels per day. Since the commencement of commercial production, ramp-up continued uninterrupted for 2003, with production increases each quarter. The Mine achieved a ramp up approaching design levels by -3- year-end, averaging 138,000 barrels per day in December 2003, resulting in an average 118,000 barrels per day in 2003. By the end of 2003, nine months after start-up, the Project was operating at 89 percent of design capacity. Fiscal 2004 represented the first complete year of commercial operations for the Project. The Project continued to ramp-up production at times achieving levels that met or exceeded design capacities. A few noteworthy milestones in 2004 include: o record monthly production in August 2004 averaging 182,000 barrels per day of bitumen; o record daily production of approximately 197,000 barrels of bitumen in August 2004; and o 40 days over 155,000 barrels of bitumen during the third quarter of 2004. These milestones evidence the ability of the Project to extract, transport and process significant volumes of bitumen. However, the Project is complex and can, from time to time, experience unforeseen operational issues requiring immediate attention and repair. During the course of 2004, two such unplanned operational events occurred. At the Mine site, the froth settlers for Train 2 malfunctioned in July 2004 and repairs were required to bring them to design specifications. Similar repairs were conducted on the froth settlers for Train 1. The froth settlers form part of the froth treatment process which combines the rich bitumen froth from storage tanks with a solvent to separate out the remaining solids, water and heavy asphaltenes. The end result of this process is clean diluted bitumen. With the froth settlers not operating to specifications, the recovery factor of clean bitumen was reduced. Under normal operating conditions, this circuit recovers approximately 99% of the bitumen. As a result of this malfunction, a lower grade of bitumen was transported to the Upgrader resulting in operational challenges, as optimal Upgrader performance requires a consistent supply of high grade quality of bitumen. As operations were brought to full capacity at both the Mine and Upgrader upon completion of these repairs, additional operational issues surfaced at the Upgrader. The extent of this unforeseen event and the associated events that followed resulted in fourth quarter production far below the Corporation's expectations. Though disappointed in the results of the fourth quarter, steps were taken to avoid a recurrence of these events in the future. Important information was obtained which will only serve to promote further production reliability. These events, together with other minor operational issues associated with a start-up, have been systematically addressed and resolved in order of priority. Full production at both the Mine and Upgrader re-commenced on January 30, 2005. The Project's average daily production of dry bitumen for 2004 was 135,542 barrels per day, or 87% of design rate. Up to the beginning of the fourth quarter, the Project delivered sequential gains in production and sequential reductions in per barrel unit operating costs. For the nine months ended September 30, 2004, production was 144,135 barrels per day (28,827 barrels net to Western) with an operating cost of $19.32 per processed barrel. Operating costs for the duration of 2004 escalated to $21.17 per processed barrel due to operating costs of $28.22 per processed barrel in the fourth quarter. Repairs associated with the unplanned maintenance are expensed as incurred as opposed to capitalized on the balance sheet . The necessity for additional financing during fiscal 2004 substantially diminished as the Project reached a certain level of production reliability, in turn providing a relatively stable cash flow. Financing and credit activities were limited to the following: o A $68 million bought-deal equity offering consisting of 2,000,000 Common Shares at a price of $34.00 per share completed on April 8, 2004; o During March 2005, Western successfully refinanced its $100 million senior facility by the assumption of this full amount into Western's Revolving Credit Facility, thereby increasing the Revolving Credit Facility to $340 million. The additional $100 million will be subject to the same terms and conditions as those contained in the Revolving Credit Facility; and -4- o Repayment of $63 million in credit facilities during the course of fiscal 2004. Operations during the fourth quarter of 2004 impeded the ability to reduce the banking facilities further. The Project has also initiated a three year de-bottlenecking program. Once completed, production volumes are expected to increase to between 180,000 and 200,000 barrels per day by the end of fiscal 2007. The Project participants are also looking at initiatives that will enable the processing of the heavier crude streams into lighter, higher volume crude blend components. De-bottlenecking, as well as these other initiatives, does not require significant amounts of capital to complete. Therefore, substantial additional volumes can be achieved with minor capital investment. Plans were also announced on September 21, 2004 to expand the Mine such that an additional 90,000 to 100,000 barrels of bitumen per day can be processed bringing total dry bitumen production to between 270,000 to 300,000 barrels per day. Total project costs are estimated at $4 to $4.5 billion (approximately $800 to 900 million, net to Western). Based on an expanded mining plan, capital would be deployed to purchase mining equipment to recover resources from additional areas located on Lease 13 and from Lease 90, an additional train for bitumen extraction and froth treatment processing and to construct a third hydro-conversion unit and associated utilities at the Scotford Upgrader. Western announced on April 23, 2004 that both provincial and federal government cabinet approvals were received by the Joint Venture for the first phase of the Jackpine Mine in the Athabasca oil sands region of northern Alberta. It is forecasted that this expansion project will add an additional 200,000 barrels of bitumen per day by 2013. NARRATIVE DESCRIPTION OF THE BUSINESS Western is a Canadian oil sands corporation that holds a 20 percent undivided ownership interest in a multibillion dollar Joint Venture to exploit the recoverable bitumen resources found in certain oil sands deposits located on the western portion of Lease 13. Lease 13 is located in northern Alberta approximately 70 km north of Fort McMurray, Alberta, abutting the Athabasca River and the integrated Upgrader is situated near Shell's existing refinery near Fort Saskatchewan, Alberta. Shell and Chevron hold the remaining 60 percent and 20 percent undivided ownership interest in the Joint Venture, respectively. The Project, which includes facilities owned by the Joint Venture and third parties, uses established processes to mine oil sands deposits, extract and upgrade the bitumen into synthetic crude oil and vacuum gas oil, or VGO. Western is also actively pursuing other oil sands and related business opportunities. Construction of the Mine and Upgrader was completed in December 2002, at a total capital cost of $5.7 billion ($1.14 billion to Western's account). Production of bitumen commenced at the Mine in January 2003, reaching commercial levels in June 2003. Ramp up of production at the Project has continued, with average production during 2004 of approximately 135,542 barrels per day (87 percent of design capacity). The focus of the Project during 2005 is to improve on the reliability and efficiency of the operations by ensuring certain de-bottlenecking initiatives are seen to fruition and constant project management. Western provides certain management services including the full and part time services of certain of its employees to Albian. As at December 31, 2004, Western had 31 employees. Since completion of construction in December 2002, Western's main role is to provide operating expertise for the Mine. PROJECT OVERVIEW The Project is designed to produce high quality bitumen by surface mining certain Athabasca oil sands deposits and upgrading the extracted bitumen into custom blended petroleum products for sale to conventional refineries where it is used to produce petroleum products. Approximately 275,000 tonnes per day of ore, in addition to approximately 155,000 tonnes per day of overburden, low grade (waste) oil -5- sand and extraction plant rejects can be mined from the Mine. Approximately 155,000 barrels per day of bitumen is extracted from this ore in the Extraction Plant and with the addition of non-bitumen feedstocks approximately 190,000 barrels per day of refinery feedstocks and synthetic crude oil blends can be produced by the Upgrader. The Project is an integrated oil sands development pursuant to which: o Oil sands deposits are mined using open pit techniques at the Mine located on the western portion of Lease 13, which is a truck and shovel mine operation; o Raw bitumen is extracted from the oil sands through processes powered by electrical and thermal energy at the Extraction Plant that is located on the western portion of Lease 13. The extraction process consists of primary extraction and froth treatment stages; o Once extracted, the raw bitumen feedstock is transported from the Mine through a dual pipeline system to the Scotford Upgrader located near Fort Saskatchewan, Alberta where it is upgraded into refinery feedstocks; o Upgrading is the final stage of the production process. The bitumen feedstock is distilled to recover diluent, then undergoes a hydro-conversion process with integrated hydro-treating to generate suitable product streams; and o After the bitumen has been upgraded, it is sold as refinery feedstock to North American refineries and to the Scotford Refinery, which is adjacent to the Scotford Upgrader, for further processing. A dual pipeline system connects the Scotford Upgrader to certain third party pipelines in Edmonton, Alberta. RESOURCE BASE Lease 13 lies within the mineable oil sands area of the Athabasca deposits. The 49,872 acres of Lease 13 are estimated by Western to contain 4.8 billion bbls of in-place mineable bitumen resources at an average grade of 11.6% bitumen and a strip ratio of less than 1.5:1. Norwest has verified these estimates in the Norwest Report. The Mine covers a 121 square kilometre portion of the western portion of Lease 13. According to GLJ, the western portion of Lease 13 contains approximately 1.0 billion bbls of proved and 0.6 billion bbls of probable reserves. Based on the Project's design capacity, the Mine's total reserves, both proved and probable, has a reserve life index of 27 years. This has been verified by Norwest in the Norwest Report based on consideration of the geology of the mine plan area, integrity of the exploration data base, the model used to represent the geology of the mine plan area and the model used to estimate ore characteristics. Norwest also considered specific geology-related risks. The current mine reserve is one of the six potentially mineable ore deposits that have been identified on Lease 13 and Shell's Other Athabasca Leases. Western is entitled to participate in all future expansions on Lease 13 and in the other oil sands opportunities with Shell and Chevron in respect of Shell's Other Athabasca Leases, and within a defined area of mutual interest. The following table outlines the Joint Venture's proved and probable reserves on the western portion of Lease 13, as estimated by GLJ, and the resources available for future expansion opportunities on the remainder of Lease 13 and Leases 88 and 89, as verified by Norwest. It also includes resources estimated on Lease 9 which was recently acquired by Shell from EnCana Corporation ("EnCana"): -6- Western's Total Share (MMbbls) (MMbbls) -------- -------- Joint Venture Reserves on western portion of Lease 13.............. 1,586 317 Future Opportunities Resources on remainder of Lease 13................... 3,200 640 Resources on Leases 88 and 89........................ 3,900 780 Resources on Lease 9 1,000 200 8,100 1,620 Lease 17 which was also acquired by Shell from EnCana has not been evaluated. Hence, no statement is made with respect to its potential. The Joint Venture intends to evaluate this lease during the course of 2005. THIRD PARTY FACILITIES The Owners have entered into various contracts with certain third parties to construct, own and operate certain additional facilities required by the Project. Terasen Pipelines (Corridor) Inc. ("Terasen"), a subsidiary of Terasen Inc., constructed and owns the dual pipeline systems that connect the Mine to the Scotford Upgrader and the Scotford Upgrader to certain third party pipelines. Terasen operates this system directly. The Owners are severally responsible for the costs of transportation on the pipeline systems, which is on a take or pay basis. ATCO built, owns and operates the cogeneration facility located on Lease 13 which provides power and steam for the Mine and Extraction Plant. ATCO also owns and operates the cogeneration facility constructed to provide electrical power to the Upgrader. The Owners are obligated to purchase power from ATCO under long-term contracts. ATCO has the ability to sell any excess power generated by the cogeneration facilities to the commercial power market. MARKETING AND SALES Shell Canada Products Limited takes delivery of vacuum gas oil at the Scotford Refinery, representing approximately one-third of the total Upgrader production, pursuant to a long-term sales arrangement. Western sells approximately 12,000 barrels per day of vacuum gas oil to Shell Canada Products Limited under this arrangement representing its 20% share of such total sales. The remaining production from the Upgrader and any third party feedstocks currently form the basis of two streams of synthetic crude oil (one heavy and one light), and are anticipated to form a single stream blend concurrent with the first expansion of the Mine, totalling approximately 130,000 barrels per day (26,000 barrels per day to Western). This production is taken in kind and marketed by each Owner to numerous refineries throughout North America. The Scotford Upgrader is located at the hub of the western Canadian refining industry near Edmonton, Alberta, providing the Owners with access to a number of pipeline systems, to which the Corridor pipeline system is connected. Provisions for pipeline deliveries have been established through most major crude oil trunkline systems. As a result, Western is able to sell all of its production volumes into the traditional North American markets. Market acceptance of Western's two streams of synthetic crude oil continues to be high, with these products consistently meeting or exceeding customer expectations. While Western's upgrading provides synthetic crude oil with superior qualities for processing, Western's products also lend themselves to blending and customizing and this flexibility may lead to significant improvements in refinery efficiencies for Western's customers. A dedicated pipeline to the Edmonton terminals has ensured the -7- integrity of Western's product and in order to maintain this quality, Western's products are shipped in segregated streams. REGULATORY APPROVALS The Project has all of the material regulatory approvals and permits that it requires for the operation of the Project. On April 23, 2004, Western announced that the Joint Venture received both provincial and federal government cabinet approval for the first phase of its Jackpine Mine. Phase 1 includes a mining and extraction facility on the eastern portion of Lease 13 with a planned capacity of approximately 200,000 barrels per day of bitumen. INSURANCE The Owners obtained insurance to protect against certain risks of loss during the construction of the Mine, Extraction Plant and the Upgrader. The insurance is typical for a project of the nature of the Project. In addition, Western obtained, for its own account, a $200 million insurance policy which, throughout the period March 2000 through April 2004, covered certain costs, expenses and losses of revenue including: (i) costs and expenses or loss of revenues arising from a delay in achieving the guaranteed production levels as set out in the feasibility study; (ii) costs and expenses incurred in connection with the modification, repair or replacement of equipment or material, which are directly related to achieving the guaranteed production levels; (iii) escalation in Project costs beyond the budgeted Project costs, which are directly related to achieving the guaranteed production levels; and (iv) debt service costs related to obligations incurred to finance any of (i), (ii) or (iii). Arbitration proceedings under the terms of Western's cost overrun and project delay insurance policy have been initiated to resolve the disputes with insurers surrounding the claims for payment pursuant to this policy. Western has filed insurance claims for the full limit of the policy, being $200 million, and will also be seeking interest and punitive and aggravated damages. The arbitration panel has now been constituted and Western anticipates hearings to commence in the fall of 2005. The arbitration involves a number of insurers. Certain insurers have notified Western that they intend to commence distinct arbitration proceedings on coverage or jurisdiction issues which they believe are unique to them. Western will seek to consolidate these into a single arbitration proceeding. In order to preserve Western's rights with regard to the cost overrun and project delay insurance claim, Western has also filed, but not served, a Statement of Claim in the Court of Queen's Bench of Alberta which includes claims for aggravated and punitive damages totaling $650 million. In addition, insurers involved in the dispute with Western have withheld insurance proceeds payable to Western for damages related to the January 2003 fire and related freezing damage. With the exception of the amounts withheld, these claims have now been resolved. Shell continues to pursue claims on behalf of the Joint Venture for lost profits resulting from production delays caused by the fire. To date, Western has received $16.1 million from insurers in respect of claims relating to the fire and freeze damage. Western's current insurance is designed to protect its ownership interest against losses or damage to the Mine, Extraction Plant and Upgrader, to preserve its operating income and to protect against its risk of loss to third parties. Western also renewed its U.S. $500 million of property and business interruption insurance and U.S. $100 million of general liability insurance. -8- PROPOSED EXPANSIONS AND FEASIBILITY STUDY AGREEMENT Western intends to expand its production basis through the development of certain long-term development opportunities relating to the resources contained within Lease 13 and on Shell's Other Athabasca Leases. These opportunities include: o optimization and expansion of the western portion of Lease 13 and development of Lease 90, which is one of Shell's Other Athabasca Leases, to increase total bitumen production from the current design of 155,000 barrels per day to 245,000 barrels per day. This development would likely be complete before 2010; o development of a new mine and extraction facility, known as the Jackpine Mine, Phase One, to be located on the eastern portion of Lease 13 with a capacity of 200,000 barrels per day of bitumen production. The development of this new mine is covered by recent regulatory approvals from the provincial and federal governments; o development of additional resources located on Leases 88 and 89, known as the Jackpine Mine, Phase Two, with a capacity of approximately 100,000 barrels per day of bitumen production. This development requires additional regulatory approval; and o development of additional resources on Lease 9 which has recently been acquired from EnCana. It is estimated that Lease 9 could result in an additional 200 million barrels net to Western. The Project also acquired Lease 17 from EnCana but this parcel has not yet been evaluated. The Owners are evaluating other de-bottlenecking and expansion scenarios on an ongoing basis which may alter the volumes and time frames for these opportunities. One such scenario now in the planning stage involves continuing with the de-bottlenecking program as originally contemplated, but undertaking the expansions that follow, one train at a time. This would involve an initial expansion on the east side of Lease 13 on the Jackpine lease with output at 90,000 to 100,000 barrels per day followed by three identical trains back-to-back using a program of continuous expansion over approximately 10 years, commencing in 2006. Total production is expected to reach 500,000 to 600,000 barrels per day and will come from Leases 13, 88, 89 and 90. Each of these expansions will be completed with matching upgrading trains adjacent to the existing plant at Scotford. Western, Shell and Chevron entered into a pre-feasibility study agreement in respect of the development of the Jackpine Mine, Phase One. The objective of the agreement was to obtain primary regulatory approvals, licenses, permits and authorizations for the construction of the Jackpine Mine, Phase One mine and extraction plant and may also in certain circumstances incorporate the resources for Leases 88, 89 and/or Lease 90. The pre-feasibility phase has now been completed and the Owners are now progressing through the feasibility study which is expected to be completed in mid 2006. The scope of the feasibility study is much more involved and includes such analysis as the location and size of the mine, the nature, location and extent of the mine facilities, the upgrader facilities and the third party facilities, a plan for the construction of these additional facilities in addition to numerous other activities. The feasibility study will also more narrowly define the capital costs associated with the expansion initiatives to an estimate within +/- 10%. The interests of the parties to this agreement are the same as in the Joint Venture Agreement; however, the terms of the Joint Venture Agreement do not govern this undertaking. This feasibility study agreement does not add to nor detract from any of Western's rights under the Joint Venture Agreement. The overall management has been delegated to the Executive Committee of the Joint Venture, which delegates certain matters to the project administrator. Western may withdraw from the feasibility study agreement at any time, however, Western may be reinstated by paying twice the costs it would have otherwise been required to pay to preserve its rights to participate in a feasibility study and expansion pursuant to the Joint Venture Agreement. -9- The Owners received approval from the joint review panel of the Alberta Energy and Utilities Board and the federal government for the Jackpine Mine, Phase One development of the eastern portion of Lease 13. The application is subject to certain conditions and has been approved by the Cabinets of both the provincial and federal governments. Since these approvals have been received, the Owners are now advancing a different scenario as outlined above, and will file an amendment to the Jackpine permit in early 2005 which will include revision to the existing Mine permit to accommodate the de-bottlenecking volumes. The timing and details of any expansion will be subject to the outcome of future evaluations of economics, market needs, regulatory requirements and sustainable development considerations. RESERVES DATA GLJ prepared the GLJ Report as at March 11, 2005 which evaluated the reserves attributable to Western as of December 31, 2004. The tables below summarize the upgraded bitumen reserves and the value of future net revenue attributable to Western's ownership as evaluated in the GLJ Report. All evaluations of future revenue are after the deduction of future income tax expenses, unless otherwise noted in the tables, royalties, development costs and production costs, but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenues contained in the following tables do not necessarily represent the fair market value of the Corporation's reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are included in the GLJ Report. The recovery and reserves estimates attributable to Western's ownership in the Project are estimates only. Actual reserves may be greater or less than those calculated. It is noted that the accuracy of any reserve estimate, especially when based on volumetric analysis, is a function of the quality of available data and of engineering interpretation and judgment. While reserve estimates presented herein are considered reasonable, performance subsequent to the date of the estimate may justify their revision, either upward or downward. The GLJ Report presents net revenue projections prepared for the reserves attributable to the ownership interest of Western along with a discussion of the evaluation. SUMMARY OF RESERVES AS AT DECEMBER 31, 2004
Constant Prices and Costs Forecast Prices and Costs ----------------------------------- ---------------------------------- Upgraded Bitumen Upgraded Bitumen ----------------------------------- ---------------------------------- Gross(1) Net(1) Gross(1) Net(1) (MMbbl) (MMbbl) (MMbbl) (MMbbl) ----------------- ----------------- ----------------- ---------------- Proved Developed Producing 199 197 199 179 Proved Developed Non-Producing 5 5 5 4 ----------------- ----------------- ----------------- ---------------- Total Proved 204 202 204 183 Total Probable 113 112 113 97 ----------------- ----------------- ----------------- ---------------- Total Proved Plus Probable 317 314 317 280
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Net Present Values of Future Net Revenue Based on Constant Prices and Costs Before Deducting Incomes Taxes After Deducting Income Taxes ---------------------------------------- ------------------------------------- Undiscounted Discounted at 10% Undiscounted Discounted at (MM$) (MM$) (MM$) (MM$) ------------------ -------------------- ------------------- ----------------- Proved Developed Producing 4,228 1,991 3,379 1,721 Proved Developed Non-Producing 172 167 111 111 ------------------ -------------------- ------------------- ----------------- Total Proved 4,400 2,159 3,490 1,832 Total Probable 3,045 672 2,026 452 ------------------ -------------------- ------------------- ----------------- Total Proved Plus Probable 7,445 2,831 5,516 2,285 ------------------ -------------------- ------------------- -----------------
The following tables present the estimated future net revenue attributable to Western, as set forth in the GLJ Report:
Total Future Net Revenue (Undiscounted) Based on Constant Prices and Costs Future Abandonment Future Net and Net Revenue Revenue Royalties Operating Development Reclamation Before Income After Revenue Royalties Costs Costs Costs Income Taxes Taxes Income Taxes (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) --------- --------- ----------- ------------- --------------- ------------- --------- ------------- Total Proved 7,981 25 3,164 393 - 4,399 909 3,490 --------- --------- ----------- ------------- --------------- ------------- --------- ------------- Total Proved Plus Probable 12,405 39 4,334 587 - 7,445 1,929 5,516 --------- --------- ----------- ------------- --------------- ------------- --------- -------------
FUTURE NET REVENUE BY PRODUCTION GROUP BASED ON CONSTANT PRICES AND COSTS The future net revenue before income taxes and discounted at 10% per year in respect of the total proved and total proved plus probable upgraded bitumen reserves attributable to Western's ownership interest in the Project as at December 31, 2004 are $2,159 million and $2,831 million, in each case based on constant prices and costs.
NET PRESENT VALUES OF FUTURE NET REVENUE BASED ON FORECAST PRICES AND COSTS Before Deducting Income Taxes After Deducting Income Taxes Discounted At Discounted At ------------------------------------------ ------------------------------------------ 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) Proved Developed Producing 3,194 2,203 1,641 1,298 1,073 2,672 1,924 1,485 1,206 1,018 Proved Developed Non-producing 138 148 125 97 73 111 114 95 73 55 ------- ------- -------- ------- ------- ------- ------- ------- ------- ------- Total Proved 3,332 2,351 1,766 1,395 1,146 2,783 2,038 1,579 1,280 1,073 Total Probable 2,563 1,138 565 315 197 1,705 761 383 219 141 ------- ------- -------- ------- ------- ------- ------- ------- ------- ------- Total Proved Plus Probable 5,895 3,489 2,331 1,710 1,343 4,488 2,799 1,962 1,499 1,214 ======= ======= ======== ======= ======= ======= ======= ======= ======= =======
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TOTAL FUTURE NET REVENUE (UNDISCOUNTED) BASED ON FORECAST PRICES AND COSTS Future Net Net Abandonment Revenue Revenue and Before After Operating Development Reclamation Income Income Income Revenue Royalties Costs Costs Costs Taxes Taxes Taxes (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) ----------- ----------- ----------- ----------- ------------ ----------- ----------- ----------- Total Proved 7,902 558 3,562 451 - 3,332 549 2,783 Total Proved Plus Probable 12,890 1,066 5,208 722 - 5,895 1,407 4,488
FUTURE NET REVENUE BY PRODUCTION GROUP BASED ON FORECAST PRICES AND COSTS The future net revenue before income taxes and discounted at 10% per year in respect of the total proved and total proved plus probable upgraded bitumen reserves attributable to Western's ownership interest in the Project as at December 31, 2004 are $1,766 million and $2,331 million, in each case based on forecast prices and costs. RECONCILIATION OF NET RESERVES BY PRINCIPAL PRODUCT TYPE BASED ON CONSTANT PRICES AND COSTS Fiscal 2004 represented a full fiscal year of production whereas fiscal 2003 consisted of seven months of commercial operations, commencing on June 1, 2003. The following table sets forth a reconciliation of the changes in Western's bitumen reserves as at December 31, 2004 against such reserves as at December 31, 2003 based on the constant price and cost assumptions set forth in Note 9 below:
Upgraded Bitumen -------------------------------------------------------- Net Probable Net Proved Plus Net Proved Probable Probable (MMbbl) (MMbbl) (MMbbl) -------------- ----------------- ------------------- At December 31, 2003 195 82 277 -------------- ----------------- ------------------- Extensions - - - Improved Recovery - - - Technical Revisions - 16 16 Discoveries - - - Acquisitions - - - Dispositions - - - Economic Factors 17 14 31 Production (10) - (10) -------------- ----------------- ------------------- At December 31, 2004 202 112 314
RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE NET REVENUE DISCOUNTED AT 10% BASED ON CONSTANT PRICES AND COSTS The following table sets forth changes between future net revenue estimates attributable to net proved reserves as at December 31, 2004 against such reserves as at December 31, 2003: -12-
2004 (MM$) --------------------- Estimated Future Net Revenue at December 31, 2003 1,429 --------------------- Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (105) Net Change in Prices, Production Costs and Royalties Related to Future Production 611 Changes in Previously Estimated Development Costs Incurred During the Period 46 Changes in Estimated Future Development Costs (161) Extensions and Improved Recovery - Discoveries - Acquisitions of Reserves - Dispositions of Reserves - Net Change Resulting from Revisions in Quantity Estimates - Accretion of Discount Pre Tax 143 Net Change in Income Taxes (131) Other changes, including Hedging - --------------------- Estimated Future Net Revenue at December 31, 2004 1,832 =====================
Notes: (1) Columns may not add due to rounding. (2) Reserve definitions consistent with National Instrument 51-101 have been used in the GLJ Report, where: "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. The targeted level of certainty under a specific set of economic conditions is at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves "Proved Plus Probable" reserves include those additional reserves that are less certain to be recovered than proved reserves. The targeted level of certainty under a specific set of economic conditions is at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. (3) All of the Project reserves are classified as "developed". The proved non-producing reserves relate to recovery factor and capacity improvements associated with de-bottlenecking capital investments. Although the capital is significant relative to the cost of drilling a well, classifying the nonproducing reserves as undeveloped is not considered appropriate for this mining project. (4) Reserves have not been attributed to Western for the bitumen deposits present in the eastern portion of Lease 13 or Leases 88 and 89. Western does not does not currently hold a working interest position in these expansion opportunities. In addition, no reserves have been attributed to Leases 90, 9 and 17. (5) Oil volumes correspond to upgraded bitumen on the basis of 1.03 bbls/bbl of undiluted bitumen. Production from the Upgrader includes volumes attributable to off-lease feedstock purchases that cannot be booked as Project reserves. (6) The oil price forecasts reflect total revenues associated with the output from the Upgrader less the purchase costs associated with feedstock. Changes to the product mix and associated feedstock composition will occur relative to what they have been. In the constant price case, GLJ estimates the oil pricing to be the December 31, 2004 Edmonton Par less $8.10/bbl in 2005 and $7.65/bbl thereafter, reflecting the average December 2004 offset to Edmonton Par for each feedstock product and marketable product stream, and Western's budgeted compositions of feedstock and sales. In the forecast price case, GLJ estimates the oil pricing to be Edmonton Par less $5.50/bbl in 2005, $5.00/bbl in 2006 and $4.00/bbl thereafter. (7) Bitumen production has been forecast by GLJ to be 150,000 barrels per day in 2005 in the proved category growing to 175,000 barrels per day by 2008 in the total proved category. In the proved plus probable case, production is forecast to grow from a rate of 155,000 barrels per day in 2005 to an average rate of 190,000 barrels per day by 2009. The incremental probable reserves reflect the current mine plan as well as improved extraction recovery relative to the proved category. (8) Royalties are paid at the Mine boundary using a deemed bitumen revenue. For purposes of this evaluation, GLJ has added $0.50/bbl to GLJ's price for 12 degree heavy oil at Hardisty to reflect historic royalties calculations. The capital expense base incurred at December 31, 2004 is estimated at $2,600 million. (9) The constant price reflects December 31, 2004 prices of $46.54/bbl Edmonton Par oil, $25.92/bbl Bow River Blend at Hardisty, $6.54/MMBTU gas and zero inflation. In the forecast price assumptions, the following GLJ price forecast was used: -13-
Project Exchange WTI Crude Oil at Light, Sweet Crude Oil at Heavy Crude Oil Alberta Plant Year Inflation Rate Cushing Oklahoma Edmonton (40 API, 0.3% S) (12 API) at Hardisty Spot Gas (%) ($US/$Cdn) ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($/MMBTU) --------------------------------------------------------------------------------------------------------------------- 2005 2.0 0.82 42.00 50.25 27.50 6.35 2006 2.0 0.82 40.00 47.75 28.50 6.10 2007 2.0 0.82 38.00 45.50 28.75 5.90 2008 2.0 0.82 36.00 43.25 27.25 5.75 2009 2.0 0.82 34.00 40.75 25.50 5.75 2010 2.0 0.82 33.00 39.50 24.75 5.75 2011 2.0 0.82 33.00 39.50 24.75 5.75 2012 2.0 0.82 33.00 39.50 24.75 5.75 2013 2.0 0.82 33.50 40.00 24.75 5.85 2014 2.0 0.82 34.00 40.75 25.50 5.95 2015 2.0 0.82 34.50 41.25 25.75 6.05 2016+ 2.0 0.82 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Western's weighted average historical realized price for 2004 was $34.60 per synthetic barrel sold , $44.52 per synthetic barrel sold excluding the effects of hedging activities. FUTURE DEVELOPMENT COSTS The following table sets forth the future development costs associated with the development of Western's reserves as set forth in the GLJ Report.
Total Proved Total Proved Total Proved Plus Estimated Using Estimated Using Probable Estimated Constant Prices and Forecast Prices and Using Forecast Costs Costs Prices and Costs (MM$) (MM$) (MM$) ------------------- ------------------- -------------- 2005 97.4 100.1 103.4 2006 46.4 48.9 55.9 2007 37.6 40.6 59.4 2008 19.2 21.3 28.3 2009 19.2 21.9 23.7 ------------------- ------------------- -------------- Total for all years undiscounted 392.6 450.9 721.8 ------------------- ------------------- -------------- Total for all years discounted at 10%/year 261.0 289.1 367.7 =================== =================== ==============
Western intends to finance these development costs through a combination of free cash-flow from operations together with existing banking facilities. To the extent that bank facilities increase, costs associated with this borrowing would likely be done at similar rates that have been incurred in the prior years. OTHER OIL AND GAS INFORMATION COSTS INCURRED The following table sets forth costs incurred by Western in respect of the Project for the year ended December 31, 2004:
Property Acquisition Costs Exploration Costs Development Costs (MM$) (MM$) (MM$) ----------------------------------------------------------------------------------------------------------------- Proved Properties Unproved Properties -------------------- ------------------- Nil Nil $38.0 $46.3
-14- PROPERTIES WITH NO ATTRIBUTED RESERVES During 2004, Shell purchased Lease 9 and 17 from EnCana. Pursuant to the Joint Venture Agreement, Western has the right to participate to its 20% Project interest in these additional leases. The following table summarizes the gross and net area associated with each of these Leases together with existing leases. Gross Area Net Area to Western (hectares) (hectares) ---------------------------- ---------------------------- Lease 88 11,375 2,275 Lease 89 5,975 1,195 Lease 90 1,166 233 Lease 9 6,028 1,206 Lease 17 8,704 1,741 FORWARD CONTRACTS Western has entered into various commodity pricing agreements designed to mitigate the exposure to the volatility of crude oil prices in U.S. dollars. As at January 1, 2005, the following transactions are in place:
Notional Volume Hedge Period Average Price Received ------------------------------------------------------------------------------- WTI Swaps 14,000 bbls/d January to March 2005 U.S. $26.06 WTI Swaps 7,000 bbls/d April to December 2005 U.S. $26.87
GLJ has not included any effects of hedging activities in the GLJ Report. ABANDONMENT AND RECLAMATION COSTS Western has abandonment and reclamation liabilities relating to the Mine, Upgrader and related facilities. Western estimates the abandonment liability, net of salvage, for these assets with consideration given to the expected cost to abandon and reclaim the lands and facilities. These estimates are based on prevailing industry conditions, regulatory requirements and past experience. The value is determined by Western -15- TAX HORIZON Western is currently not required to pay cash income taxes. Western estimates that cash income taxes will become payable within six to eight years, depending on commodity prices, foreign exchange rates, operating costs, interest rates, future annual taxable income levels, expansions of the Project and other business activities. Changes in these factors from estimates used by Western could result in Western paying income taxes earlier or later than expected. PRODUCTION ESTIMATES Western estimates that its production of synthetic crude oil will be between 11 MMbls and 13 MMbls for 2005. Production from the Project accounts for 100% of Western's estimated production in 2005. PRODUCTION HISTORY The following table sets forth certain information in respect of production, product prices received, royalties, production costs and netbacks received by the Corporation for its synthetic crude oil for each quarter of its most recently completed financial year: Three Months Ended March 31, 2004 June 30, 2004 September 30, 2004 December 31, 2004 first estimating the anticipated timing and amount of net cash outflows using third party costs for future dismantlement and site restoration. These future payments are then present valued using a credit adjusted risk free rate appropriate for Western. The liability is estimated in the period in which the liability is incurred. These estimates are prepared annually and adjustments are made quarterly for material changes in the amount of the liability or the timing of abandonment. Where material differences are identified, adjustments to the liabilities or accretion expense are made on a prospective basis. Western's share of the present value of abandonment and reclamation costs that require recognition in its financial statements at December 31, 2004 is $8.0 million ($192.5 million undiscounted). These liabilities relate to Western's 20% working interest in the Project's future dismantlement costs and site restoration costs for the Mine, Upgrader and related facilities. GLJ has not included any abandonment and reclamation costs in the GLJ Report. Western does not anticipate any material expenditures relating to abandonment and reclamation during the next three years as the current mine plan contemplates development over 30 years.
Three Monts Ended --------------------------------------------------------------------------- March 31, 2004 June 30, 2004 September 30, 2004 December 31, 2004 -------------- ------------- ------------------ ----------------- Average Daily Production (kbpd) 27,197 28,400 30,862 21,990 Average Net Prices Received ($Cdn/bbl) 34.61 36.07 38.63 27.33 Royalties ($000s) 680 768 1,019 486 Operating Expenses ($000s) 51,825 52,828 50,766 57,574 Feedstocks ($000s) 29,701 23,926 47,339 36,844 Netback Received ($Cdn/bbl) 12.33 15.30 18.34 (8.58)
Notes: (1) Netback is calculated as oil sands revenue less royalties, operating expenses and feedstocks on a per barrel of production basis. LAND TENURE Oil produced from oil sands is produced under Crown Oil Sands Leases granted by the Province of Alberta. Such Crown Oil Sands Leases have an initial term of 15 years, and may be continued thereafter under the Oil Sands Tenure Regulation (Alberta) to the extent that the lessee has attained the required minimum level of evaluation of the oil sands in the leases or the leases are producing. Lease 13 has been continued under such regulation. The real property related to the pipelines, the Upgrader and the cogeneration facilities fall into two basic categories of ownership: (i) a number of locations, including some pumping/compressor stations, are owned in fee simple; and (ii) the majority of locations are covered by leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the land to be used in such a manner. ROYALTIES An initial royalty of 1% of the gross revenue on the bitumen produced is paid until the Owners have recovered 100% of the capital costs associated with the Mine and Extraction Plant, including a return on capital. Such return is based on the monthly Canadian federal long-term bond rate. Subsequent thereto, the royalty will be the greater of 1% of the gross revenue on the bitumen produced and 25% of net -16- bitumen revenue. Gross revenue is calculated based on the fair market value of the bitumen prior to upgrading. Net revenue is determined by deducting from gross revenue the aggregate of all allowable operating costs, interest expense and amortization of capital costs and any loss carryforwards. Based on forecasted production levels and proposed capital expansions, Western does not foresee the higher royalty rates to take effect in the immediately foreseeable future. ENVIRONMENTAL CONSIDERATIONS The key environmental issues and stakeholder concerns to be managed by the Owners in the development of the Mine are similar to those currently being managed by existing oil sands operators and communities and encompass the health of local and regional residents and Project employees, surface disturbance on the terrestrial ecosystem, effects on traditional land use and historical resources, local and regional air quality, water quality, health of the aquatic ecosystem in the Athabasca and Muskeg rivers and cumulative effects on wildlife populations and aquatic resources. The Owners have committed to both site-specific and regional monitoring programs that will track the effects of the Project and the cumulative effects of regional development on environmental components and ecosystems. The Owners will operate the Project to achieve compliance with applicable statutes, regulations, codes, permit conditions and, to the extent practicable, government guidelines. Where the applicable laws are not clear or do not address all environmental concerns, management will apply appropriate internal standards and guidelines to address such concerns. In addition to complying with legislation and regulations and exercising due diligence, the Owners will strive to continuously improve the overall environmental performance of the operation and products while aspiring for short term and long term commercial success for the Project. Air quality is of particular importance to the Project, and has taken on greater significance with the federal government's ratification of the Kyoto agreement. As part of a Voluntary Climate Change Action Plan, the Joint Venture has substantially reduced emission targets for the Project. As it stands today, the Project is operating with emissions that are approximately 27 per cent lower than the original case that was approved by the Alberta Energy and Utilities Board. This has been achieved through the addition of cogeneration units, the use of waste hydrogen from a neighbouring facility and a variety of process improvements. Western's goal is to further reduce emissions by another 50 per cent by 2010 through a combination of energy efficiency projects. To achieve this goal, the Owners are pursuing a multi-faceted plan, which includes energy efficiency projects, investigation of cleaner technology, the purchase of domestic and international offsets and tree-planting offset programs. JOINT VENTURE AGREEMENT The following section describes the general terms of the Joint Venture Agreement and certain other relevant agreements. GENERAL The Joint Venture, which commenced December 6, 1999, consists of the following: (i) the mining of oil sands from the western portion of Lease 13; (ii) extraction of bitumen from such oil sands at the Extraction Plant; (iii) the upgrading of such diluted bitumen in the Upgrader into refinery feedstocks and synthetic crude oil blends; (iv) certain rights of the Corporation and Chevron to participate in mining operations on the east area of Lease 13 and in Shell's Other Athabasca Leases; (v) an area of mutual interest for expansion of operations of the Joint Venture; (vi) the disposition of the Upgrader products; and (vii) the construction operations relating to the foregoing. The Joint Venture has been established pursuant to a number of agreements among the Owners and is the subject of other agreements between the Owners and third parties. -17- JOINT VENTURE AND RELATED AGREEMENTS The principal agreement, which established the Joint Venture and governs the relationship of the Owners, is the Joint Venture Agreement. This agreement also sets out the manner in which certain of the other Project agreements will be dealt with. The JVA provides for the formation of the Joint Venture, the manner in which the Joint Venture is administered, the creation and manner in which the Executive Committee, which is the decision making body in respect of most matters, functions, the responsibilities of the project administrator, secondments of Owners' personnel, budgets, costs, technology matters, dispositions, defaults, environmental matters, expansions, Owner's rights vis-a-vis each other, as well as financial, accounting, banking matters, basic design parameters of the Project and other matters. The Joint Venture continues until all abandonment and decommissioning obligations of the Owners have been fulfilled in accordance with applicable laws and all required regulatory approvals have been received, all third party Project agreements have been terminated and all accounts among the Owners in respect of the Project have been settled. EXECUTIVE COMMITTEE AND PROJECT ADMINISTRATOR The JVA establishes an Executive Committee that is responsible for most decisions relative to the Joint Venture, other than those which are requirements of the Owners. One of Shell's representatives has been appointed as the first Chairman and each Owner has appointed two representatives to the Executive Committee. Voting at the Executive Committee level is based upon Owners' ownership interests. The Executive Committee also oversees the operations of Albian and Shell as operators of the Mine and Extraction Plant and the Upgrader and related facilities and ensures that each Owner has an ongoing opportunity to provide qualified secondees to the Project. The project administrator, which initially is Shell, has an administrative function and deals with day to day matters that include making payments under third-party Project agreements and dealing with administrative matters relating to non-performing Owners. The project administrator is responsible for carrying out the directions of the Executive Committee and appointing an individual to act as project integration manager. WESTERN PERSONNEL Albian operates the Mine and the Extraction Plant pursuant to an operating agreement. The mining and extraction services agreement dated December 6, 1999 between Western and Albian (the "Mining and Extraction Services Agreement") sets out that Western will provide certain mine and extraction management services including the full and part-time services of certain of its employees and consultants to Albian. Further, Western will identify additional personnel to be employed by Albian beyond the Western personnel who are necessary for the operation of the Mine and the Extraction Plant. Western has eight employees working directly for the Joint Venture, three of which are operational in nature including the Chief Operating Officer of Albian while five are based in Calgary whose primary role is to assist with our Joint Venture partners in the planning and feasibility studies associated with expansion initiatives. All costs incurred by Western and approved by the Executive Committee in respect of the provision of services by Western pursuant to the Mining and Extraction Services Agreement are reimbursed by Albian. -18- EXPANSIONS Should an Owner wish to undertake an expansion of a key component of the Project, the mining of the remaining area of Lease 13 or the construction of a new mine, it must first advise the other Owners and provide a period of time for them to advise as to whether or not they will participate in the feasibility study for the proposed expansion. If an Owner does not originally participate in a feasibility study it may, upon completion of the feasibility study, purchase the right to participate in the feasibility study and the expansion by paying twice the cost of its proportionate share of the feasibility study. If an expansion is to take place, an Owner must satisfy certain conditions relating to financial capability to undertake the proposed expansion. Expansion on the eastern portion of Lease 13 or in respect of the Upgrader prior to five years after Project Start-up may only be undertaken with the written approval of Shell (provided Shell or an affiliate has an ownership interest in the Upgrader and is an Owner and operator of the Scotford Refinery at the time in respect of expansion to the Upgrader). In order to participate in an expansion in respect of the east area of Lease 13, each Owner would be required to pay to Shell an amount based on the share of the recoverable bitumen reserves to be acquired by such Owner. Owners' interests will be adjusted to reflect expansions. Expansions may only take place by Owners with total ownership interest of a minimum of 40% in the key component of the Project being expanded. If an Owner other than Shell does not participate in an expansion on the east portion of Lease 13 or in Shell's other Athabasca Leases it shall have no further expansion rights. DISPOSITIONS Owners may not assign or transfer ownership interests in the Project until three years after Project Start-up unless such dispositions are: (i) a grant of security and the secured party acknowledges it is subject to the Joint Venture Agreement and is subordinate to all liens granted thereunder; (ii) dispositions to affiliates; (iii) to a person meeting certain specified financial requirements; and (iv) certain limited public or private placement offerings of securities. Partial assignments are only permissible if all resulting ownership interests are 10% or greater. The Owners have also granted each other a right of first refusal in respect of proposed dispositions. DIVIDEND POLICY No dividends have been paid on any shares of Western since the date of its incorporation. The Corporation currently intends to retain its earnings to finance the growth and development of its business and therefore it is not expected that dividends will be paid on the Common Shares in the immediate or foreseeable future. In addition, the note indenture governing the Notes contains restrictions on the Corporation's ability to pay dividends or distributions of any kind. DESCRIPTION OF SHARE CAPITAL The authorized share capital of the Corporation includes an unlimited number of Common Shares, an unlimited number of Non-voting Convertible Class B Equity Shares ("Non-voting Convertible Equity Shares"), an unlimited number of Class C Preferred Shares ("Class C Shares") and an unlimited number of Class D Preferred Shares, issuable in series ("Class D Shares"). The following is a brief description of the attributes of the Corporation's Common Shares, Non-voting Convertible Equity Shares, Class C Shares and Class D Shares. -19- COMMON SHARES The holders of Common Shares are entitled, subject to specified preferences in favour of holders of Class C Shares and Class D Shares, to dividends if, as and when declared by the directors and to one vote per share at meetings of the holders of Common Shares and, upon liquidation, subject to specified preferences in favour of holders of Class C Shares and Class D Shares, to share equally share for share with the Non-voting Convertible Equity Shares in the remaining assets of the Corporation. NON-VOTING CONVERTIBLE EQUITY SHARES The holders of Non-voting Convertible Equity Shares are entitled to dividends in parity with the Common Shares if, as and when declared by the directors and, upon liquidation, subject to specified preferences in favour of holders of Class C Shares and Class D Shares, to share equally share for share with the Common Shares in the remaining assets of the Corporation. Holders of Non-voting Convertible Shares are not entitled to receive notice of, attend or vote at any meetings of shareholders unless otherwise entitled pursuant to applicable laws. Each Non-voting Convertible Equity Share shall entitle the holder to acquire (subject to adjustment), at no additional cost, one Common Share at 4:30 p.m. (Calgary time) (the "Acquisition Expiry Time") on the earlier of: (i) five (5) business days following the date upon which a receipt for a prospectus (the "Qualifying Prospectus") to be filed by Western with respect to the distribution of the Common Shares upon conversion of the Non-voting Convertible Equity Shares has been issued by the last of the securities commissions or similar regulatory authorities in the Province of Alberta and such other provinces of Canada in which the Corporation files such Qualifying Prospectus (based upon the residences of Canadian subscribers); and (ii) 12 months from the date of issuance of the Non-voting Convertible Equity Shares. Non-voting Convertible Equity Shares outstanding at the Acquisition Expiry Time shall be deemed to be converted by the holder, without any further action on the part of the holder, at the Acquisition Expiry Time. As at the date hereof, there are no outstanding securities of this class. CLASS C SHARES The Corporation is authorized to make one issuance of Class C Shares. The holders of Class C Shares shall not be entitled to receive notice of, attend or vote at any meetings of the shareholders of the Corporation unless otherwise entitled pursuant to applicable laws but shall be entitled to receive in respect of each calendar year, if, as and when declared by the directors, a non-cumulative preferential dividend in the amount (if any) declared by the directors. No dividends shall be declared or paid in any year on the Common Shares, Non-voting Convertible Equity Shares, Class D Shares or any other shares of the Corporation ranking junior to the Class C Shares from time to time with respect to the payment of dividends, unless all dividends which shall have been declared and which remain unpaid on the Class C Shares then issued and outstanding shall have been paid or provided for at the date of such declaration or payment. Upon liquidation, holders of Class C Shares shall be entitled to payment of an amount (subject to adjustment) equal to the amount or value of the consideration paid for such shares (the "Redemption Amount") in priority to the Common Shares, the Non-voting Convertible Equity Shares, the Class D Shares and any other shares ranking junior to the Class C Shares from time to time. The Class C Shares are redeemable by the Corporation or the holders of Class C for the Redemption Amount. As at the date hereof, there are no outstanding securities of this class. CLASS D SHARES The Class D Shares are entitled to receive notice of, attend and vote at any meetings of shareholders and are convertible into Common Shares, prior to redemption, on a one-for-one basis. The Class D Shares are redeemable by the Corporation at a price equal to their issue price plus a cumulative dividend of 12% per annum compounded semi-annually until January 1, 2007, from which date the dividend increases by 3% -20- per quarter to a maximum of 24% per annum. As of December 31, 2004, all 666,667 Class D Shares were converted into Common shares for no additional consideration. Consequently, as at the date hereof, there are no outstanding securities of this class. -21- MARKET FOR SECURITIES The Common Shares of the Corporation are listed for trading on the Toronto Stock Exchange ("TSX") under the symbol "WTO". The following table sets for the high, low and closing trading prices and the volume of Common Shares traded on the TSX for each monthly of the most recently completed financial year:
MONTH HIGH LOW CLOSING VOLUME --------------------------------------------------------------------------------------------------------------- January 31.56 28.70 29.49 3,555,084 February 33.40 29.50 33.40 1,751,884 March 35.35 32.21 33.60 3,180,792 April 34.50 31.00 31.25 2,308,909 May 32.74 30.05 31.34 2,939,697 June 33.88 30.35 33.75 3,466,351 July 34.50 33.11 33.78 2,243,037 August 34.10 31.95 33.62 3,597,272 September 37.75 33.31 37.74 5,101,079 October 42.36 37.35 38.90 3,879,521 November 43.50 38.25 42.86 3,093,040 December 43.24 39.01 41.85 2,263,065
RATINGS Western's Notes are currently rated by two separate agencies, Standard and Poors ("S&P") and Moody's Investor Service. ("Moody's") Please refer to the table below for the respective ratings assigned to Western. ----------------------------- ------------------------ ------------------------- TYPE OF SECURITY S&P Moody's ----------------------------- ------------------------ ------------------------- US$450 Million Notes BB+/Positive Ba2 ----------------------------- ------------------------ ------------------------- S&P Rating Definition - Obligations rated BB are regarded as having significant speculative characteristics. An obligation rated BB is less vulnerable to non-payment than other speculative issues. However, it faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions which could lead to the obligor's inadequate capacity to meet its financial commitment on the obligation. BB+ is one level below that which is considered "Investment Grade" under the S&P rating system. The (+) sign is added to show relative standing within the major rating categories. The ratings outlook for Western by S&P is "Positive" which indicates that a rating may be raised. Moody's - Moody's long-term obligation ratings are opinions of the relative credit risk of fixed-income obligations with an original maturity of one year or more. They address the possibility that a financial obligation will not be honoured as promised. Such ratings reflect both the likelihood of default and any financial loss suffered in the event of default. Obligations rated Ba are judged to have speculative elements and are subject to substantial credit risk. Moody's appends numerical modifiers 1, 2, and 3 to -22- each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category. Investment grade under the Moody's rating system would be Baa3 and higher. A security rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the rating organization. DIRECTORS AND OFFICERS The following table lists the names of the directors and officers of Western, their municipalities of residence, positions and offices with Western and principal occupations during the preceding five years:
Name and Municipality of Present Position and Principal Occupation During the Last Director Since Residence Office Five Years ---------------------------------------------------------------------------------------------------------------- Directors Glen F. Andrews(2)(4)(8) Director Retired businessman. Previously October 1999 President of BHP Copper North America Bainbridge Island, until June 1999. Prior thereto, Washington Executive Vice-President and General Manager, BHP Copper of the South America and Pacific regions from 1996 to 1998 and North American region in 1998. Tullio Cedraschi(4) Director President and Chief Executive Officer of October 2000 Montreal, Quebec CN Investment Division, the entity responsible for investing the assets of the Canadian National Railways Pension Trust Funds. Geoffrey A. Cumming(2)(3(7) Chairman and Managing Director of Zeus Capital October 1999 Auckland, New Zealand Director Limited, a private New Zealand investment corporation, since March 2003. Vice-Chairman of Gardiner Group Capital Limited, a private Canadian investment corporation, to June 2003 and prior to July 2002, Chief Executive Officer of Gardiner Group Capital Limited. Oyvind Hushovd(4) Director Chairman and Chief Executive Officer of December 2003 Oakville, Ontario Gabriel Resources Ltd., a mining corporation, since March 2003. President and Chief Executive Officer of Falconbridge Ltd., a mining corporation, from 1996 to February 2002.
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Name and Municipality of Present Position and Principal Occupation During the Last Director Since Residence Office Five Years ---------------------------------------------------------------------------------------------------------------- John W. Lill(2) Director Executive Vice President and Chief December 2003 Toronto, Ontario Operating Officer of Dynatec Corporation, a mining corporation, since November 2003. President and Chief Operating Officer (Base Metals) with BHP Billiton, a mining corporation, from 2001 to 2003 and Chief Operating Officer (Copper) with BHP Billiton from 2000 to 2001. From 1998 to 2001, Vice President of Mining Operations for Rio Algom Ltd., a mining corporation. Randall Oliphant(1) Director Chairman and Chief Executive Officer of February 2005 Toronto, Ontario Rockcliff Group Limited, a private company investing mainly in the mining sector, since 2003. Prior thereto, served in various senior financial roles in Barrick Gold Corporation culminating in appointment as Chief Executive Officer in 1999 until 2003. Director of Adolph Coors Company Robert G. Puchniak(1) Director Executive Vice President and Chief October 1999 Winnipeg, Manitoba Financial Officer of James Richardson & Sons, Limited ("James Richardson") since March 2001. Prior thereto, Vice-President, Finance and Investment, James Richardson since 1996. Guy J. Turcotte(7) President, Chief President of Western since January 2002 July 1999 Calgary, Alberta Executive Officer and Chief Executive Officer of Western and Director since July 1999; Chairman of Fort Chicago Energy Partners, L.P. since September 1997 and Chief Executive Officer until December 2002. Mac H. Van Director Co-Chairman of ARC Financial December 1999 Wielingen(1)(3)(6) Corporation ("ARC"), a private investment Calgary, Alberta management company focused on the energy sector, and Chairman of ARC Energy Trust. Previously, President of ARC since 1989.
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Name and Municipality of Present Position and Principal Occupation During the Last Director Since Residence Office Five Years ---------------------------------------------------------------------------------------------------------------- Officers John Frangos Executive Executive Vice-President and Chief -- Calgary, Alberta Vice-President and Operating Officer of Western since Chief Operating January 2002; prior thereto Corporate Officer Development, Western since October 1999; previously Vice-President International Business Development of BHP Minerals from April 1996 to September 1999. David A. Dyck Vice-President, Vice-President, Finance and Chief -- Calgary, Alberta Finance and Chief Financial Officer of Western since Financial Officer April 2000; prior thereto, Senior Vice President Finance & Administration and Chief Financial Officer of Summit Resources Limited ("Summit") since September 1998; Vice President Finance and Chief Financial Officer of Summit from October 1996 to September 1998. Charles W. Berard Corporate Secretary Partner with Macleod Dixon llp, -- Calgary, Alberta Barristers & Solicitors.
Notes: (1) Member of the Audit Committee. (2) Member of the Compensation Committee. (3) Member of the Governance Committee. (4) Member of the Health, Safety and Environment Committee. (5) The Corporation does not have an Executive Committee. (6) Mr. Van Wielingen was a director of Gauntlet Energy Corporation ("Gauntlet") from September 1999 to December 2003. On June 17, 2003, an order was granted under the Companies Creditors Arrangement Act which provided creditor protection to Gauntlet to develop a financial restructuring plan that was approved by its creditors. (7) Mr. Guy Turcotte will be resigning as President and Chief Executive Officer effective April 15, 2005 and will assume the position of Chairman of the Board and Director. Mr. Geoff Cumming, the current Chairman, will be stepping down as Chairman effective April 15, 2005, continuing as an independent Director. (8) It is anticipated that Mr. Andrews will be retiring from the Board and the various sub-committees at the Annual and Special Meeting on May 11, 2005. As announced on February 24, 2005, Messrs Brian MacNeill and Walter Grist retired from the Board. Also announced at this time was the appointment of Mr. Randall Oliphant. Mr. Randall Oliphant is the Chairman and Chief Executive Officer of Rockcliff Group Limited, a private investment corporation actively involved in the strategic planning and corporate development of its investee companies, principally in the mining sector. Until 2003, he was the President and Chief Executive Officer of Barrick Gold Corporation, and served in senior financial positions since joining the company in 1987 prior to being appointed Chief Executive Officer in 1999. He is on the Advisory Board of Metalmark Capital LLC (formerly Morgan Stanley Capital Partners) and has served on the Board of the Adolph Coors Company. He also serves on the Boards of a number of private companies and not-for-profit organizations. Mr. Oliphant holds a B.Comm. from the University of Toronto and is a Chartered Accountant. As disclosed in the Corporation's Information Circular, Mr. David Boone is proposed to become a director at the Corporation's Annual and Special Meeting to be held on May 11, 2005. Mr. Boone is a Professional Engineer and has more than 25 years of oil and gas industry experience with significant producing companies in the Canadian industry. He began his career with Imperial Oil holding various positions and joined PanCanadian Petroleum in 2000 as Executive Vice-President and Chief Operating -25- Officer. He was named Executive Vice-President of EnCana Corporation upon its founding in early 2002 and President of the company's Offshore and International Operations Division. In 2003, he founded a new oil and gas company, Escavar Energy Inc. and is currently President of that company. On March 30, 2005, the Corporation announced the appointment of Mr. James C. Houck as President and Chief Executive Officer effective April 15, 2005. Mr. Houck will also be nominated to the Board at the Corporation's Annual and Special Meeting. Mr. Houck spent most of his career with ChevronTexaco Inc. and held various senior positions within the Texaco organization in global gas and power, business development, production operations, research & development and finance & strategic planning. From 1998 to 2003, Mr. Houck was the President of ChevronTexaco's Worldwide Power and Gasification Inc. Most recently, Mr. Houck has been a Principal of FrontStreet Partners, a US based privately held investment firm. Each director holds office until the next annual meeting of shareholders of the Corporation or until their successors are duly elected or appointed. As at March 30, 2005, the directors and officers of the Corporation, together with their respective spouses, children or corporations controlled by them own or control, directly or indirectly, an aggregate of 1,744,103 Common Shares or approximately 3.27% of the issued and outstanding voting securities of the Corporation. Not included the amount above is 1,887,377 Common shares owned by Turcotte Family Holdings Ltd. ("Turcotte Holdings") Mr. Turcotte is a discretionary beneficiary under a family trust that exercises voting control over Turcotte Holdings. Mr. Turcotte does not own, directly or indirectly, or exercise control or direction over any voting shares of Turcotte Holdings. Investors should be aware that some of the directors and officers of the Corporation are directors and officers of other private and public companies. Some of these private and public companies may, from time to time, be involved in business transactions or banking relationships which may create situations in which conflicts might arise. Any such conflicts shall be resolved in accordance with the procedures and requirements of the relevant provisions of the Business Corporations Act (Alberta), including the duty of such directors and officers to act honestly and in good faith with a view to the best interests of the Corporation. AUDIT COMMITTEE COMPOSITION AND QUALIFICATIONS The Audit Committee consists of three outside independent directors: Robert G. Puchniak (Chair), Randall Oliphant and Mac H. Van Wielingen, all of whom are financially literate. In considering criteria for the determination of financial literacy, the Board of Directors looks at the ability to read and understand a balance sheet, an income statement and a cash flow statement of a public company. The following is a brief description of the education and experience of each of the members of the Audit Committee: ROBERT G. PUCHNIAK, CHAIRMAN AND INDEPENDENT DIRECTOR Mr. Puchniak was appointed Executive Vice-President and Chief Financial Officer of James Richardson & Sons, Limited, an investment and holding corporation, in March 2001 and prior thereto was Vice-President, Finance and Investment with James Richardson & Sons, Limited since November 1996. Mr. Puchniak was President and Chief Executive Officer of Tundra Oil and Gas Ltd., a private oil and gas corporation, from January 1989 to April 2003. Mr. Puchniak has also held positions with Gendis Inc. and -26- Richardson Securities Limited. Mr. Puchniak is a director of a number of public and private corporations including James Richardson International Limited, Tundra Oil and Gas Ltd., Opti Canada Inc., Trident Resources Corp, Richardson Partners Financial Holdings Limited and Lombard Realty Limited. Past involvements include Director, Moffat Communications Limited, Terraquest Energy Corporation and Richland Petroleum Corporation; Chairman, Manitoba Teachers' Retirement Fund; Chairman, Council of Examiners, Institute of Chartered Financial Analysts; and President, Winnipeg Society of Financial Analysts. Mr. Puchniak holds a Bachelor of Commerce (Honours) degree from the University of Manitoba and was awarded the University Gold Medal for his achievements. He earned a Chartered Financial Analyst designation in 1975. RANDALL OLIPHANT, INDEPENDENT DIRECTOR Mr. Randall Oliphant is the Chairman and Chief Executive Officer of Rockcliff Group Limited, a private investment corporation actively involved in the strategic planning and corporate development of its investee companies, principally in the mining sector. Until 2003, he was the President and Chief Executive Officer of Barrick Gold Corporation, and served in senior financial positions since joining the company in 1987 prior to being appointed Chief Executive Officer in 1999. He is on the Advisory Board of Metalmark Capital LLC (formerly Morgan Stanley Capital Partners) and has served on the Board of the Adolph Coors Company. He also serves on the Boards of a number of private companies and not-for-profit organizations. Mr. Oliphant holds a B.Comm. from the University of Toronto and is a Chartered Accountant. MAC H. VAN WIELINGEN, INDEPENDENT DIRECTOR Mr. Van Wielingen is a founder and currently Co-Chairman of ARC Financial Corporation, an investment management corporation focused on the energy sector in Canada. Mr. Van Wielingen is also a founder and currently Chairman of ARC Energy Trust. He is a past and a current director of numerous private and public energy companies in Canada. He also chairs the Significant Gift Division of the United Way of Calgary and area. Mr. Van Wielingen holds an Honours Business Degree from the University of Western Ontario Business School and has studied post-graduate Economics at Harvard University. RESPONSIBILITIES AND TERMS OF REFERENCE The following is a summary of the key roles and responsibilities of the Audit Committee. Full particulars are set out in the Audit Committee Charter which is attached as Appendix C hereto. The Audit Committee reviews Western's interim unaudited consolidated financial statements, press releases and annual audited consolidated financial statements and certain corporate disclosure documents including the annual information form, management's discussion and analysis, offering documents including all prospectuses and other offering memoranda before they are approved by the Board. The Committee reviews and makes a recommendation to the Board in respect of the appointment of the external auditor and it monitors accounting, financial reporting, control and audit functions. The Audit Committee meets to discuss and review the audit plans of the external auditors and is directly responsible for overseeing the work of the external auditor with respect to the preparing or issuing of the auditor's report or the performance of other audit, review or attest services including the resolution of disagreements between management and the external auditor regarding financial reporting. The Committee questions the external auditor independently of management and reviews a written statement of the external auditors' independence based on the criteria found in the recommendations of the Canadian Institute of Chartered Accountants. The Committee considers and makes a recommendation to the Board as to the compensation of the external auditor and ensures that fees paid to the external auditor for audit and non-audit services are publicly disclosed. The Committee must be satisfied that adequate procedures are in place for the review of the Corporation's public disclosure of financial information extracted or derived from its financial statements and it periodically assesses the adequacy of those -27- procedures. In addition, it reviews and reports to the Board on Western's risk management policies and procedures and reviews the internal control procedures to determine their effectiveness to ensure compliance with applicable legal requirements, regulatory requirements and Western's policies. The Audit Committee reviews the controls in place with respect to officers' expenses and perquisites, reviews insurance coverage for significant business risks and uncertainties and reviews material litigation and its impact on financial reporting. The Committee has established procedures for dealing with complaints, submissions or concerns on an anonymous and confidential basis which come to its attention with respect to accounting, internal accounting controls or audit matters. The Audit Committee is also charged with reviewing the report of the independent qualified reserves evaluator relating to the Corporation's estimated oil and gas reserves. The Committee meets with the independent qualified reserves evaluator to review the evaluation report, the corporate summary of the reserves and future net revenues of the oil sands properties and other related matters. In addition, it reviews the selection and qualifications of the independent engineering firm, the scope of its work and the consistency of its practices, standards and definitions AUDITOR SERVICE FEES PricewaterhouseCoopers llp has served as the auditors of Western since its incorporation. The following table summarizes the total fees paid to PricewaterhouseCoopers llp for the years ended December 31, 2004 and December 31, 2003:
2004(1) 2003 -------------------------- ----------------------------------- Audit fees $131,980 $66,900 Audit-related fees -- -- Tax fees 24,960 5,720 All other fees -- -- -------------------------------------------------------------------------------------------------------------------- TOTAL $156,940 $72,620 --------------------------------------------------------------------------------------------------------------------
Note: (1) Paid or estimated to be payable for 2004 services. Audit fees were paid for professional services rendered by the auditors for the audit of the Corporation's annual financial statements or services provided in connection with statutory and regulatory filings. Audit-related fees were paid for review of quarterly financial statements of Western, attendance at quarterly audit meetings, and for services provided in connection with financings. Tax fees were paid for tax advice and assistance with tax audits, including GST and property tax reviews. All permissible categories of non-audit services require pre-approval from the Audit Committee. RISKS AND UNCERTAINTIES The Corporation is exposed to a number of risks and uncertainties relating to its operations. THE MINE, EXTRACTION PLANT AND UPGRADER MAY NOT PERFORM AS PLANNED. The Project may encounter interruptions in production or additional costs due to many factors, including: o breakdown or failure of equipment or processes; o design errors; -28- o operator errors; o violation of permit requirements; o disruption in the supply of energy; and o catastrophic events such as fire, earthquake, storms or explosions. The Project consists of multiple facilities, all of which must be run on an integrated and co-ordinated basis. There can be no assurance that each component will continuously operate as designed or expected or that the necessary levels of integration and co-ordination will continuously be achieved. Some of the mining and extraction processes employed in the Project represent new applications of established processes, processes that are larger in scale than other commercial operations, or new processes that are scaled-up from the pilot plant processes used to test the feasibility of the Mine and Extraction Plant. There can be no assurance that all components of the mining and extraction facility will continue to perform as expected or that the costs to operate this facility will not be significantly higher than expected. There can be no assurance that the Upgrader will have the same level of success in upgrading bitumen and purchased feedstocks into products with the desired specifications. Costs to operate the Upgrader may be significantly higher than expected. THIRD-PARTY FACILITIES MAY NOT OPERATE AS PLANNED. The Project depends upon successful operation of facilities owned and operated by third parties. The Owners are party to certain agreements with third parties to provide for, among other things, the following services and utilities: o pipeline transportation to be provided through the Corridor pipeline system; o electricity and steam to be provided to the Mine and the Extraction Plant from the Muskeg River cogeneration facility; o transportation of natural gas to the Muskeg River cogeneration facility by the ATCO pipeline; o hydrogen to be provided to the Upgrader from the HMU and Dow; and o electricity and steam to be provided to the Upgrader from the Upgrader cogeneration facility. For the Mine and Extraction Plant, electricity and steam is provided by the Muskeg River cogeneration facility. If the Muskeg River cogeneration facility fails to continuously operate in the manner designed, there can be no assurance that the Owners will be able to obtain alternative sources of electricity on a timely basis, at prices acceptable to Western, or at all. If the cogeneration facility does not continuously provide the required steam, it is unlikely that other sources of steam could be acquired on a timely basis, at prices acceptable to Western, or at all. For the Upgrader, the electricity and steam is provided by the Upgrader cogeneration facility. There can be no assurance that in the event the Upgrader cogeneration facility fails to continuously operate in the manner designed, the Owners will be able to secure alternative sources of electricity and steam on a timely basis, at prices acceptable to Western, or at all. The HMU is designed to produce approximately 75% of the Upgrader's hydrogen requirements, with the remainder to be provided by Dow. If the HMU fails to perform continuously as designed or Dow fails to deliver pursuant to its contract, respectively, there can be no assurance that the Project will be able to obtain its hydrogen requirements on a timely basis, at prices acceptable to Western, or at all. -29- The Project relies on transportation of bitumen and upgrader output from a pipeline system owned and operated by Terasen. If the Corridor pipeline system is unavailable for any reason, Western will have to find alternatives to the Corridor pipeline system which may not be available on a timely basis, at prices acceptable to Western, or at all. Under the terms of certain third-party agreements, the Owners are committed to pay for utilities and services on a long-term "take-or-pay" basis, regardless of the extent that such utilities and services are actually used. In addition, under the terms of the agreement with Terasen, Western must make scheduled payments to them even if the Corridor pipeline system has diminished capacity or is unavailable. If, due to Project delays, suspensions, shut-downs or other reasons, the Owners fail to meet their commitments under these long-term agreements, the Owners may incur substantial costs and may, in some circumstances, be obligated to purchase the facilities constructed by the third parties to provide the services and utilities for a purchase price in excess of the fair market value of the facilities. There can be no assurance that Western will have sufficient funds to satisfy these obligations. Most of the contracts with third-party operators do not contain provisions for the payment of liquidated damages. Accordingly, if certain of the third-party facilities do not operate as planned, Western will not have a direct financial claim against the third-party operators. THE PRICE OF CRUDE OIL AND NATURAL GAS MAY FLUCTUATE AND NEGATIVELY IMPACT FINANCIAL RESULTS. Western's financial results are dependent upon the prevailing price of crude oil and natural gas. Oil and natural gas prices fluctuate significantly in response to supply and demand factors beyond Western's control. Political developments, especially in the Middle East, can affect world oil supply and oil prices. As a result of the relatively higher operating costs of the Project compared to some conventional crude oil production operations, Western's operating margin is more sensitive to oil prices than that of some conventional crude oil producers. Any prolonged period of low oil prices could result in a decision by the Owners to suspend or reduce production. Any such suspension or reduction of production would result in a corresponding substantial decrease in Western's revenues and earnings and could expose Western to significant additional expense as a result of certain long-term contracts. If the Owners did not decide to suspend or reduce production, the sale of our product at reduced prices would lower our revenues. In addition, because natural gas comprises a substantial part of Western's operating costs, any prolonged period of high natural gas prices will negatively impact Western's financial results. WESTERN MAY EXPERIENCE PRICING PRESSURE ON ITS SHARE OF THE PROJECT'S SYNTHETIC CRUDE OIL PRODUCTION DUE TO OVERSUPPLY AND COMPETITION. Western sells its share of synthetic crude oil production to refineries in North America. These sales compete with the sales of both synthetic and conventional crude oil. There exist other suppliers of synthetic crude oil and there are several additional projects being contemplated. If undertaken and completed, these projects will result in a significant increase in the supply of synthetic crude oil to the market. In addition, not all refineries are able to process or refine synthetic crude oil. There can be no assurance that sufficient market demand will exist at all times to absorb Western's share of the Project's synthetic crude oil production. WESTERN MAY NOT BE ABLE TO PRODUCE A HIGH VALUE SINGLE STREAM BLEND. Western expects that concurrent with expansion initiatives it will be in a position to market a single stream blend of synthetic crude oil which has a greater value than the heavy and light streams currently marketed. There is a risk that Western will be unable to create a single stream with a higher value than the heavy and light streams. There is also a risk that the price per barrel from selling two synthetic crude -30- oil streams and vacuum gas oil could be significantly less than the price per barrel from selling a single synthetic crude oil stream and vacuum gas oil. FLUCTUATIONS IN THE US AND CANADIAN DOLLAR EXCHANGE RATE MAY CAUSE WESTERN'S OPERATING COSTS TO RISE. Crude oil prices are generally based on a US dollar market price, while Western's operating costs are primarily denominated in Canadian dollars. Adverse fluctuations in the US and Canadian dollar exchange rate may cause Western's operating costs to rise in relation to Western's revenues. Western undertakes minor hedging activities against currency fluctuations. There can be no assurance that current activities nor more expansive hedging programs in the future that Western may adopt are or would be successful. WESTERN COMPETES WITH LARGER COMPANIES AND ALTERNATIVE FUELS WHEN IT SELLS ITS SHARE OF THE PROJECT'S PRODUCTION. The Canadian and international petroleum industry is highly competitive in all aspects, including the distribution and marketing of petroleum products. Western competes with established oil sands operators which have established operating histories and greater financial and other resources than Western. In addition, Western competes with other producers of synthetic crude oil blends and producers of conventional crude oil, including Shell and Chevron, some of whom have lower operating costs and many of whom have extensive marketing networks. The crude oil industry also competes with other industries and alternative energy sources in supplying energy, fuel and related products to consumers. FEEDSTOCK SUPPLY FOR THE UPGRADER MAY NOT ALWAYS BE AVAILABLE. The Upgrader will require certain additional feedstocks to produce its output. Western has entered into contracts for required feedstocks for terms of between one and five years. There can be no assurance that feedstocks of the desired quality will be available on a timely basis after these contracts expire, at prices acceptable to Western, or at all. Unavailability of required feedstocks could have an adverse effect on the rate and quality of Upgrader output. THE PROJECTIONS AND ASSUMPTIONS ABOUT WESTERN'S FUTURE PERFORMANCE MAY PROVE TO BE INACCURATE. Western has only a few years of operating results. Western's long-term financing plan is based upon certain assumptions and financial projections regarding its share of revenues and of operating, maintenance and capital costs of the Project. These projections and assumptions may provide to be inaccurate. DEBT LEVELS COULD LIMIT FUTURE FLEXIBILITY IN OBTAINING ADDITIONAL DEBT FINANCING AND IN PURSUING BUSINESS OPPORTUNITIES. As at December 31, 2004, Western had approximately $812 million of debt (including obligations under the HMU lease). Western may also incur significant additional indebtedness for various purposes, including expansions. Western's debt level and restrictive covenants will have an important effect on its future operations. In addition, Western's ability to make scheduled payments or to refinance its debt obligations will depend upon its financial and operating performance, which in turn, will depend upon prevailing industry and general economic conditions beyond Western's control. There can be no assurance that Western's operating performance, cash flow and capital resources will be sufficient to repay its debt in the future. -31- FINANCING ARRANGEMENTS CONTAIN COVENANTS LIMITING OUR DISCRETION TO OPERATE OUR BUSINESS. Western's financing arrangements contain provisions that limit its discretion to operate its business. If Western fails to comply with the restrictions set forth in its current or future financing agreements, Western will be in default and the principal and accrued interest may become due and payable. THE PROJECT MAY EXPERIENCE EQUIPMENT FAILURES FOR WHICH WESTERN DOES NOT HAVE SUFFICIENT INSURANCE. The Upgrader processes large volumes of hydrocarbons at high pressure and temperatures in equipment with fine tolerances. Equipment failures could result in damage to the Extraction Plant and the Upgrader and liability to third parties against which Western may not be able to fully insure or may elect not to insure for various reasons, including high premium costs. Even with adequate insurance, delays in realizing on claims and replacing damaged equipment could adversely affect Western's operations and revenues. HEDGING ACTIVITIES COULD RESULT IN LOSSES OR LIMIT THE BENEFIT OF CERTAIN COMMODITY PRICE INCREASES. The nature of Western's operations results in exposure to fluctuations in commodity prices. Western has initiated a hedging program to use financial instruments and physical delivery contracts to hedge its exposure to these risks. When engaging in hedging Western will be exposed to credit-related losses in the event of non-performance by counterparties to the financial instruments. From time to time Western may enter into additional hedging activities in an effort to mitigate the potential impact of declining oil prices. These activities may consist of, but may not be limited to: o buying a price floor under which Western will receive a minimum price for its oil production; o buying a collar under which Western will receive a price within a specified range for its oil production; o entering into fixed contracts for oil production; and o entering into a contract to fix the differential between the price for Western's outputs and either the West Texas Intermediate or the Edmonton Par crude oil pricing benchmarks. If product prices increase above those levels specified in any future hedging agreements, Western could lose the cost of floors or ceilings or a fixed price could limit Western from receiving the full benefit of commodity price increases. In addition, by entering into these hedging activities, Western may suffer financial loss if it is unable to produce sufficient quantities of oil to fulfil its obligations. Western may hedge its exposure to the costs of various inputs to the Project, such as natural gas or feedstocks. If the prices of these inputs falls below the levels specified in any future hedging agreements, Western could lose the cost of ceilings or a fixed price could limit Western from receiving the full benefit of commodity price decreases. RESERVE AND RESOURCE ESTIMATES ARE UNCERTAIN. There are numerous uncertainties inherent in estimating quantities of reserves and resources, including many factors beyond Western's control. Western's reserve and resource data represent estimates only. The usefulness of such estimates is highly dependent upon the accuracy of the assumptions on which they -32- are based, the quality of the information available and the ability to compare such information against industry standards. Fluctuations of oil prices may render the mining of oil sands reserves uneconomical. Other factors relating to the oil sands reserves, such as the need for orderly development of ore bodies or the processing of new or different grades of ore, may impair Western's profitability. In general, estimates of economically recoverable bitumen reserves and the related future net pretax cash flows of the Project are based upon a number of variable factors and assumptions, such as: o historical production from similar properties which are owned by other operators; o the assumed effects of regulation by governmental agencies; o estimated future operating costs; and o the availability of enhanced recovery techniques, all of which may vary considerably from actual results of the Project. There is a limited history of production from Western's properties. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. Western's reserve figures have been determined based upon assumed oil prices and operating costs. For those reasons, estimates of the economically recoverable bitumen reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Western's actual production, revenues, taxes and development and operating expenditures with respect to Western's reserves will vary from such estimates, and such variances could be material. Reserve estimates may require revision based on actual production experience. INDEPENDENT REVIEWS MAY BE INACCURATE. Although third parties have prepared reviews, reports and projections relating to the viability and expected performance of the Project, there can be no assurance that these reports, reviews and projections and the assumptions on which they are based will, over time, prove to be accurate. SHELL AND CHEVRON MAY NOT AGREE WITH WESTERN ON MATTERS RELATED TO THE PROJECT. The Project is a joint venture among Shell, Chevron and Western. Future plans of the Project, including decisions related to levels of production, will depend on agreement among the Owners and will depend on the financial strength and views of Shell and Chevron. There can be no assurance that the Owners will agree on all matters relating to the Project. Under the Joint Venture Agreement, ordinary resolutions of the Executive Committee may be passed without Western's consent and there can be no assurance that such resolutions may not adversely affect Western. In addition, if Western's voting interest in any functional units falls below 15%, Western's consent will not be required for an extraordinary resolution of the Executive Committee relating to that functional unit and such resolutions may adversely affect Western. -33- SHELL AND CHEVRON MAY NOT MEET THEIR OBLIGATIONS TO THE PROJECT. Western is subject to the risk of non-payment by Shell or Chevron in meeting their payment obligations to the Project. To the extent any Owner does not meet its obligations to fund its costs in respect of the Joint Venture Agreement and related agreements, Western, together with any other performing Owners, would be required to fund those obligations. IF WESTERN DEFAULTS ON ITS OBLIGATIONS UNDER THE JOINT VENTURE AGREEMENT, SHELL AND CHEVRON WILL HAVE THE RIGHT TO PURCHASE WESTERN'S INTEREST IN THE JOINT VENTURE AT A DISCOUNT. If Western fails to meet all or part of our obligations under the Joint Venture Agreement, including by failing to participate in any expansion of an existing mine which does not require an expansion of the Extraction Plant, Upgrader, major shared facilities or third party facilities (which expansions can be carried out pursuant to an ordinary resolution of the Executive Committee), the other Owners will have an option to purchase Western's entire ownership interest in the Joint Venture and related assets at a discount. The amount at which they could purchase Western's ownership interest would be equal to 80% of the capital costs incurred if default occurs prior to final completion, or 80% of fair market value if default occurs after final completion. SHELL MAY NOT FULFIL ITS OBLIGATIONS TO WESTERN UNDER OUR LONG-TERM SALES CONTRACT. Western expects to sell its share of vacuum gas oil produced by the Project to an affiliate of Shell on a long-term basis. Since a large portion of our revenues will be received from an affiliate of Shell, Western will have a concentration of credit risk. Furthermore, if the Shell affiliate does not have the capacity at the Scotford Refinery to physically process Western's share of vacuum gas oil produced by the Project after using its commercially reasonable efforts to maintain such capacity, it will not be required to purchase Western's share of vacuum gas oil until the Refinery regains such capacity. Modifications to the Scotford Refinery were undertaken to permit it to take the expected vacuum gas oil output. If the affiliate of Shell were to default on, or not be required to fulfil its obligations to Western, or if the Scotford Refinery is not capable of processing the vacuum gas oil, there can be no assurance that Western could sell its share of vacuum gas oil to other purchasers at a price equal to or greater than that provided for in its contract with the Shell affiliate, or at all. Additionally, the price Western receives for products sold to the affiliate of Shell may vary depending on the characteristics of the products sold. To the extent the characteristics of the products fail to meet agreed upon specifications, the purchase price for such products will be adjusted downward. If the characteristics of the products are significantly below specifications the affiliate of Shell is entitled to reject such products. Downward adjustment of the purchase price or rejection of the products could have an adverse effect on Western's operations and revenues, and there can be no assurance that we could sell any rejected products elsewhere. IF WESTERN DOES NOT PARTICIPATE IN CERTAIN EXPANSIONS, WESTERN WILL LOSE VOTING OR SIGNIFICANT EXPANSION RIGHTS. If Western does not participate in expansions on the western portion of Lease 13, in certain circumstances Western's voting interest will be diluted and Western's consent will no longer be required for extraordinary resolutions of the Executive Committee. In addition, if Western does not participate in an expansion on the remainder of Lease 13 or Shell's Other Athabasca Leases, or if Western no longer has an ownership interest in each functional unit comprising the Project, Western will lose its right to participate in any further expansions, lose any rights to share in the resources contained on Leases 88 and 89 and Shell's Other Athabasca Leases and lose any rights to participate in an area of mutual interest with the -34- other Owners. Shell and Chevron, have significantly greater capital resources than Western has. If the other Owners decide to undertake expansions, including expansions on the eastern portion of Lease 13 and on Leases 88 and 89, there can be no assurance that Western will be able to fund its share of the expansion. Western's participation would be subject to several conditions, including Western's satisfaction with feasibility studies and Western's access to the necessary capital resources. IF WESTERN PARTICIPATES IN CERTAIN EXPANSIONS, THOSE EXPANSIONS WILL BE SUBJECT TO MANY OF THE SAME RISKS AS THE PROJECT. Western may participate in expansions on the western portion of Lease 13, on the remainder of Lease 13 or on Shell's Other Athabasca Leases. The Owners are evaluating potential long-term development opportunities relating to resources contained within Lease 13 and on Shell's Other Athabasca Leases. If Western were to participate in any expansion, Western will require additional financing in order to fund its share of costs associated with an expansion. Additionally, Western's participation in expansions will be subject to many of the same risks as the Project. WESTERN MAY NOT BE ABLE TO EFFECTIVELY MANAGE ITS GROWTH. The Joint Venture Agreement permits participation in certain expansion opportunities. Participation in any expansion opportunities would significantly increase the demands on Western's management resources. Western may not be able to effectively manage these expansions, and any failure to do so could have a material adverse effect on Western's business, financial condition or results of operations. THE PROJECT MAY NOT BE ABLE TO HIRE AND RETAIN THE SKILLED EMPLOYEES IT REQUIRES. The Project requires experienced employees with particular areas of expertise. There are other oil sands and other industrial projects and expansions in Alberta that compete with the Project for skilled employees, and such competition may result in increases to the compensation paid to such employees. The Project has already experienced increased costs as a result of such competition and decreases in productivity. There can be no assurances that all of the required employees with the necessary expertise will be available. VARIOUS HAZARDS INHERENT IN WESTERN'S OPERATIONS COULD RESULT IN LOSS OF EQUIPMENT OR LIFE. The operation of the Project is subject to the customary hazards of mining, extracting, transporting and processing hydrocarbons, including the risk of catastrophic events such as fire, earthquake, storms or explosions. A casualty occurrence might result in the loss of equipment or life, as well as injury or property damage. Western does not carry insurance with respect to all casualty occurrences and disruptions. There is no assurance that Western's insurance will be sufficient to cover any such casualty occurrences or disruptions, including with respect to the damage caused by the fire at the Mine. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on the Project and on Western's business, financial condition and results of operations. THE ABANDONMENT AND RECLAMATION COSTS RELATING TO THE PROJECT MAY BE HIGHER THAN ANTICIPATED. Western will be responsible for compliance with terms and conditions set forth in the environmental and regulatory approvals for the Project and all present and future laws and regulations regarding the decommissioning and abandonment of the Project and the reclamation of its lands. The costs related to these activities may be substantially higher than anticipated. It is not possible to accurately predict these costs since they will be a function of regulatory requirements at the time and the value of the equipment salvaged. In addition, to the extent Western does not meet the minimum credit rating required under the Joint Venture Agreement by the prescribed time period, Western must establish and fund a reclamation -35- trust fund. Western currently does not hold the minimum credit rating. Even if Western does hold the minimum credit rating, in the future Western may determine that it is prudent or that Western is required by applicable laws or regulations to establish and fund one or more additional funds to provide for payment of future decommissioning, abandonment and reclamation costs. Even if Western concludes that the establishment of such a fund is prudent or required, Western may lack the financial resources to do so. Western may also be required by future regulatory requirements to establish a fund or place funds in trust with regulators for the decommissioning and abandonment of the Project and the reclamation of its lands. THE PROJECT MAY FAIL TO COMPLY WITH VARIOUS ENVIRONMENTAL APPROVALS WHICH MAY EITHER CAUSE THE WITHDRAWAL OF THESE APPROVALS OR IMPOSE OTHER COSTS. The operation and decommissioning of the Project and reclamation of the Project's lands are conditional upon various environmental and regulatory approvals issued by governmental authorities. Further, the operation and decommissioning of the Project and reclamation of the Project's lands will be subject to approvals and present and future laws and regulations relating to environmental protection and operational safety. Risks of substantial costs and liabilities are inherent in oil sands operations, and there can be no assurance that substantial costs and liabilities will not be incurred or that the Project will be permitted by regulators to carry on its operations. Other developments, such as increasingly strict environmental and safety laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the Project's operations, could also result in substantial costs and liabilities to Western, delays in operations or abandonment of the Project. Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other so-called "greenhouse gases". The Project will be a significant producer of some greenhouse gases covered by the treaty. The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas production. Future federal legislation, together with existing provincial emission reduction legislation, such as in Alberta's Climate Change and Emissions Management Act, may require the reduction of emissions and/or emissions intensity from the Project. The direct or indirect costs of such legislation may adversely affect the Project. There can be no assurance that future environmental approvals, laws or regulations will not adversely impact the Owners' ability to operate the Project or increase or maintain production or will not increase unit costs of production. Equipment from suppliers that can meet future emission standards or other environmental requirements may not be available on an economic basis, or at all, and other methods of reducing emissions to required levels may significantly increase operating costs or reduce output. CHANGES IN GOVERNMENT REGULATION OF WESTERN'S OPERATIONS MAY HARM WESTERN. Western's mining, extraction and upgrading operations and the operations of third-party contractors are subject to extensive Canadian federal, provincial and local laws and regulations governing exploration, development, transportation, production, exports, labour standards, occupational health, waste disposal, protection and remediation of the environment, mine safety, hazardous materials, toxic substances and other matters. Amendments to current laws and regulations and the introduction of new laws and regulations governing operations and activities of mining corporations and more stringent application of such laws and regulations are actively considered from time to time and could affect the viability of the Project. There can be no assurance that the various government licenses and approvals or amendments thereto that from time to time may be sought will be granted to the Project at all or with conditions satisfactory to Western or, if granted, will not be cancelled or will be renewed upon expiry or that income tax laws and -36- government incentive programs relating to the Project, and the mining, oil sands and oil and gas industries generally, will not be changed in a manner which may adversely affect Western. Currently, Western benefits from a favourable royalty regime; however, there can be no assurance that this royalty regime will not change in a manner that would adversely affect Western. Lease 13 is subject to the Oil Sands Tenure Regulation (Alberta) which was introduced in 2000. This legislation deems Lease 13 to continue beyond its primary term to the extent that the lessee has attained the minimum level of evaluation of the oil sands in Lease 13 or Lease 13 is producing. There can be no assurance that the Owners will be able to comply with the requirements of the Oil Sands Tenure Regulation (Alberta). In addition, the Minister, in certain circumstances, may change the designation of any lease subject to the legislation and provide notice requiring the Owners to commence production or recovery of, or to increase existing production or recovery of bitumen or other oil sands products within the time specified in such notice. There can be no assurance that if such a notice is given, the Owners will be able to comply with its terms to maintain Lease 13. Additionally, the Oil Sands Tenure Regulation (Alberta) expires on December 1, 2008 and, if such legislation is not renewed in its present or similarly favourable form, the status of Lease 13 may be in question. ABORIGINAL PEOPLES MAY MAKE CLAIMS AGAINST WESTERN OR THE PROJECT REGARDING THE LANDS ON WHICH THE PROJECT IS LOCATED. Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Certain aboriginal peoples have filed a claim against the Government of Canada, certain governmental entities and the City of Fort McMurray, Alberta claiming, among other things, that the plaintiffs have aboriginal title to large areas of lands surrounding Fort McMurray, including the lands on which the Project and most of the other oil sands operations in Alberta are located. Such claims, if successful, could have an adverse effect on the Project. TRANSFER AGENTS AND REGISTRAR Valiant Trust Company at its principal office in Calgary, Alberta is the transfer agent and registrar of the Common Shares of the Corporation and Equity Transfer Services Inc. at its principal office in Toronto, Ontario is the co-agent and registrar of the Common Shares of the Corporation. INTEREST OF EXPERTS Norwest, independent mining consultants to the Corporation, prepared the Norwest Report and GLJ, independent petroleum consultants to the Corporation, prepared the GLJ Report, both referenced herein. As at the date of the respective reports, the principals of each of Norwest and GLJ, as respective groups, owned beneficially, directly or indirectly, less than 1% of the outstanding Common Shares. Neither Norwest nor GLJ received or will receive any interest, direct or indirect, in any securities or other property of Western or its affiliates in connection with the preparation of its report. ADDITIONAL INFORMATION Additional information relating to the Corporation may be found on SEDAR at www.sedar.com. Additional information including directors' and officers' remuneration and indebtedness, principal holders of the Corporation's securities and securities authorized for issuance under equity compensation plans, if applicable, is contained in the Corporation's information circular for its most recent annual meeting of shareholders that involved the election of directors, and additional financial information is provided in the Corporation's comparative financial statements and MD&A for its most recently completed financial year. -37 - GLOSSARY In this Annual Information Form, the following terms shall have the meanings set forth below, unless otherwise indicated: "Albian" Albian Sands Energy Inc., a corporation owned by the Owners in proportion to their ownership interest, which was incorporated for the purposes of acting as the operator of the Mine and the Extraction Plant; "ATCO" ATCO Power Canada Limited; "bbls" Barrels. One barrel equals 0.15891 cubic metres at 15(0) Celsius; "Chevron" Chevron Canada Limited; "Common Shares" The Class A shares of Western; "Dow" Dow Chemicals Canada Inc.; "Executive Committee" The executive committee appointed under the Joint Venture Agreement which has the responsibility for managing the Project and which is comprised of two representatives of each of the Owners; "Extraction Plant" The extraction facilities are located on the western portion of Lease 13 which are designed to separate crude bitumen from the oil sands and process such crude bitumen so that it may be transported by pipeline to the Scotford Upgrader; "Extraction Plant Start-up" That time when the Extraction Plant has operated at not less than 85% of its design capacity for a period of 30 consecutive days and any construction deficiencies and defects have been rectified to the satisfaction of the Owners; "GLJ" Gilbert Laustsen Jung Associates Ltd., independent petroleum consultants; "GLJ Report" The report prepared by GLJ dated March 24, 2005 evaluating the reserves attributable to Western as of December 31, 2004; "HMU" The hydrogen manufacturing unit which supplies hydrogen to the Upgrader; "Joint Venture" The unincorporated joint venture created by the Owners pursuant to the Joint Venture Agreement to undertake the Project; "Joint Venture Agreement" or "JVA" The Joint Venture Agreement dated December 6, 1999, among the Owners, as amended; "Lease 13" Bituminous Sands Lease No. 7277080T13 and all renewals, extensions, replacements and amendments thereto, granted to Shell by the Government of Alberta, and transferred to Albian Sands Energy Inc., the western portion of which is the site for the mining and extraction operations of the Project; "MD&A" Management Discussion & Analysis "MM$" Millions of dollars and "M$" thousands of dollars; -38- "MMbbls" Millions of barrels; "Mine" The open pit mine is located on the western portion of Lease 13 and all equipment, machinery, vehicles and facilities used in connection therewith; "Non-voting Convertible Equity Shares" The non-voting convertible Class B equity shares of Western each convertible into one Common Share in certain circumstances subject to adjustment, at no additional cost; "Norwest" Norwest Corporation, independent mining consultants; "Norwest Report" The report prepared by Norwest dated January 18, 2000 and confirmed by a further report dated March 6, 2001 that considered additional exploration data and geological information acquired after August 1, 1999; "Notes" Western's senior secured notes having a principal amount of US$450 Million bearing interest at a rate of 8.375% per annum and maturing on May 1, 2012; "Owners" The owners of undivided ownership interests in the Project which include Shell, as to a 60% undivided ownership interest, Chevron, as to a 20% undivided ownership interest, and Western, as to a 20% undivided ownership interest; "Project" The design and construction of facilities and implementation of operations of the Mine, the Extraction Plant, the Upgrader and all other facilities necessary to mine, extract, transport and upgrade crude bitumen from the oil sands deposits on the western portion of Lease 13; "Project Start-up" That time when the main Project facilities have operated at not less than 85% of their design capacity for a period of 30 consecutive days and any construction deficiencies and defects have been rectified to the satisfaction of the Owners; "Scotford Refinery" The oil refinery owned by Shell Products Canada Limited which is located near Fort Saskatchewan, Alberta and which is adjacent to the location of the Scotford Upgrader; "Scotford Upgrader" or "Upgrader" The oil sands bitumen upgrader which processes diluted bitumen product from the Extraction Plant to produce refinery feed stocks for sale to Shell Products Canada Limited at the Scotford Refinery and synthetic crude oil for shipment to other North American refineries; "Senior Credit Facility" The credit facility between the Corporation and certain lending institutions which, prior to repayment, provided a portion of the capital costs of the Project and which facility also included debt service and cost overrun facilities; "Shell" Shell Canada Limited; and "Shell's Other Athabasca Leases" Alberta Crown Oil Sands Lease Nos. 7288080T88, 7288080T89, 7288080T90, 7280050T26, 7281010T93, 7281030T53, 7281030T45, 7280080T28, 7400120009, 7401100017 and all renewals, extensions, replacements and amendments in respect of same, granted to Shell by the Government of Alberta. -39- APPENDIX A REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR To the board of directors of Western Oil Sands Inc. (the "Corporation"): 1. We have prepared an evaluation of the Corporation's reserves data as at December 31, 2004. The reserves data consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004, using forecast prices and costs; and (ii) the related estimated future net revenue; and (b) (i) proved oil and gas reserves estimated as at December 31, 2004, using constant prices and costs; and (ii) the related estimated future net revenue. 2. The reserves data are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the reserves data based on our evaluation. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). 3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook. 4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Corporation's board of directors:
Location of Description and Reservesr Preparation Date of (Country or Evaluation Foreign Net Present Value of Future Net Revenue Geographic (before income taxes, 10% discount rate) ----------------------------------------------------------- Report Area) Audited Evaluated Reviewed Total ------ ----- ------- --------- -------- ----- March 11, 2005 Canada 0 2,331.2 MM$ 0 2,331.2 MM$
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. 6. We have no responsibility to update the evaluation referred to in paragraph 4 for events and circumstances occurring after the preparation dates. -40- 7. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. Executed as to our report referred to above: Gilbert Laustsen Jung Associates Ltd., Calgary, Alberta, Canada Dated March 29, 2005 /s/ James H. Willmon, P. Eng. ----------------------------- James H. Willmon, P. Eng. Vice-President APPENDIX B REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION Management of Western Oil Sands Inc. (the "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporation's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and (ii) the related estimated future net revenue; and (b) (i) proved oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and (ii) the related estimated future net revenue. An independent qualified reserves evaluator has evaluated the Corporation's reserves data. The report of the independent qualified reserves evaluator is presented in Appendix A to this Annual Information Form. The Audit Committee of the Board of Directors of the Corporation has: (a) reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator; (b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and (c) reviewed the reserves data with management and the independent qualified reserves evaluator. The Audit Committee of the Board of Directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Audit Committee, approved (a) the content and filing with securities regulatory authorities of the reserves data and other oil and gas information; (b) the filing of the report of the independent qualified reserves evaluator on the reserves data; and (c) the content and filing of this report. -2- Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. /s/ Guy J. Turcotte, President and Chief Executive Officer /s/ John Frangos, Executive Vice President and Chief Operating Officer /s/ Robert G. Puchniak,, Director /s/ Mac H. Van Wielingen, Director March 30, 2005 -3- APPENDIX C AUDIT COMMITTEE CHARTER PURPOSE The purpose of the Audit Committee of the Board is to assist the Board in fulfilling its oversight responsibilities in relation to the review and approval of the financial statements and financial reporting of the Corporation and the assessment of internal control and management information and the risk management systems and procedures of the Corporation. The Audit Committee shall also be directly responsible for overseeing all audit processes and the relationship of the external auditors with the Corporation and the external auditors shall report directly, and be accountable, to the Audit Committee. The role of the Audit Committee is one of supervision, stewardship and oversight. Management is responsible for preparing the financial statements and financial reporting of the Corporation and for maintaining internal control and management information and risk management systems and procedures. The external auditors are responsible for the audit or review of the financial statements and other services they provide. MANDATE 1. Financial Statements and Financial Reporting. The Audit Committee shall: (a) review with management and the external auditors, and recommend to the Board for approval, the annual financial statements of the Corporation, the reports of the external auditors thereon and related financial reporting, including Management's Discussion and Analysis and earnings press releases prior to the public disclosure of such information; (b) review with management and the external auditors, and recommend to the Board for approval, the interim financial statements of the Corporation and related financial reporting, including Management's Discussion and Analysis and earnings press releases prior to the public disclosure of such information; (c) review with management and recommend to the Board for approval, the Corporation's Annual Information Form; (d) review with management and recommend to the Board for approval, any financial statements of the Corporation which have not previously been approved by the Board and which are to be included in a prospectus of the Corporation; (e) consider and be satisfied that adequate procedures are in place for the review of the Corporation's public disclosure of financial information extracted or derived from the Corporation's financial statements (other than disclosure referred to in clauses (a) and (b) above), and periodically assess the adequacy of such procedures; (f) review with management, the external auditors and, if necessary, legal counsel, any litigation, claim or contingency, including tax assessments, that could have a material effect upon the financial position of the Corporation, and the manner in which these matters may be, or have been, disclosed in the financial statements; (g) review the appropriateness of the accounting practices and policies of the Corporation and review any proposed changes thereto; -4- (h) review and discuss any new or pending developments in accounting and reporting standards that may affect the Corporation; and (i) review accounting, tax and financial aspects of the operations of the Corporation as the Audit Committee considers appropriate. 2. Relationship with External Auditors. The Audit Committee shall: (a) consider and make a recommendation to the Board as to the appointment or re-appointment of the external auditors, ensuring that such auditors are participants in good standing pursuant to applicable securities laws; (b) consider and make a recommendation to the Board as to the compensation of the external auditors; (c) review and approve the annual audit plan of the external auditors (including without limitation, engagement letters, objectives and scope of the external audit word, procedures for quarterly review of financial statements, materiality limits, areas of audit risk, staffing, timetables and proposed fees); (d) oversee the work of the external auditors in performing their audit or review services and oversee the resolution of any disagreements between management and the external auditors; (e) review and discuss with the external auditors all significant relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors' independence, including, without limitation, (A) requesting, receiving and reviewing, on a periodic basis, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on the independence of the external auditors with respect to the Corporation, (B) discussing with the external auditors any disclosed relationships or services that the external auditors believe may affect the objectivity and independence of the external auditors, and (C) recommending that the Board take appropriate action in response to the external auditors' report to satisfy itself of the external auditors' independence; (f) as may be required by applicable securities laws, rules and guidelines, either: (i) pre-approve all non-audit services to be provided by the external auditors to the Corporation (or its subsidiaries, if any), or, in the case of de minimus non-audit services, approve such non-audit services prior to the completion of the audit; or (ii) adopt specific policies and procedures for the engagement of the external auditors for the purpose of the provision of non-audit services; (g) be satisfied that the fees paid by the Corporation to the external auditors for audit and non-audit services are publicly disclosed; and -5- (h) review and approve the hiring policies of the Corporation regarding partners, former partners, employees and former employees of the present and former external auditors of the Corporation. 3. Relationship with Independent Reserve Engineers. The Audit Committee shall: (a) review the selection and qualifications of the independent engineering firm responsible for estimation of reserves (the "Reserves Engineers"), the scope of the Reserves Engineers' work and ensure the consistency of its practices, standards and definitions; (b) review directly with the independent engineering firm the evaluation report and corporate summary of the reserves and future cash flows of the properties owned by the Corporation; (c) review externally disclosed oil and gas reserve estimates and ensure they meet the requirements of the Alberta Securities Commission and/or any other relevant regulatory body; (d) review the Corporation's practices against the Petroleum Society and Petroleum Evaluation Engineers' Definitions and Guidelines of Estimating and Classifying Oils and Gas Reserves and any relevant "best practice" guidelines and make recommendations to the Board as required; (e) periodically review the Corporation's relationship with the Reserves Engineers (f) maintain direct communication with the Reserves Engineers and the Corporation's senior reserve personnel; and (g) assist the Board in respect of matters related to evaluations of petroleum and natural gas reserves. 4. Internal Controls. The Audit Committee shall: (a) review with management and the external auditors, the adequacy and effectiveness of the internal control and management information systems and procedures of the Corporation (with particular attention given to accounting, financial statements and financial reporting matters and to being satisfied that such systems are reliable and that they operate effectively to produce accurate, appropriate and timely management and financial information) and determine whether the Corporation is in compliance with applicable legal and regulatory requirements and with the Corporation's policies; (b) provide the Board with an independent mechanism for reviewing reserves; (c) review the external auditors' recommendations regarding any matters, including internal control and management information systems and procedures, and management's responses thereto; -6- (d) establish procedures for the receipt, retention and treatment of complaints, submissions and concerns regarding accounting, internal accounting controls or auditing matters on an anonymous and confidential basis; (e) review policies and practices concerning the expenses and perquisites of the Chairman, including the use of the assets of the Corporation; (f) review with external auditors any corporate transactions in which directors or officers of the Corporation have a personal interest; (g) review insurance coverage of significant business risks and uncertainties; (h) review material litigation and its impact on financial reporting; and (i) review policies and procedures for the review and approval of officers' expenses and perquisites. 5. Financial Risk Management. The Committee shall: (a) review with management and the external auditors their assessment of significant financial risks and exposures; (b) review and assess the steps that management has taken to mitigate such risks; and (c) report the results of such reviews to the Board for the purpose of assisting the Board in identifying the principal business risks associated with the businesses of the Corporation. Composition and Procedures 1. Composition of Committee. The Audit Committee shall consist of not less than three directors, none of whom shall be an officer or employee of the Corporation or any of its subsidiaries or any affiliate thereof. Each Audit Committee member shall satisfy the independence and financial literacy requirements of applicable securities laws, rules or guidelines, any applicable stock exchange requirements or guidelines and any other applicable regulatory rules. In addition, the Chair shall have "accounting or related financial expertise". The Board has defined "financial literacy" as the ability to understand a balance sheet, income statement and a cash flow statements in accordance with Canadian GAAP and the Board has defined "accounting or financial expertise" as the ability to analyze and understand a full set of financial statements, including the notes attached thereto in accordance with Canadian GAAP. Each member of the Audit Committee shall have no direct or indirect material relationship with the Corporation or any affiliate thereof which could reasonably be expected to interfere with the exercise of the member's independent judgment, other than interests and relationships arising from the holdings of shares of the Corporation. Determinations as to whether a particular director satisfies the requirements for membership on the Audit Committee shall be made by the full Board. 2. Appointment of Committee Members Members of the Audit Committee shall be appointed from time to time and shall hold office at the pleasure of the Board. Where a vacancy occurs at any time in the membership of the Audit -7- Committee, it may be filled by the Board. The Board shall fill any vacancy if the membership of the Audit Committee is less than three directors. 3. Absence of Committee Chair If the Chair of the Audit Committee is not present at any meeting of the Audit Committee, one of the other members of the Audit Committee who is present at the meeting shall be chosen by the Audit Committee to preside at the meeting. 4. Authority to Engage Experts The Audit Committee has the authority to engage independent counsel and other advisors as it determines necessary to carry out its duties and to set the compensation for any such counsel and advisors, such engagement to be at the Corporation's expense. 5. Meetings The Audit Committee shall meet at least four times per year and shall meet at such other times during each year as it deems appropriate. In addition, the Chair of the Audit Committee may call a special meeting of the Audit Committee at any time. The Audit Committee shall meet with the external auditors on a regular basis in the absence of management and, if so requested by a member of the Audit Committee, the external auditor shall attend every meeting of the Audit Committee held during the term of office of the external auditor. The Chair of the Audit Committee, the Chairman of the Board, any two members of the Audit Committee or the external auditors may call a meeting of the Audit Committee. The external auditors shall be provided with notice of every meeting of the Audit Committee and, at the expense of the Corporation, shall be entitled to attend and be heard thereat. The Chair of the Audit Committee shall hold in camera meetings of the Audit Committee, without management present, at every Audit Committee meeting. 6. Quorum A majority of the members of the Audit Committee shall constitute a quorum. 7. Procedure, Records and Reporting Subject to any statute or the articles and by-laws of the Corporation, the Audit Committee shall fix its own procedures at meetings, keep records of its proceedings and report to the Board when the Audit Committee may deem appropriate (but not later than the next meeting of the Board). 8. Delegation The Audit Committee may delegate from time to time to any person or committee of persons any of the Audit Committee's responsibilities that lawfully may be delegated. 9. Review of Terms of Reference The Audit Committee shall review and reassess the adequacy of its Terms of Reference at least annually, and otherwise as it deems appropriate, and recommend changes to the Board. Such review shall include the evaluation of the performance of the Audit Committee against criteria defined in the Audit Committee mandate as well as the Directors' Charter.