EX-2 4 o10068exv2.txt ANNUAL INFORMATION FORM EXHIBIT 2 HAWKER RESOURCES INC. RENEWAL ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2002 MAY 20, 2003 TABLE OF CONTENTS GLOSSARY OF TERMS......................................................................................... 1 ABBREVIATIONS............................................................................................. 3 CONVERSION................................................................................................ 3 FORWARD-LOOKING STATEMENTS................................................................................ 3 ITEM 1: CORPORATE STRUCTURE............................................................................... 5 1.1 Name and Incorporation........................................................................... 5 1.2 Intercorporate Relationships..................................................................... 5 ITEM 2: GENERAL DEVELOPMENT OF THE BUSINESS............................................................... 5 2.1 History.......................................................................................... 5 2.2 Significant Acquisitions and Significant Dispositions............................................ 7 2.3 Trends........................................................................................... 8 ITEM 3: NARRATIVE DESCRIPTION OF THE BUSINESS............................................................. 10 3.1 General.......................................................................................... 10 3.2 Corporate Strategy............................................................................... 12 3.3 Business Strengths............................................................................... 12 3.4 Drilling Activity................................................................................ 13 3.5 Location of Production........................................................................... 13 3.6 Location of Wells................................................................................ 14 3.7 Land Holdings.................................................................................... 15 3.8 Reserve Estimates................................................................................ 15 3.9 Reconciliation of Reserves....................................................................... 17 3.10 Production History............................................................................... 18 3.11 Netback History.................................................................................. 18 3.12 Capital Expenditures............................................................................. 18 3.13 Future Commitments............................................................................... 19 ITEM 4: SELECTED CONSOLIDATED FINANCIAL INFORMATION....................................................... 20 4.1 Annual Information............................................................................... 20 4.2 Quarterly Information............................................................................ 21 4.3 Dividend Policy.................................................................................. 21 ITEM 5: MANAGEMENT'S DISCUSSION AND ANALYSIS.............................................................. 21 ITEM 6: MARKET FOR SECURITIES............................................................................. 26 ITEM 7: DIRECTORS AND OFFICERS............................................................................ 26 ITEM 8: ADDITIONAL INFORMATION............................................................................ 27
GLOSSARY OF TERMS In this document, unless the context otherwise requires, the following words and phrases shall have the meanings set forth below: "2% DEBENTURE" means a debenture of the Corporation issued as part of the Financing on April 3, 2003 in the principal amount of $8.40, bearing interest at the rate of 2% per annum from the date of issue payable on the earlier of the maturity date of December 31, 2003 and the date of surrender; "ARRANGEMENT" means the arrangement involving BidCo and Southward pursuant to section 193 of the Business Corporations Act (Alberta) completed on April 30, 2003; "ARTC" means Alberta Royalty Tax Credit; "BIDCO" means 1022971 Alberta Ltd., all of the outstanding shares of which were acquired by the Corporation for an aggregate consideration of $1.00 on March 31, 2003; "CLASS A SHARE" means a class A share in the capital of the Corporation; "COMMON SHARE" means a common share in the capital of the Corporation; "CONVERSION" means the deemed exercise of all of the Warrants which will occur immediately after the issuance of a receipt for a prospectus of the Corporation qualifying the issuance of up to $45,000,000 of Common Shares and pursuant to which the former holders of the Warrants will be issued, for each Warrant, 5 Common Shares and 9 Class A Shares upon the surrender of 5 Series V Shares, 9 Series W Shares and one 2% Debenture; "CORPORATION" OR "HAWKER" means Hawker Resources Inc.; "EQUITY SHARES" means Common Shares and Class A Shares; "ESTABLISHED RESERVES" means proved reserves plus risked probable reserves; "FINANCECO" means 970183 Alberta Ltd., a wholly owned subsidiary of Matco; "FINANCING" means the financing completed by the Corporation on April 3, 2003 pursuant to which the Corporation issued 223,798 Common Shares and 430,493 Units for aggregate gross proceeds of approximately $3.7 million (which Units will be converted to 6,026,902 Equity Shares pursuant to the Conversion); "GROSS" means Hawker's working interest or royalty interest share of reserves or production, as the case may be, before the deduction of royalties and, with respect to land and wells, means the total number of acres or wells, as the case may be, in which Hawker has a working interest or a royalty interest; "MATCO" means Matco Investments Ltd.; "MATCO CAPITAL" means Matco Capital Ltd., a corporation controlled by Matco; "McDANIEL" means McDaniel and Associates Consultants Ltd., independent oil and natural gas reservoir engineers; "McDANIEL REPORT" means the engineering report prepared by McDaniel evaluating the crude oil, natural gas liquids and natural gas reserves attributable to a 50% undivided interest in the Optioned Properties effective as of May 1, 2003 based upon detailed engineering evaluations made by McDaniel effective as of January 1, 2003, adjusted to take into account actual and estimated production from January 1, 2003 to May 1, 2003 and based on an engineering evaluation of wells drilled from January 1, 2003 to May 1, 2003, and which was prepared on the basis of both constant and escalating price and cost assumptions as detailed in the notes under "Narrative Description of the Business - Reserve Estimates"; - 2 - "NET" means Hawker's working interest share of production or reserves, as the case may be, after the deduction of royalties, and, with respect to land and wells, means Hawker's working interest share therein; "OPTIONED PROPERTIES" means all of the petroleum and natural gas rights and related assets of Southward other than those which are both west of the fifth meridian and in the Province of Alberta, as described under the heading" Narrative Description of the Business - Location of Production"; "PROBABLE ADDITIONAL RESERVES" means those reserves which an analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future; "PROVED RESERVES" means those reserves estimated as recoverable under current technology and existing economic conditions from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir; "PURCHASE OPTION" means the option in favour of the Corporation to purchase an undivided interest of up to 49% in the Optioned Properties at a purchase price based on an ascribed price, as at May 1, 2003 and subject to adjustment, of $136,900,000 for a 100% interest in the Optioned Properties; "RISKED PROBABLE RESERVES" means probable additional reserves discounted by one-half to account for the additional risk of recovery for probable reserves; "ROYALTY INTEREST" means an interest in an oil and gas property consisting of a royalty granted in respect of production from the property; "SERIES V SHARE" means a series V voting preferred share in the capital of the Corporation; "SERIES W SHARE" means a series W non-voting preferred share in the capital of the Corporation; "SOUTHWARD" means Southward Energy Ltd.; "STATEMENTS OF REVENUES AND OPERATING EXPENSES" means the statements of revenues and operating expenses relating to the proposed acquisition by the Corporation of an aggregate 50% undivided interest in the Optioned Properties audited by Deloitte & Touche LLP. "TSX" means the Toronto Stock Exchange; "TAX ACT" means the Income Tax Act (Canada); "UNIT" means a Unit issued by the Corporation on April 3, 2003 pursuant to the Financing for a subscription price of $8.46787851 per Unit consisting of: (i) a 2% Debenture; (ii) a Warrant; (iii) 5 Series V Shares; and (iv) 9 Series W Shares; "WARRANT" means a series A warrant of the Corporation which entitles the holder thereof to purchase 5 Common Shares and 9 Class A Shares upon the surrender of 5 Series V Shares and 9 Series W Shares and either the surrender of a 2% Debenture or the payment of $8.40. Pursuant to the Conversion, all of the Warrants will be deemed to be exercised immediately after a receipt is issued for a prospectus of the Corporation qualifying the issuance of up to $45,000,000 of Common Shares and upon such deemed exercise, the holders thereof will be deemed to have surrendered one 2% Debenture to the Corporation; - 3 - "WORKING INTEREST" means the percentage undivided interest held by a party in an oil and gas property; and UNLESS OTHERWISE INDICATED, REFERENCES HEREIN TO "$" OR "DOLLARS" ARE TO CANADIAN DOLLARS. ABBREVIATIONS
CRUDE OIL AND NATURAL GAS LIQUIDS NATURAL GAS --------------------------------- ----------- bbls barrels mcf thousand cubic feet bbls/d barrels per day mmcf million cubic feet mbbls thousand barrels bcf billion cubic feet boe barrels of oil equivalent of natural gas mcf/d thousand cubic feet per day and crude oil on the basis of 1 bbl of mmcf/d million cubic feet per day crude oil for 6 mcf of natural gas GJ gigajoules boe/d barrels of oil equivalent per day GJ/d gigajoules per day mboe thousand boe NGLs natural gas liquids mmbtu million British thermal units stb standard stock tank barrel
CONVERSION The following table sets forth certain standard conversions from Standard Imperial units to the International System of Units (or metric units).
TO CONVERT FROM TO MULTIPLY BY ----------------------------------------------------------------------------- mcf Thousand cubic metres ("10(3)m(3)") 0.0282 Thousand cubic metres mcf 35.494 bbls Cubic metres ("m(3)") 0.159 Cubic metres bbls 6.290 Feet Metres 0.305 Metres Feet 3.281 Miles Kilometres 1.609 Kilometres Miles 0.621 Acres Hectares 0.405 Hectares Acres 2.471
FORWARD-LOOKING STATEMENTS Certain statements contained in this document constitute forward-looking statements. When used in this document, the words "may", "would", "could", "will", "intend", "plan", "anticipate", "believe", "seek", "propose", "estimate", "expect", and similar expressions, as they relate to the Corporation, are intended to identify forward-looking statements. Such statements reflect the Corporation's current views with respect to future events and are subject to certain risks, uncertainties and assumptions, including, without limitation, those described in this Annual Information Form under the headings "Narrative Description of the Business", "Selected Consolidated Financial Information" and "Management's Discussion and Analysis". In particular, this document contains forward-looking statements pertaining to the following: - the quantity of the Corporation's reserves; - oil and natural gas production levels; - capital expenditure programs; - projections of market prices and costs; - supply and demand for oil and natural gas; - 4 - - expectations regarding the Corporation's ability to raise capital and to continually add to reserves through acquisitions and development; and - treatment under governmental regulatory regimes. The Corporation's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this document: - volatility in market prices for oil and natural gas; - liabilities and risks inherent in oil and gas operations; - uncertainties for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; - incorrect assessments of the value of acquisitions; and - geological, technical, drilling and processing problems. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. Although the Corporation believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Furthermore, the forward-looking statements contained in this document are made as of the date of this document, and the Corporation undertakes no obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement. - 5 - ITEM 1: CORPORATE STRUCTURE 1.1 NAME AND INCORPORATION Hawker was incorporated as 599386 Alberta Ltd. under the Business Corporations Act (Alberta) on February 14, 1994 and changed its name to SYNSORB Biotech Inc. by Articles of Amendment filed on March 31, 1994. Effective May 8, 2002: (i) each former holder of common shares received one new common share for each eight cancelled common shares they previously held; (ii) the stated capital of the Corporation was reduced in respect of the common shares of the Corporation by $59,896,000; and (iii) 4,000,235 common shares of Oncolytics Biotech Inc. held by the Corporation were distributed to its shareholders. By Articles of Amendment filed on April 3, 2003, the name of the Corporation was changed to Hawker Resources Inc. and a new class of non-voting equity shares was created. The Common Shares of Hawker are listed for trading on the Toronto Stock Exchange under the symbol "HKR". The head office of the Corporation is located at 3200, 350 - 7th Avenue S.W., Calgary, Alberta, T2P 3N9, and the registered office is located at 4500, 855 - 2nd Street S.W., Calgary, Alberta, T2P 4K7. 1.2 INTERCORPORATE RELATIONSHIPS Hawker owns, directly or indirectly, all of the issued and outstanding securities of BidCo and Southward, both companies incorporated under the Business Corporations Act (Alberta) and registered to carry on business in Alberta. Hawker also owns, directly or indirectly, all interests of Southward Energy Partnership, a partnership formed under the laws of Alberta. ITEM 2: GENERAL DEVELOPMENT OF THE BUSINESS 2.1 HISTORY Prior to December 10, 2001, the Corporation was a biotechnology company focusing primarily on the discovery and development of pharmaceutical products for gastroenteric diseases. On that date, the Corporation announced that it was terminating the clinical trials of its remaining product and would consider future strategic alternatives. Over the course of the fiscal year ended December 31, 2002, the Corporation divested itself of its position in Oncolytics Biotech Inc. by distributing 4,000,235 of such shares to its shareholders and by selling 2,255,565 of such shares through the TSX for aggregate gross proceeds of $6,898,000. During that period, the Corporation completed staff reductions and the winding-down of its clinical trials and continued to evaluate strategic alternatives. The Corporation held discussions with several industry parties in an attempt to reach a transaction with another pharmaceutical entity that would make use of the Corporation's technology and its specialized manufacturing plant and equipment. These discussions did not lead to the Corporation receiving any acceptable proposal for such a transaction. On October 30, 2002, the Corporation retained Network Capital Inc. as its financial advisor to seek a transaction to maximize value for shareholders, including pursuing transactions that would substantially reorganize the business of the Corporation. - 6 - On November 26, 2002, Southward announced a shareholder value maximization process, established an independent committee to oversee the process and retained a financial advisor. The process initiated by Southward required that binding offers be submitted by interested parties on or prior to March 3, 2003. In late December 2002, the Corporation approached an investor group led by David Tuer with respect to the transformation of the Corporation from a pharmaceutical research company into an oil and gas enterprise and the completion of the Financing. On January 6, 2003, the transformation of the Corporation to an oil and gas enterprise and the proposed Financing were announced, subject to obtaining shareholder approval, which was to be sought at the annual and special meeting of the Corporation on April 3, 2003. In January 2003, the Corporation sold its manufacturing equipment for approximately $900,000 in net proceeds and in February 2003, the Corporation granted a third party an exclusive license to certain of its patents relating to toxin binding sugars for net proceeds of US $240,000. The Corporation is continuing to attempt to sell its manufacturing facility and related land. In early March 2003, BidCo entered into an agreement with a third party which provided, as amended, that in the event that BidCo was successful in purchasing all of the common shares of Southward, the third party would purchase all of the petroleum and natural gas rights and related assets of Southward, except for a 1% interest in the Optioned Properties and 100% of the seismic data relating to the Optioned Properties, for a purchase price of $164,631,000, of which $135,531,000 was allocated for internal purposes to a 99% interest in the Optioned Properties. In mid-March 2003, the Purchase Option was granted which provided the right to purchase an undivided interest of up to 49% in the Optioned Properties at a purchase price, subject to adjustment, equal to $1,369,000 for each 1% undivided interest in the Optioned Properties acquired pursuant to the Purchase Option. The right to exercise the Purchase Option was conditional upon the completion of the sale of the Southward assets to the grantor of the option, which condition was satisfied on April 30, 2003. The Purchase Option provided that it could be assigned to the Corporation, but that it could not be assigned to any other party without the prior written consent of the grantor of the option. On March 16, 2003, BidCo entered into an arrangement agreement with Southward which contemplated that, subject to the terms and conditions of the agreement, BidCo and Southward would implement the Arrangement. The Arrangement provided that: (i) shareholders of Southward would transfer all of the outstanding common shares to BidCo in consideration for $4.77 per share; and (ii) all of the outstanding options to acquire common shares of Southward would be terminated, and in consideration for such termination the former holders of the options would receive the difference between the exercise price of each of their options and $4.77, provided that if such amount was less than $0.10 in respect of any option, the former holder thereof would receive $0.10. On March 31, 2003, the Corporation acquired the Purchase Option and all of the shares of BidCo for an aggregate consideration of $1.00. At the annual and special meeting of the shareholders of the Corporation held on April 3, 2003 a new board of directors was elected, including the appointment of Mr. Tuer, an experienced oil and gas senior executive, as the new Chairman of the Board and Chief Executive Officer of the Corporation, and the shareholders approved, among other things: (i) the Financing; (ii) the creation of the Class A Shares; and (iii) the name change to Hawker Resources Inc. On April 3, 2003, the Corporation completed the Financing and issued 223,798 Common Shares and 430,493 Units for aggregate proceeds of approximately $3.7 million. Pursuant to the Conversion, the - 7 - securities which comprise the Units will be converted into an aggregate of 6,026,902 Equity Shares immediately after a receipt is issued for a prospectus of the Corporation qualifying the issuance of up to $45,000,000 of Common Shares. Pursuant to the Financing, Matco Capital and Mr. Tuer beneficially acquired 28.8% and 14.4%, respectively, of the outstanding Equity Shares, after giving effect to the Conversion. During the period of March 13, 2003 to April 3, 2003, all outstanding in-the-money stock options were exercised, resulting in the issuance of an additional 275,000 Common Shares for aggregate proceeds of $192,250. On April 28, 2003 the Arrangement was approved by the shareholders and optionholders of Southward and was also approved by the Court of Queen's Bench of Alberta. On April 30, 2003, the Arrangement was completed by Southward and BidCo in accordance with the arrangement agreement. Pursuant to the Arrangement, BidCo paid an aggregate of approximately $120 million to the shareholders and optionholders of Southward and Southward became a wholly owned subsidiary of BidCo. Concurrent with the completion of the Arrangement, Southward completed the sale of all of its oil and gas assets, with the exception of: (i) a 1% interest in the Optioned Properties; and (ii) 100% of the seismic data relating to the Optioned Properties, which were retained by Southward. Gross proceeds from the sale were $164,631,000, which were used by Southward as follows: (i) $46 million was used by Southward to repay existing bank indebtedness, including bank indebtedness incurred in connection with the termination of options and satisfaction of various employee obligations and transaction expenses; (ii) $117 million was advanced to BidCo to repay indebtedness incurred to acquire the common shares of Southward and compensate the holders of terminated options pursuant to the Arrangement; and (iii) the remaining proceeds of approximately $1.6 million were retained by Southward. Prior to the completion of the Arrangement, the Corporation granted a call option which gives the purchaser of the oil and gas assets of Southward the right to acquire from the Corporation a 99% interest in the seismic data in respect of the Optioned Properties, for a purchase price of $3,710,000. If this call option is exercised, and the Corporation exercises the Purchase Option, in whole or in part, the Corporation will be required to purchase an equivalent proportion of the seismic data in respect of the Optioned Properties at a purchase price based on an ascribed price of $4 million for a 100% interest in the seismic data. 2.2 SIGNIFICANT ACQUISITIONS AND SIGNIFICANT DISPOSITIONS As discussed above, the Corporation has indirectly acquired all of the issued and outstanding securities of Southward pursuant to the Arrangement and, in conjunction therewith, was granted the Purchase Option. The Purchase Option gives the Corporation the right to purchase an undivided interest of up to 49% in the Optioned Properties, which together with the 1% undivided interest held by the Corporation in the Optioned Properties will give the Corporation an aggregate 50% undivided interest in the Optioned Properties upon the full exercise of the option. The Optioned Properties are located east of Edmonton in the Lavoy and Cold Lake/Bonnyville areas of Alberta. The McDaniel Report estimates production for the last 8 months of 2003 from a 50% undivided interest in the Optioned Properties to be held by the Corporation to be an average of 19.0 mmcf/d, before royalties. Production from the Optioned Properties consists of sweet dry gas, with drilling depths typically less than 850 metres. The Optioned Properties include interests in 164.0 producing gas wells (141.2 wells net), related facilities and gathering systems, associated seismic and 284,325 acres (140,523 acres net) of undeveloped land. The Purchase Option provides that the purchase price for the undivided interest in the Optioned Properties to be acquired by the Corporation will be based on an ascribed price, as at May 1, 2003 and subject to adjustment, of $136,900,000 for 100% of the Optioned Properties. The Purchase Option gives the Corporation the right to purchase an undivided interest of up to 49% in the Optioned Properties for a - 8 - maximum purchase price of $67,081,000. The Corporation intends to fully exercise the Purchase Option and thereby own an aggregate 50% undivided interest in the Optioned Properties. The Purchase Option provides that the closing of the acquisition of the Optioned Properties must occur on or prior to July 29, 2003 with an effective date of May 1, 2003. Accordingly, the Corporation will be entitled to the revenues attributable to the undivided interest acquired in the Optioned Properties from May 1, 2003, and will be obligated to pay interest on the purchase price from May 1, 2003 until closing at an interest rate equal to the prime rate of a designated Canadian chartered bank plus 1%. The Corporation currently intends to exercise the Purchase Option on or before June 30, 2003. The McDaniel Report estimates that the cash flows attributable to the 49% interest in the Optioned Properties the Corporation intends to acquire on the exercise of the Purchase Option, net of royalties and capital expenditures and before income taxes, would be an aggregate of $5.3 million from May 1, 2003 to June 30, 2003. Interest on the purchase price under the Purchase Option as of June 30, 2003 would be approximately $670,810. Accordingly, the Corporation anticipates a favourable purchase price adjustment, based upon an anticipated June 30, 2003 closing of the purchase of the 49% interest in the Optioned Properties pursuant to the exercise of the Purchase Option, of approximately $4.63 million thereby effectively reducing the purchase price from approximately $67.1 million to approximately $62.5 million. The Purchase Option provides that if the Corporation acquires an undivided interest in the Optioned Properties equal to or greater than 33 1/3%, it will be entitled to operate the Optioned Properties located in the Cold Lake/Bonnyville area. As the Corporation will hold an aggregate 50% interest in the Optioned Properties upon the closing of this offering, the Corporation intends to assume operatorship of the Optioned Properties in the Cold Lake/Bonnyville area. The Corporation believes that the Optioned Properties have undeveloped potential and accordingly the Corporation intends to pursue exploration and development activities in the area with a view to developing additional reserves. There can be no assurance that such activities will be economically successful. 2.3 TRENDS Commodity Price Volatility Crude oil and natural gas prices are volatile and subject to a number of external factors. Prices are cyclical and fluctuate as a result of shifts in the balance between supply and demand for crude oil and natural gas, world and North American market forces, inventory and storage levels, OPEC policy, weather patterns and other factors. In early 2002, the industry initially saw a general weakening of prices for both oil and natural gas. However, through the second half of the year, commodity prices rebounded above historical averages. Currently, tight supply/demand balance has kept prices high for both crude oil and natural gas. Crude oil is influenced by a world economy and OPEC's ability to adjust supply to world demand. Recent success by OPEC and low North American crude stocks have kept crude oil prices high. However, the Corporation expects world prices of crude oil to decrease to historical average levels of approximately US $24 per barrel (WTI), but also expect continued global political factors to hold prices at those levels. Natural gas prices are greatly influenced by market forces in North America. It is generally believed that natural gas has greater stability than crude oil in terms of short-term pricing as there is a shortage of natural gas production and natural gas storage levels are low. The Corporation expects natural gas prices to moderate somewhat through 2003, but expect the supply of North American natural gas to continue to be constrained by North American production decline rates. - 9 - Industry Consolidation and Competition Over the past few years, consolidation within the Canadian oil and gas industry has resulted in a significant reduction of the number of junior to intermediate-sized exploration and production companies. American companies have also been acquiring companies and assets in Canada. The strong demand for natural gas production and reserves is expected to result in a continued high level of corporate and asset transactions as buyers strive to increase their natural gas assets and sellers take advantage of high transaction prices. Along with this merger and acquisition activity, a number of traditional exploration and production companies have recently converted into income or royalty trusts. This trend, which has increased competition for investment dollars and property acquisitions, is expected to continue in the short-term. As occurred in 2000 and early 2001, the strength of commodity prices resulted in significantly increased operating cash flows and has led to increased drilling activity. The Canadian Association of Oilwell Drilling Contractors forecasts an 11% increase in industry drilling in 2003, approaching the number of wells drilled in 2001, which was a record year. This industry activity will increase competition for oilfield goods and services and may cause drilling and operating costs to increase. Provincial Royalties and Incentives For crude oil, natural gas and related product production from federal or provincial Crown lands, the royalty regime is a significant factor in the profitability of such production operations. Royalties payable on production from lands other than Crown lands are determined by negotiations between the freehold mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on the type of product being produced, well productivity, geographical location and field discovery date. From time to time the various provincial governments in western Canada have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration and development. The trend in recent years has been for provincial governments to allow such programs to expire without renewal, and consequently few such programs are currently operative. Crude oil and natural gas royalty holidays for specific wells and royalty reduction reduce the amount of Crown royalties paid by the Corporation to the provincial governments. In Alberta, the Alberta royalty tax credit program also provides a rebate, to certain eligible producers, on Alberta Crown royalties paid in respect of eligible producing properties. These incentives result in increased profitability from operations of the Corporation. Government Regulation The oil and natural gas industry is subject to extensive controls and regulation imposed by various levels of government. In western Canada, the various provincial governments have legislation and regulations, which govern land tenure, royalties, production rates, environmental protection, the prevention of waste and other matters. It is not expected that these controls and regulation will affect the operations of the Corporation in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments may be enacted. - 10 - Environmental The Corporation believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. The Corporation is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment. Kyoto Protocol In December 2002, Canada became a signatory to the Kyoto Protocol. This international treaty establishes commitments to reduce emissions of greenhouse gases that are believed to be responsible for increasing the surface temperatures of the Earth and affecting the global climate. The U.S. Government's decision to withdraw from the Kyoto Protocol may have serious implications for Canada in the context of a continental or hemispheric energy market, but the U.S. is expected to develop a strategy to reduce greenhouse gases, perhaps using the NAFTA model. Early indications from the Government of Canada's policy commitments are that Canada's ratification will not significantly penalize the oil and gas industry. Some uncertainly will remain until the Federal government provides its detailed implementation plan and it becomes clearer what the effect will be on business economics, primarily on the cost site. However, the Corporation does not expect ratification of the Kyoto Protocol to have a material effect on its performance in 2003. ITEM 3: NARRATIVE DESCRIPTION OF THE BUSINESS 3.1 GENERAL The Corporation is a publicly traded Canadian company listed on the TSX that has recently transformed itself from a pharmaceutical research company into an oil and gas enterprise. The Corporation intends to report the financial results of its oil and gas activities as one industry segment. For operational purposes, the Corporation intends to manage all of its oil and gas activities as one integrated unit. Competitive Conditions The oil and gas industry is highly competitive. The Corporation will compete for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than the Corporation. The Corporation's competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators. The Corporation's ability to increase reserves in the future will depend not only on its ability to explore and develop its properties, but also on its ability to select and acquire suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. The Corporation's ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with its future industry partners and joint operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. Seasonally The Corporation expects to have seasonal impacts with regard to its exploration and development program. The Corporation expects to experience reduced activity in the second quarter of the fiscal year - 11 - as limitations on the transportation of heavy equipment on municipal roads curtails the ability of drilling rigs and other oilfield equipment to get to and from well sites. Government Regulation The oil and natural gas industry is subject to extensive controls and regulation imposed by various levels of government. In western Canada, the various provincial governments have legislation and regulations, which govern land tenure, royalties, production rates, environmental protection and the prevention of waste. The oil and natural gas industry is also subject to regulation and intervention by governments in such matters as the award of exploration and production rights, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and, possibly, expropriation or cancellation of contract rights. It is not expected that these controls and regulation will affect the operations of the Corporation in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments may be enacted. Environmental Regulation The oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures. A breach of such legislation may result in the imposition of material fines and penalties, the revocation of necessary licenses and authorizations and civil liability for pollution damage. In 1994, the United Nations' Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which will require, upon ratification, nations to reduce their emissions of carbon dioxide and other greenhouse gases. As a result of Canada's ratification of the Kyoto Protocol reductions in greenhouse gases from the Corporation's operations may be required which could result in increased capital expenditures and reductions in production of oil and gas. The Corporation does not face any environmental issues or impacts that are unique to the Corporation. However, like all participants in the Canadian oil and gas industry, reclamation and restoration of abandoned wells and facilities is recognized as a corporate responsibility. The expenses associated with meeting this responsibility are provided for on a unit of production basis. Oil and Natural Gas Prices Oil prices are subject to international supply and demand. Political developments, especially in the Middle East, can affect world oil supply and oil prices. Natural gas prices are primarily affected by supply and demand in North America and, to a lesser extent, by prices of alternate sources of energy. The Corporation expects continued volatility and uncertainty in oil and natural gas prices. Employees As at December 31, 2002, the Corporation did not have any full-time employees and as of May 20, 2003, the Corporation had 11 full-time employees. - 12 - 3.2 CORPORATE STRATEGY Vision - The Corporation's primary ongoing business objective is to become a full cycle oil and gas company with a dual focus on exploration and development activities and on an aggressive acquisition strategy, with a particular emphasis on natural gas opportunities. Drilling Program - Management intends to employ a "cheap deep" approach to exploration by implementing a high density drilling program with low cost options to look at deeper horizons, while continuing to seek out additional opportunities to add to the Corporation's land base. Responsible Fiscal Management - Approximately 50% of the Corporation's anticipated cash flow will be directed towards the replacement of existing reserves, leaving a significant amount of cash flow available for a focused exploration program or to pay down debt. The Corporation intends to prudently add value through its drilling and exploration activities and carefully manage its costs, thereby positioning itself to add to its inventory of opportunities and undeveloped land holdings. Prudent Use of Equity - Management recognizes that, at this early stage of development, equity must be used sparingly, and it intends to rely heavily on operational revenues and debt financing to satisfy liquidity requirements. The Corporation will attempt to minimize the dilution that would be caused to existing shareholders if large amounts of equity were issued. 3.3 BUSINESS STRENGTHS Strength of Management - Mr. Tuer has over 28 years of petroleum engineering and management experience in Canada and internationally, including experience as President and Chief Executive Officer of one of Canada's largest energy companies. Mr. Terry Schmidtke has over 24 years of operational experience in the areas of reservoir engineering, field operations, strategic planning and acquisitions and divestitures. Mr. Herring has over 22 years of accounting and oil and gas experience. Experienced, Interested Board - The Corporation's board of directors is comprised of individuals with broad backgrounds and demonstrated experience in creating shareholder value. In particular, Mr. Tuer, Mr. Ronald Mathison, Mr. Martin Lambert and Mr. Stan Grad have extensive industry and transactional experience. Several of the directors have significant financial stakes in the Corporation. Focused Production Areas - Following its acquisition of the Optioned Properties, Hawker will commence its energy business with high quality, tightly focused properties that management believes can be exploited through additional developmental drilling. The Optioned Properties contain close to 100 geophysically and geologically defined locations, and include over 140,000 net acres of undeveloped land. Emphasis on Gas - Hawker's initial production will be 100% natural gas. As the Corporation expands, its portfolio of oil producing properties will increase, but the emphasis on natural gas will remain part of Hawker's business plan. Price Certainty Through Hedging - An integral part of the Corporation's strategy in acquiring an interest in the Optioned Properties was the prior negotiation of the right to secure certain hedging arrangements in respect of a portion of the production from the properties. These forward sales contracts reduce the economic uncertainty of the acquisition of an interest in the Optioned Properties by providing certainty to the price for a material portion of Hawker's 2003 and first quarter 2004 gas production. - 13 - Advantageous Tax Position - The Corporation has non-capital losses and unclaimed expenditures of $37 million and $41 million, respectively, that are available for application against future taxable income. The Corporation also has $4.9 million of unclaimed investment tax credits available to reduce future year's income tax. The acquisition by Hawker of an additional 49% undivided interest in the Optioned Properties will add to the Corporation's tax pools by an amount equal to the purchase price of $67 million. 3.4 DRILLING ACTIVITY The following table sets forth the number of gross and net exploratory and development wells included in the Optioned Properties and which were completed, capped or abandoned during the periods indicated.
YEARS ENDED DECEMBER 31 ---------------------------------------------------------------------- 2002 2001 ------------------------------------ ------------------------------- GROSS WELLS(1) NET WELLS(2) GROSS WELLS(1) NET WELLS(2) -------------- ------------ -------------- ------------ Exploratory Gas 8.0 4.0 - - Dry(3) 3.0 1.5 - - ---- ---- ---- ---- Total Exploratory 11.0 5.5 - - ==== ==== ==== ==== Development Gas 15.0 7.0 31.0 15.4 Dry(3) 3.0 1.5 21.0 10.5 ---- ---- ---- ---- Total Development 18.0 8.5 52.0 25.9 ==== ==== ==== ==== Total Drilling Activity 29.0 14.0 52.0 25.9 ==== ==== ==== ====
NOTES: (1) "Gross Wells" means the total wells in which the Corporation will acquire an interest. (2) "Net Wells" means the total wells in which the Corporation will acquire an interest, multiplied by the working interest therein that relates to a 50% interest in the Optioned Properties. (3) "Dry Well" means a well which is not a productive well or a service well. A productive well is a well which is capable of producing oil and gas in commercial quantities or in quantities considered by the operator to be sufficient to justify the costs required to complete, equip and produce the well. A service well means a well such as a water or gas-injection, water-source or water-disposal well. Such wells do not have marketable reserves of crude oil or natural gas attributed to them but are essential to the production of the crude oil and natural gas reserves. 3.5 LOCATION OF PRODUCTION The following description of the Optioned Properties describes an undivided 50% interest in the properties. LAVOY AREA The Lavoy area is located approximately 100 kilometres east of Edmonton, Alberta near the town of Vegreville, Alberta. The Corporation will acquire an interest in 140.0 producing gas wells (122.4 net wells) and 10 facilities, all of which are non-operated. These facilities have a combined working interest capacity of approximately 40 mmcf/d of sweet dry gas and are comprised of compressors and dehydration equipment. Gross production in 2002 from the Lavoy area averaged 29 mmcf/d of sweet dry gas. The sweet dry gas produced in the Lavoy area contains no liquids, and does not require hydrocarbon dewpoint control at the transportation stage. The majority of the wells in the Lavoy area are controlled through SCADA, an electronic system for natural gas processing and control, using a data acquisition system that is controlled and sourced real-time from Calgary. The Lavoy area is characterized by multi-zone potential from 14 producing horizons from the Paleozoic to the Upper Cretaceous. Zonal rights in the Lavoy area are typically 100% working interest from surface - 14 - to basement. Drilling depths in the Lavoy area are typically less than 850 metres. In 2002, 29 wells (14 net wells) were drilled in Lavoy with a 79% success rate. In 2002, each successful well in the Lavoy area averaged approximately 520 mmcf of reserves, illustrating that the property is not mature from the perspective of development drilling. Access to these properties is available year round, and the area lends itself to seismic acquisition, fracture technology, air drilling and coil tubing advancements. Two central dehydration and compression facilities were established in 2002 at East Warwick and West Lavoy. These facilities process 6.4 mmcf/d net of the Corporation's production. The Corporation owns various working interests in a non-operated extensive gathering system that is closely accessible to all lands in the area, and there is ample gas transportation out of the area. COLD LAKE/BONNYVILLE The Cold Lake/Bonnyville area is located approximately 250 kilometres northeast of Edmonton. The Corporation will acquire an interest in 24.0 producing gas wells (18.9 net wells) and one facility in the Cold Lake/Bonnyville area. The Cold Lake/Bonnyville area is characterized by a large reserve potential at shallow depths, with multi-zone potential from four producing Cretaceous zones and drilling depths that are typically less than 500 metres. Gross production in 2002 from the Cold Lake/Bonnyville area averaged 4.9 mmcf/d of sweet dry gas. As with the Lavoy area, the sweet dry gas produced in the Cold Lake/Bonnyville area contains no liquids, and does not require hydrocarbon dewpoint control at the transportation stage. No wells were drilled on this property in 2002. The Corporation currently anticipates exploring two low risk locations into the Clearwater B pool, and is evaluating the project inventory in the area with a view to exploiting potential upside in the Colony McLaren and Clearwater zones. The Corporation intends to assume operatorship of this property. Production from the Cold Lake/Bonnyville area is processed at a non-operated facility. Two field compressors were installed during 2002. 3.6 LOCATION OF WELLS The following table sets forth the producing wells and wells capable of producing included in the Optioned Properties as at December 31, 2002.
GAS WELLS -------------------------------------------------------- PRODUCING SHUT-IN(3) ---------------------- ----------------------- GROSS(1) NET(2) GROSS(1) NET(2) -------- ------ -------- ------ Lavoy 140.0 61.7 36.0 17.3 Cold Lake/Bonnyville 28.0 11.0 8.0 3.3 ----- ---- ---- ---- TOTAL 168.0 72.7 44.0 20.6 ===== ==== ==== ====
NOTES: (1) "Gross Wells" means all wells in which the Corporation will acquire a working interest. (2) "Net Wells" means the total wells in which the Corporation will acquire an interest, multiplied by the working interest therein that relates to a 50% interest in the Optioned Properties. - 15 - (3) "Shut-in Wells" are wells which are capable of economic production or which the Corporation considers capable of production but which, for a variety of reasons, including but not limited to lack of markets or development, are not currently on production. 3.7 LAND HOLDINGS The following table summarizes the undeveloped land included in the Optioned Properties as at March 31, 2003.
PROPERTY GROSS ACRES(1) NET ACRES(2) -------- -------------- ------------ Lavoy 273,295 135,852 Cold Lake/Bonnyville 10,240 4,564 Manitoba 80 18 British Columbia 710 89 ------- ------- TOTAL 284,325 140,523 ======= =======
NOTES: (1) "Gross Acres" means the total acres in which the Corporation will acquire an interest. (2) "Net Acres" means the total acres in which the Corporation will acquire an interest, multiplied by the working interest therein that relates to a 50% interest in the Optioned Properties. The undeveloped land holdings of the Corporation have been evaluated by Antelope Land Services Ltd. which ascribed a value of $10,590,389 to a 50% undivided interest in the undeveloped lands included in the Optioned Properties. The Corporation has retained 100% of the seismic data relating to the Optioned Properties, which consists of approximately 6,234 kilometres of 2-D and 33.4 square kilometres of 3-D seismic data. Of this data, 3,337 kilometres of 2-D and 28 square kilometres of 3-D is purchased trade data in which the Corporation does not own any proprietary rights and will earn no revenue. The remaining 2,897 kilometres of 2-D and 5.4 square kilometres of 3-D seismic data constitutes proprietary seismic data. This seismic data will be used as a technological database to interpret and generate exploration and development prospects. The Corporation has granted a call option in respect of this seismic data which gives the grantee the right to acquire an undivided 99% in this seismic data for a purchase price of $3,710,000. If this call option is exercised, and the Corporation exercises the Purchase Option, in whole or in part, the Corporation will be required to purchase an equivalent proportion of this seismic data at a purchase price based on an ascribed price of $4 million for a 100% interest in the seismic data. 3.8 RESERVE ESTIMATES McDaniel has prepared the McDaniel Report in which it evaluated the crude oil, natural gas liquids and natural gas reserves attributable to an undivided 50% interest in the Optioned Properties, effective May 1, 2003, and estimated the net present worth value of such reserves. The information used to prepare the McDaniel Report was made available to McDaniel by Southward or was obtained from public sources or McDaniel's own files. The following tables summarize the reserve determinations contained in the McDaniel Report and the estimated future net present worth values therefrom. THE RESERVE DETERMINATIONS AND ESTIMATED NET PRESENT WORTH VALUES INCLUDED IN THE TABLES BELOW DO NOT INCLUDE THE ARTC AND ARE STATED PRIOR TO PROVISION FOR INCOME TAXES AND INDIRECT COSTS, SUCH AS GENERAL AND ADMINISTRATIVE EXPENSES AND FACILITY SITE RESTORATION, AND MAY NOT NECESSARILY BE REPRESENTATIVE OF THE FAIR MARKET VALUE OF THE RESERVES. THE PROBABLE RESERVES AND THE PRESENT WORTH VALUE OF SUCH RESERVES AS SET FORTH IN THE TABLES BELOW HAVE BEEN REDUCED BY 50% TO REFLECT THE DEGREE OF RISK ASSOCIATED WITH RECOVERY OF SUCH RESERVES. OTHER ASSUMPTIONS AND QUALIFICATIONS - 16 - RELATING TO COSTS, PRICES FOR FUTURE PRODUCTION AND OTHER MATTERS ARE SUMMARIZED IN THE NOTES FOLLOWING THE TABLES. THE RESERVE DETERMINATIONS AND ESTIMATED NET PRESENT WORTH VALUES INCLUDED IN THE TABLES BELOW REPRESENT A 50% UNDIVIDED INTEREST IN THE OPTIONED PROPERTIES. OPTIONED PROPERTIES (50% INTEREST) PETROLEUM AND NATURAL GAS RESERVES AND PRE-TAX ESTIMATED NET PRESENT WORTH ESCALATING PRICES AND COSTS
NATURAL GAS PRE-TAX ESTIMATED NET PRESENT WORTH (MMCF) (THOUSANDS OF DOLLARS) --------------- ----------------------------------- Discounted at ----------------------------------- Gross Net 0% 10% 15% 20% ------ ------ ------- ------ ------ ------- Proved Reserves Producing .......... 18,607 14,450 65,104 52,721 48,523 45,124 Non-Producing ...... 3,592 2,629 11,983 9,628 8,897 8,314 ------ ------ ------ ------ ------ ------ Total Proved Reserves .... 22,199 17,079 77,087 62,349 57,420 53,438 Risked Probable Reserves.. 4,195 3,181 13,502 8,678 7,332 6,341 ------ ------ ------ ------ ------ ------ Established Reserves ..... 26,394 20,260 90,589 71,027 64,752 59,779
OPTIONED PROPERTIES (50% INTEREST) PETROLEUM AND NATURAL GAS RESERVES AND PRE-TAX ESTIMATED NET PRESENT WORTH CONSTANT PRICES AND COSTS
NATURAL GAS PRE-TAX ESTIMATED NET PRESENT WORTH (MMCF) (THOUSANDS OF DOLLARS) ---------------- ------------------------------------- Discounted at ------------------------------------- Gross Net 0% 10% 15% 20% ------ ------ ------- ------ ------ ------ Proved Reserves Producing ............... 18,607 14,450 87,183 68,053 61,720 56,662 Non-Producing ........... 3,592 2,629 15,154 11,778 10,734 9,910 ------ ------ ------- ------ ------ ------ Total Proved Reserves ......... 22,199 17,079 102,337 79,831 72,454 66,572 Risked Probable Reserves ...... 4,195 3,181 19,516 12,243 10,224 8,742 ------ ------ ------- ------ ------ ------ Established Reserves .......... 26,394 20,260 121,853 92,074 82,678 75,314
NOTES TO RESERVE DETERMINATIONS The following notes provide important information relating to the preceding reserve determinations. (1) "Gross Reserves" are defined as the total of the Corporation's working interests and/or royalty interests share of reserves before deducting royalties owned by others. (2) "Net Reserves" are defined as the total of the Corporation's working interests and/or royalty interests share of reserves after deducting the amounts attributable to the royalties owned by others. (3) "Net Present Worth" values are based on net reserves and are expressed after giving effect to estimated operating expenses and capital expenditures but before provision for income taxes, overhead and general administrative expenses, and for the escalating price assumptions case, the operating expenses and capital expenditures have been escalated at 2.0% per year. (4) "Proved Reserves" are defined as those reserves estimated as recoverable under current technology and existing economic conditions, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir. (5) "Proved Producing Reserves" are defined to include both those proved reserves that are actually on production, or if not producing, that could be recovered from existing wells or facilities and where the reasons for the current non-producing status is the choice of the owner. An illustration of such a situation is where a well or zone is capable of production but is shut-in because its deliverability is not required to meet contract commitments. (6) "Proved Non-Producing Reserves" are defined as those reserves estimated as recoverable from existing wells that require relatively minor capital expenditures to produce. - 17 - (7) "Proved Undeveloped Reserves" are defined as those reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major capital expenditure will be required. (8) "Probable Additional Reserves" are defined as those reserves which an analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future. (9) "Risked Probable Reserves" means probable additional reserves discounted by one-half to account for the additional risk of recovery for probable reserves; (10) "Established Reserves" means proved reserves plus risked probable reserves; (11) The constant price assumptions table is based on the following prices and held constant over the life of the reserves (West Texas Intermediate ("WTI") - $US 30.00/bbl; Edmonton Light $Cdn. 43.10/bbl; Alberta Average Natural Gas $Cdn. 6.90/mmbtu). (12) The escalating price assumptions table is based on the McDaniel price forecast (March 1, 2003) and escalating over the life of the reserves. An excerpt of the price forecast from the McDaniel Report, being the WTI oil price at Cushing, Oklahoma, the Edmonton Oil Price for 40 API, 0.5% sulphur crude, and the Alberta Average field price for gas, appears below.
CRUDE OIL NATURAL GAS -------------------------- --------------- WTI EDMONTON LIGHT ALBERTA AVERAGE YEAR ($US/BBL) ($CDN/BBL) ($CDN/MMBTU) ---- --------- -------------- --------------- 2003 30.00 43.10 6.90 2004 26.00 37.20 5.65 2005 24.00 34.30 5.05 2006 23.00 32.80 4.80 2007 23.30 33.20 4.65 2008 23.80 33.90 4.70 2009 24.30 34.60 4.80 2010 24.80 35.30 4.90 2011 25.30 36.00 5.00 2012 25.80 36.70 5.10 2013 26.30 37.50 5.20 2014 26.80 38.20 5.30 2015 27.30 38.90 5.40 2016 27.80 39.60 5.50 2017 28.40 40.40 5.60 2018 29.00 41.30 5.70 2019 29.60 42.20 5.85 2020 30.20 43.00 5.95 2021 30.80 43.90 6.10 2022 31.40 44.70 6.20
(13) The value of the ARTC has not been included in the Net Present Worth values. (14) The McDaniel Report estimates that capital expenditures to be incurred in 2003, 2004 and 2005 and thereafter and in total, net to the Corporation, necessary to achieve the estimated net present worth values from proved plus probable additional reserves are as follows:
ESCALATING PRICE ASSUMPTIONS CONSTANT PRICE ASSUMPTIONS ---------------------------- -------------------------- 2003 $ 1,117,000 2003 $ 1,110,300 2004 175,600 2004 168,800 2005+ 287,300 2005+ 262,300 ------------ ------------ Total $ 1,579,900 $ 1,541,400 ============ ============
(15) All of the proved producing reserves in the Optioned Properties are currently on production. (16) The McDaniel Report estimates future abandonment costs of $20,000 for each well that has been assigned reserves. Actual abandonment costs may exceed this estimate. No allowance was included for future abandonment costs of any facilities. 3.9 RECONCILIATION OF RESERVES The following table summarizes the changes to the proved reserves (before royalties) associated with a 50% undivided interest in the Optioned Properties from December 31, 2001 to December 31,2002. - 18 -
NATURAL GAS (MMCF) ------------------------------- PROVED PROBABLE TOTAL ------ -------- ----- January 1, 2002 22,920 4,889 27,809 Production (6,310) - (6,310) Acquisitions - - - New Development 5,920 2,060 7,980 Dispositions (269) (9) (278) Revisions (1,319) (531) (1,850) ------ ----- ------ January 1, 2003 20,942 6,409 27,351 ====== ===== ======
3.10 PRODUCTION HISTORY The following table shows the average daily production volumes from an undivided 50% interest in the Optioned Properties, before the deduction of royalties, for each of the fiscal quarters of 2001 and 2002.
2002 2001 ------------------------------------------------------ ------------------------------------------------------ THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS ENDED ENDED ENDED ENDED ENDED ENDED ENDED ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ----------- ------------ ------------ ------------ ------------ ------------ ------------ ------------ Natural Gas (mcf/d) 16,714 16,071 16,460 19,258 16,071 16,534 18,096 18,190
3.11 NETBACK HISTORY The following table summarizes the average netbacks ($ per mcf) received for natural gas production from an undivided 50% interest in the Optioned Properties for each of the fiscal quarters of 2001 and 2002.
2002 2001 ------------------------------------------------------ ------------------------------------------------------ (UNAUDITED) (UNAUDITED) THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS ENDED ENDED ENDED ENDED ENDED ENDED ENDED ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------ Sales Price $3.10 $3.10 $3.37 $4.72 $9.26 $6.07 $3.99 $3.55 Processing and Other - - - - - - - - Income Royalties 0.83 0.93 0.97 1.12 2.46 1.60 0.84 0.75 Operating Costs 0.55 0.66 0.51 0.56 0.39 0.42 0.50 0.41 ----- ----- ----- ----- ----- ----- ----- ----- Netback 1.72 1.51 1.89 3.04 6.41 4.05 2.65 2.39 ===== ===== ===== ===== ===== ===== ===== =====
3.12 CAPITAL EXPENDITURES The following table summarizes the capital expenditures in respect of an undivided 50% interest in the Optioned Properties in the categories indicated for each of the fiscal quarters of 2001 and 2002.
2002 2001 ------------------------------------------------------ ------------------------------------------------------ (UNAUDITED) (UNAUDITED) THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS ENDED ENDED ENDED ENDED ENDED ENDED ENDED ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------ Land acquisitions $ 197,314 $ 67,739 $ 320,420 $ 126,603 $ 839,101 $ 1,354,036 $ 1,727,559 $ 487,130 Exploration (including drilling) 1,128,209 1,273,520 913,588 328,622 1,873,729 3,465,651 1,162,818 1,745,135
- 19 -
2002 ------------------------------------------------------ (UNAUDITED) THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS ENDED ENDED ENDED ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ------------ ------------ ------------ ------------ Development (including facilities) 266,080 592,692 1,363,206 389,783 ------------ ------------ ------------ ------------ Total 1,591,603 1,933,951 2,597,214 845,008 ============ ============ ============ ============
2001 ------------------------------------------------------- (UNAUDITED) THREE MONTHS THREE MONTHS THREE MONTHS THREE MONTHS ENDED ENDED ENDED ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 ------------ ------------ ------------ ------------- Development (including facilities) 890,289 1,537,726 1,169,140 888,443 ------------ ------------ ------------ ------------- Total 3,603,119 6,357,413 4,059,517 3,120,708 ============ ============ ============ =============
3.13 FUTURE COMMITMENTS As a pre-condition to BidCo entering into the arrangement agreement, Southward agreed that at the direction of BidCo it would enter into fixed price forward sales contracts in respect of up to 12,875 GJ/d of gas production from the Optioned Properties. At BidCo's direction, on March 17, 2003, Southward entered into four forward sales contracts in respect of an aggregate of 12,880 GJ/d for 2003 and the first quarter of 2004, of which the Corporation will retain an interest in contracts in respect of 6,440 GJ/d, representing 36% of gas production attributable to a 50% undivided interest in the Optioned Properties for the last 8 months of 2003 (based on the McDaniel Report) at prices ranging from $6.24 to $7.15 per GJ. These forward sales contracts reduce the economic uncertainty of the acquisition of an interest in the Optioned Properties by providing certainty to the prices for a portion of the production from the properties. In addition to the forward sales contracts noted above, pursuant to the Purchase Option, the Corporation will acquire an interest in forward sales contracts and financial hedging contracts with respect to production from the Optioned Properties as follows:
VOLUME CONTRACT PRICE(1) TRANSACTION TYPE (GJ/d) (GJ/d) EXPIRY ------------------------ --------- ----------------- ----------------- Fixed Summer 1,658 $4.10 October 31,2003 Fixed Summer 3,220 $6.64 October 31,2003 Costless Collar Summer 3,220 $6.24 - $7.00 October 31,2003 Costless Collar Winter 4,830 $6.36 - $7.15 March 31,2004 Fixed Winter 1,610 $ 6.76 March 31,2004 Fixed Summer 1,450 $ 5.06 October 31,2003 Cogeneration Fuel Supply 263 $1.959(2) October 31,2008 Daily Declining Profile 977(3) netback(4) October 31,2011 Reserve Based 101(5) netback(6) life of reserves
NOTES: (1) The contract price net of costs is obtained by subtracting costs of $0.20 from the contract price. (2) The contract price increases over the term of the contract, with the price for each of the 12 month periods remaining in the term as follows:
DATE PRICE --------------- ------ November 1,2003 $2.008 November 1,2004 $2.058 November 1,2005 $2.110 November 1,2006 $2.163 November 1,2007 $2.217
- 20 - (3) The Corporation's obligations under this contract will, on November 1 of this year and each succeeding year, decline to the following:
DATE OBLIGATION (GJ/d) ------------------------------ ----------------- November 1,2003 841 November 1,2004 724 November 1,2005 623 November 1,2006 and thereafter 568
(4) TransCanada Pipelines Limited netback pricing. (5) Reserve based with respect to production from Mannville 2-19 well. (6) Progas Limited netback pricing. Hawker's aggregate future commitments represent an aggregate of 50% of its estimated 2003 production from total proved reserves at a weighted average price of $5.98 per GJ and 44% of its estimated first quarter 2004 production from total proved reserves at a weighted average price of $6.57 per GJ. ITEM 4: SELECTED CONSOLIDATED FINANCIAL INFORMATION 4.1 ANNUAL INFORMATION The following table sets forth selected consolidated financial information of the Corporation for each of the last three years ended December 31. This financial information reflects the Corporation's operations as a pharmaceutical research company prior to its transformation into an oil and gas enterprise.
YEARS ENDED DECEMBER 31 ----------------------- (000s except per share amounts) 2002 2001 2000 ---- ---- ---- Revenue $ 139 $ 729 $ 1,513 Net earnings (loss) $3,766 ($ 22,988) ($ 7,889) Basic and diluted net earnings (loss) per $ 0.76 ($ 4.64) ($ 1.63) share Total assets $4,015 $ 22,584 $46,326 Total cash and cash equivalents $ 289 $ 5,841 $18,821 Total long-term debt - - $ 9,163 Cash dividends declared per Common Nil Nil Nil Share
- 21 - 4.2 QUARTERLY INFORMATION The following table sets forth certain financial information for the last eight financial quarters ended December 31, 2002. This financial information reflects the Corporation's operations as a pharmaceutical research company prior to its transformation into an oil and gas enterprise. QUARTER ENDED (000s except per share amounts)
DEC. 31 SEPT. 30 JUNE 30 MAR. 31 DEC. 31 SEPT. 30 JUNE 30 MAR. 31 2002 2002 2002 2002 2001 2001 2001 2001 -------- -------- ------- ------- -------- -------- ------- ------- Revenue - - - - - - - $ 214 Other income $ 1 $ 2 $ 4 $ 132 $ 50 $ 93 $147 $ 50 Net earnings ($ 1,241) ($ 6,567) $8,056 $3,518 ($ 13,621) ($ 1,612) ($ 3,687) ($ 4,068) (loss) Basic earnings ($ 0.25) ($ 1.32) $ 1.61 $ 0.71 ($ 2.75) ($ 0.33) ($ 0.72) ($ 0.82) (loss) per share
4.3 DIVIDEND POLICY To date, the Corporation has not paid any dividends on its outstanding Common Shares. The future payment of dividends will be dependent upon the financial requirements of the Corporation to fund future growth, the financial condition of the Corporation and other factors which the board of directors of the Corporation may consider appropriate in the circumstances. It is unlikely that dividends will be paid in the foreseeable future. ITEM 5: MANAGEMENT'S DISCUSSION AND ANALYSIS THIS DISCUSSION AND ANALYSIS OF THE FINANCIAL CONDITION OF THE CORPORATION AND THE RESULTS OF OPERATIONS SHOULD BE READ IN CONJUNCTION WITH THE CONSOLIDATED AUDITED FINANCIAL STATEMENTS AND THE RELATED NOTES. OVERVIEW Prior to December 10, 2001, the Corporation was a biotechnology company focusing primarily on the discovery and development of pharmaceutical products for gastroenteric diseases or conditions which could benefit from new or additional therapies. On December 10, 2001, the Corporation terminated development of SYNSORB Cd(R), its sole development drug. Subsequent to that date, the Corporation has had no drug under active development and has no regular source of operating revenue or cash flow. After that date, the Corporation reduced its spending and terminated all contracts and commitments that were considered not critical to an orderly wind down of the clinical trials and the preservation of its asset base. During 2002, the employees of the Corporation were reduced to one full-time and one part-time employee. PROVISION FOR SYNSORB Cd(R) WIND-DOWN COSTS A provision for the future wind-down costs of clinical trials, reduction in staff and elimination of their costs associated with the development of the SYNSORB Cd(R) totalling $3,830,000 was included in the results for the year ended December 31,2001. Of this amount, approximately $946,000 related directly to - 22 - the wind down of clinical activity, $1,339,000 related to staff reductions and $1,545,000 related to other costs associated with halting SYNSORB Cd(R) related activity. An additional provision amount of $50,000 was included for the period ended June 30, 2002. As at December 31, 2002, the entire provision amount had been utilized. No further windup costs are anticipated. WRITE-DOWNS OF CAPITAL ASSETS The decision to halt clinical trials led to a write-down of certain capital assets. In 2001, the Corporation wrote down its patents associated with SYNSORB related technology to nil, and the charge of $2,060,000 was included in amortization expense. In 2000, the Corporation wrote down its patents associated with SYNSORB Pk(R) to nil, and the charge of $602,000 was included in amortization expense. As part of its drug development activity, in 1998 SYNSORB built a cGMP-compliant manufacturing facility. In 2001, the Corporation determined that continued ownership of this facility was unnecessary and wrote-down the value of the facility and associated equipment on December 31, 2001 to the estimated net realizable value based on its potential sale as a cGMP-compliant manufacturing facility. In 2001, this resulted in the Corporation writing-down the value of its building and land to $8,600,000 and writing-down the value of its manufacturing equipment to $2,000,000, and the total associated charge of $5,876,000 was included in amortization expense. Efforts to market the facility as a manufacturing facility were unsuccessful and the Corporation now expects to realize commercial value for the building and land. Accordingly, the Corporation wrote-down the value of the building and land to $2,500,000 and the associated charge of $6,100,000 is included in amortization expense. While the Corporation feels that these write-downs are appropriate, the book value of the building and land may not reflect the ultimate realizations which may be achieved on their disposition. The manufacturing equipment was auctioned subsequent to December 31, 2002, the value of the manufacturing equipment as at December 31, 2002 was written down to $1,000,000 and the associated charge of $997,000 is included in amortization expense. For the year ended December 31, 2001 the Corporation wrote off leasehold improvements, computer equipment and office furniture and equipment and the total charge of $267,000 was included in amortization expense. DISTRIBUTION OF SHARES OF ONCOLYTICS BIOTECH INC. At December 31, 2001 the Corporation owned 6,255,800 common shares of Oncolytics Biotech Inc. ("Oncolytics"). Effective May 15, 2002 the Corporation distributed to its shareholders 4,000,235 common shares of Oncolytics which was accounted for as a return of capital. The deemed value of these shares, net of expenses, was $11,600,000 resulting in a gain on distribution of $8,325,000. As part of this transaction, the Corporation's holding of 1,500,000 shares in BCY Life Science's Inc. was transferred to Oncolytics. No gain or loss was recorded as a result of that transfer. During the year ended December 31, 2002 the Corporation sold 2,255,565 common shares of Oncolytics for net proceeds of $6,898,000 resulting in a gain on sale of $4,899,000. As at December 31, 2002 the Corporation did not hold any common shares of Oncolytics. - 23 - YEAR ENDED DECEMBER 31, 2002 COMPARED WITH YEAR ENDED DECEMBER 31, 2001 Liquidity and Capital Resources At December 31, 2002 the Corporation's cash and working capital positions were $289,000 and $412,000, respectively, compared at December 31, 2001 balances of $5,841,000 and ($4,725,000) respectively. As at December 21, 2002 the Corporation had no long term or short term debt. At December 31, 2001 the current portion of long term debt of the Corporation was $5,910,000, all of which was repaid during 2002. The Corporation's primary source of liquidity during 2002 was the liquidation of its assets. In 2002 the Corporation sold 2,255,565 common shares of Oncolytics for net proceeds of $6,898,000 resulting in a gain on sale of $4,899,000. As at December 31, 2002 the Corporation did not hold any common shares of Oncolytics. During 2002 the Corporation attempted to dispose of both its manufacturing equipment and its manufacturing facility. Subsequent to December 31, 2002 the Corporation disposed of most of its manufacturing equipment through auction realizing proceeds, net of expenses, of approximately $900,000 and has listed its manufacturing building and related land for sale as commercial premises. The Corporation also holds miscellaneous intellectual property rights with respect to certain drug technologies, which it may license, dispose of or abandon. In February 2003 the Corporation received U.S.$230,000 for an exclusive license of certain of its patents regarding toxin binding sugars. No assurance can be given as to whether any assets can be disposed of or what, if any, proceeds can or will be received with respect thereto. In addition to the liquidation of assets, the Corporation may receive milestone payments and royalties with respect to the previous sale of its INH subsidiary or may choose to sell these rights. The Corporation cannot predict the likelihood, timing or amount of any milestone or royalty receipts. Results of Operations For the year ended December 31, 2002, the Corporation had total revenue of $139,000 compared to $729,000 for the year ended December 31, 2001. Interest income for the 12 months ended December 31, 2002 decreased significantly compared to the same period in 2001 as a result of lower average cash balances on hand and lower interest rates in 2002. Expenses for the year ended December 31, 2002 of $9,126,000 were less than the expenses of $26,803,000 for the comparable period in 2001. Because the Corporation had terminated research and development in late 2001 and made a provision in that year for future wind down costs associated with drug development, research development expenses in 2002 were nil. Operating expenses for the 2002 period were $1,596,000, a significant reduction from $7,106,000 for 2001. The reduction is due to the termination of almost all employees, the termination of certain office space effective April 11, 2002 and the consolidation of all activity at the manufacturing facility. Interest on long term debt in 2002 was $71,000, a significant reduction from $787,000 in 2001 due to the payment by the Corporation during 2002 of all of its long and short-term debt. Amortization in 2002 was $7,216,000 compared to $9,655,000 in 2001. Included in the 2001 amortization amounts was property and other capital asset write-downs of $8,203,000 arising from the termination of the Corporation's drug development program. The amortization in 2002 included additional write-downs of the Corporation's equipment and manufacturing facility based on the Corporation's determination that those assets could only be sold on the basis of general commercial conditions and not their drug specific attributes. - 24 - YEAR ENDED DECEMBER 31, 2001 COMPARED WITH YEAR ENDED DECEMBER 31, 2000 Liquidity and Capital Resources The Corporation's cash and working capital position at December 31, 2001 were $5,841,000 and ($4,725,000) respectively, compared to December 31, 2000 balances of $18,821,000 and $14,942,000 respectively. The working capital deficiency of ($4,725,000) included $5,910,000 as the current portion of long term debt, all of which was repaid subsequent to year-end. On December 10, 2001, when it announced its decision to halt development of SYNSORB Cd(R), the Corporation had cash of approximately $7,000,000 and long term debt, including current portion, totalling $6,383,625. During 2001 the Corporation entered into a Common Share Purchase Agreement (CSPA) allowing the Corporation to access funds through the sale of a maximum of 1,000,000 Oncolytics common shares pursuant to a common share equity line. Under this agreement the Corporation was able, at its option, to sell the Oncolytics common shares over a period of 12 months commencing on June 19, 2001 at a discount from the average daily price of the common shares. During the year ended December 31, 2001 the Corporation sold 494,200 Oncolytics common shares, representing 7% of the Corporation's total holdings in Oncolytics, for net proceeds of $3,481,070 under the terms of the CSPA. Subsequent to year-end the Corporation terminated the CSPA with no penalty. On April 20, 2001 the Corporation issued 126,000 common shares on the exercise of options for proceeds of $126,000. No other equity was issued during 2001. During the year the Corporation repaid $2,866,000 of the principal outstanding with respect to its long-term debt and a further $5,910,000 was outstanding at December 31, 2001. Effective December 31, 2001, the Corporation agreed to a revised repayment schedule for its $5,000,000 credit facility drawn down during construction of the manufacturing facility. Therefore, all of the amount outstanding at December 31, 2001 was repayable within one year. Interest paid in 2001 with respect to these debt facilities was $787,000 compared to $1,176,000 for 2000. On February 5, 2002 the Corporation prepaid the remaining $838,586 owing under a loan bearing an interest rate of 13.73% per annum, with certain intellectual property pledged as collateral. On March 1, 2002 the Corporation repaid the remaining principal of $4,000,000 outstanding on its floating rate debt. Results of Operations For the year ended December 31, 2001, the Corporation recorded total revenue of $729,000 compared to $1,513,000 for the year ended December 31, 2000. Milestone payments totalled $214,000 for the year ended December 31, 2001 compared to $106,000 for the same period in 2000. A payment of $94,000 was also received from a partnering agreement in 2000. Interest income for the twelve months ended December 31, 2001 decreased by 61% compared to the same period in 2000 as a result of a lower average cash on hand balance and lower interest rates in 2001. Expenses for the years ended December 31,2001 and 2000 of $9,255,000 and $7,889,000 respectively for research and development and clinical trials represented approximately 35% and 56% respectively of the Corporation's total expenses. Included in 2001 research and development expenses were $1,384,000 of future wind down costs since further development of SYNSORB Cd(R) was terminated in December 2001. Of this amount $946,000 relates directly to the wind down of the clinical trial and $438,000 relates to other costs associated with halting development of SYNSORB Cd(R). There were minimal expenses associated with SYNSORB Pk(R) during 2001 as active development of the drug was suspended in December 2000. - 25 - During 2001, the Corporation spent $974,000 for research programs and other expenses to develop and broaden the SYNSORB technology, primarily in the field of carbohybrids. Ongoing research and development has been suspended since the termination of development of SYNSORB Cd(R). Operating expenses totalled $7,106,000 and $3,648,000 for the years ended December 31, 2001 and 2000 respectively. The increase of $3,458,000 primarily reflects $2,446,000 in future wind down costs and $507,000 in December 2001 staff termination costs. Included in the future wind down costs are $1,339,000 related to future staff terminations and $1,107,000 in other administrative costs relating to the termination of development of SYNSORB Cd(R) such as legal and audit fees, insurance, rent and other office costs. Capital Expenditures Capital expenditures for the year ended December 31, 2001 totalled $944,000, including $720,000 in patent costs incurred for the Corporation's intellectual property, $92,000 in leasehold improvements, $127,000 in office and computer equipment, and $25,000 in manufacturing equipment. All capital expenditures, except those deemed necessary to maintain intellectual property, were suspended subsequent to the decision on December 10, 2001 to halt development of SYNSORB Cd(R). The Corporation has offered its manufacturing facility for sale. Capital expenditures for the year ended December 31, 2000 totalled $980,000. At year-end 2001, the Corporation had no commitments for future capital spending. Annual amortization of capital investments totalled $9,655,000 or approximately 36% of the Corporation's total expenses for the year 2001 compared to $1,404,000 or 10% for 2000. Included in the 2001 amortization amount are property and other capital assets write downs of $8,203,000 arising as a result of the termination of development of SYNSORB Cd(R). Depreciation of the manufacturing facility commenced on January 1, 2001 at the rate of 5% per annum on a declining balance. INCOME TAXES As at December 31, 2002 the Corporation had non-capital losses of approximately $37,314,000 available to reduce future taxable income. These losses will expire in the years 2005 through 2008. In addition, the Corporation had unclaimed expenditures of approximately $41,000,000 available to reduce future taxable income and $4,939,000 of unclaimed investment tax credits available to reduce future income tax payable. As at December 31, 2002 the Corporation had non-capital losses of approximately $37,314,000 available to reduce future taxable income. These losses will expire in the years 2005 through 2008. In addition, the Corporation had unclaimed expenditures of approximately $41,000,000 available to reduce future taxable income and $4,939,000 of unclaimed investment tax credits available to reduce future income tax payable. The acquisition by Hawker of an additional 49% undivided interest in the Optioned Properties will add to the Corporation's tax pools by an amount equal to the purchase price of $67 million, subject to adjustment. TREATMENT OF RESEARCH AND DEVELOPMENT COSTS During 2001 and the previous two years, the research and development costs of the Corporation were expensed as incurred. Under Canadian generally accepted accounting principles (GAAP), development costs should be capitalized if certain criteria are met. Companies with major products in clinical trials do not necessarily meet these criteria. In the United States all research and development costs are expensed in accordance with US GAAP. The Corporation's development costs in 2001, and the previous two years, did not meet the following two capitalization criteria: (i) the technical feasibility of the product or process must have been established; and (ii) the future market for the product or process must be clearly defined. - 26 - With regard to (i), the Corporation was conducting clinical trials for SYNSORB Cd(R) and SYNSORB Pk(R) and the technical feasibility of these products was not known. With regard to (ii), the future market for these products was not clearly defined. For these reasons, the Corporation's development costs were expensed and not capitalized. RISKS AND UNCERTAINTIES Throughout the conduct of its clinical trials, the Corporation has maintained product liability insurance at levels consist with the current industry practice. No assurance can be given that this coverage will provide full protection against all risks. ITEM 6: MARKET FOR SECURITIES The Corporation's Common Shares are listed for trading on the TSX under the trading symbol "HKR". ITEM 7: DIRECTORS AND OFFICERS The following table sets out the names and municipalities of residence of each of the current directors and officers of the Corporation, their current positions and offices with the Corporation and their principal occupations and positions held during the last five years.
NAME AND MUNICIPALITY OF POSITION WITH THE DIRECTOR OR OFFICER PRESENT OCCUPATION AND POSITIONS HELD DURING RESIDENCE CORPORATION SINCE THE LAST FIVE YEARS ------------------------ ----------------- ------------------- -------------------------------------------- David A. Tuer Chief Executive January 6, 2003 Chief Executive Officer and a Director of Hawker Calgary, Alberta Officer and a and Chairman, Calgary Health Region. Prior to Director October 2001, President, Chief Executive Officer and a Director of PanCanadian Petroleum Limited Ronald P. Mathison(1)(2)(3) Chairman and a April 3, 2003 President and Director of Matco Investments Ltd. Calgary, Alberta Director Stan G.P. Grad(3) Director April 21, 2003 Independent Businessman Calgary, Alberta Bruce J. Kenway, C.A.(1) Director March 31, 1994 Partner, Kenway Mack Slusarchuk Stewart LLP, Calgary, Alberta Chartered Accountants Martin A. Lambert(1)(2) Director April 3, 2003 Partner, Bennett Jones LLP Calgary, Alberta Keith T. Smith(3) Director April 3, 2003 President and Chief Executive Officer of zed.i Calgary, Alberta solutions inc. from April 2001. Prior thereto, Vice President, Corporate Development with zed.i solutions inc. since April 2000 and Executive Vice President of Acanthus Resources Ltd., a private oil and gas company, from August 1998 to April 2000. Prior thereto, Executive Vice President of WestCastle Energy Corp., the Manager of WestCastle Energy Trust, and a Director of WestCastle Acquisition Corp., the operating company of WestCastle Energy Trust from February 1997 to August 1998
- 27 -
NAME AND MUNICIPALITY OF POSITION WITH THE DIRECTOR OR OFFICER PRESENT OCCUPATION AND POSITIONS HELD DURING RESIDENCE CORPORATION SINCE THE LAST FIVE YEARS ----------------------- ----------------- ------------------- --------------------------------------------- Barry Herring Chief Financial May 6, 2003 Chief Financial Officer of the Corporation since Calgary, Alberta Officer May 6, 2003. Prior thereto, Vice President, Finance and Chief Financial Officer of Southward Energy Ltd. from January 2002 to April 2003, Senior Vice President of Calpine Canada from June 2000 to September 2000, Vice President, Finance and Operations of Quintana Minerals Canada Corp. from May 1999 to June 2000 and Vice President, Finance and Operations of Ocean Energy Inc. from 1997 to 1999. Terry C. Schmidtke Chief Operating April 21, 2003 Chief Operating Officer of the Corporation since Calgary, Alberta Officer April 21, 2003. Prior thereto, Senior Vice President, Central Plains Region for EnCana Corporation from April 2002 to March 2003, and General Manager of various business units of PanCanadian Petroleum Limited since 1994. Darrell R. Peterson Corporate April 3, 2003 Partner, Bennett Jones LLP since March 2003. Calgary, Alberta Secretary Prior thereto, Associate of Bennett Jones LLP.
NOTES: (1) Member of Audit Committee. (2) Member of Corporate Governance Committee. (3) Member of Reserves Committee. The officers and directors of the Corporation, as a group, beneficially own, directly or indirectly, 5,230,767 Equity Shares or approximately 46% of the outstanding Equity Shares (calculated as though the Conversion had occurred). ITEM 8: ADDITIONAL INFORMATION Additional information, including information as to directors' and officers' remuneration and indebtedness, principal holders of the Corporation's securities, options to purchase securities and interests of insiders in material transactions is contained in the Information Circular of the Corporation for the Annual and Special Meeting of Shareholders of the Corporation held on April 3,2003. Additional financial information is provided in the Corporation's audited consolidated financial statements for the year ended December 31,2002. When the Corporation's securities are in the course of a distribution pursuant to a short form prospectus or when a preliminary short form prospectus has been filed in respect of a distribution of the Corporation's securities, upon request to the Chief Financial Officer, the Corporation will provide to any person: 1) one copy of this Annual Information Form together with one copy of any document, or the pertinent pages of any document, incorporated by reference in this annual information form; 2) one copy of the Corporation's audited consolidated financial statement for the year ended December 31, 2002, together with the report of the auditors thereon, and one copy of any of the Corporation's interim consolidated financial statements subsequent to such audited financial statements; and - 28 - 3) one copy of the Corporation's Information Circular for the Annual and Special Meeting of the Shareholders of the Corporation held on April 3, 2003. At any other time, one copy of each of the documents referred to in 1, 2 and 3 above may be obtained upon request to Chief Financial Officer for the Corporation, provided that the Corporation may require the payment of a reasonable charge if the request is made by a person who is not a shareholder of the Corporation. Any request for any documents referred to above should be made to the Chief Financial Officer, Hawker Resources Inc., 3200, 350 - 7th Avenue S.W., Calgary, Alberta, T2P 3N9 and fax (403) 266-1814.