EX-99 122 ex99-119form40_f.txt EXHIBIT 99.119 -------------------------------------------------------------------------------- EXHIBIT 99.119 -------------- ADVANTAGE ENERGY INCOME FUND RENEWAL ANNUAL INFORMATION FORM 2003 May 12, 2004 -------------------------------------------------------------------------------- TABLE OF CONTENTS Page GLOSSARY OF TERMS ......................................................... 1 ABBREVIATIONS ............................................................. 6 CONVERSION ................................................................ 6 ADVANTAGE ENERGY INCOME FUND .............................................. 8 GENERAL DEVELOPMENT OF THE BUSINESS ....................................... 9 DESCRIPTION OF THE BUSINESS AND OPERATIONS ................................ 12 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION .............. 13 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION . 27 REPORT ON RESERVES DATA ................................................... 28 ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND ............ 29 ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD ................. 36 ADDITIONAL INFORMATION RESPECTING ADVANTAGE INVESTMENT MANAGEMENT LTD ..... 42 MARKET FOR SECURITIES ..................................................... 48 PROMOTERS ................................................................. 49 LEGAL PROCEEDINGS ......................................................... 49 INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS .................. 49 AUDITORS, TRANSFER AGENT AND REGISTRAR .................................... 49 MATERIAL CONTRACTS ........................................................ 49 INTEREST OF EXPERTS ....................................................... 50 RISK FACTORS .............................................................. 50 ADDITIONAL INFORMATION .................................................... 59 SCHEDULE "A" - FINANCIAL STATEMENTS OF MARKWEST RESOURCES CANADA CORP. SCHEDULE "B" - UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS GLOSSARY OF TERMS "8 1/4% Debentures" means the 8 1/4% convertible unsecured subordinated debentures of the Trust due February 1, 2009; "8 1/2% Note Indenture" means the trust indenture providing for the issuance of the 8 1/2% Notes dated December 2, 2003 and made between AOG and Computershare Trust Company of Canada, as trustee; "8 1/2% Notes" means the 8 1/2% unsecured subordinated promissory notes of AOG issued pursuant to the 8 1/2% Note Indenture; "9% Debentures" means the 9.00% convertible unsecured subordinated debentures of the Trust due August 1, 2008; "9 3/8% Note Indenture" means the trust indenture providing for the issuance of the 9 3/8% Notes dated July 8, 2003 and made between AOG and Computershare Trust Company of Canada, as trustee; "9 3/8% Notes" means the 9 3/8% unsecured subordinated promissory notes of AOG issued pursuant to the 9 3/8% Note Indenture; "10% Debentures" means the 10% convertible unsecured subordinated debentures of the Trust due November 1, 2007; "10 3/8% Notes" means the 10 3/8% unsecured subordinated promissory notes of AOG issued pursuant to the 10 3/8% Note Indenture; "10 3/8% Note Indenture" means the trust indenture providing for the issuance of the 10 3/8% Notes dated October 18, 2002 and made between AOG and Computershare Trust Company of Canada, as trustee; "14% Note Indenture" means the trust indenture providing for the issuance of the 14% Notes dated May 24, 2001 and made between AcquisitionCo and Computershare Trust Company of Canada, as trustee and as amended by the supplemental note indenture dated December 14, 2001; "14% Notes" means the 14% unsecured subordinated promissory notes of AOG issued pursuant to the 14% Note Indenture; "ABCA" means the Business Corporations Act (Alberta), R.S.A. 2000, c. B-9, as may be amended, including the regulations promulgated thereunder; "AcquisitionCo" means 925212 Alberta Ltd., a corporation incorporated under the ABCA that, prior to the Amalgamation, was wholly-owned by the Trust; "AcquisitionCo Units" means the units of AcquisitionCo, each such unit consisting of one AcquisitionCo common share and a Note; "Affiliate" or "Associate" when used to indicate a relationship with a person or company, means the same as set forth in the Securities Act (Alberta); "Amalgamation" means the amalgamation of AOG and AcquisitionCo pursuant to the Arrangement; "AOG" or "Corporation" means Advantage Oil & Gas Ltd., formerly Search Energy Corp., a corporation incorporated under the ABCA and a wholly-owned subsidiary of the Trust. All references to "AOG", unless the context otherwise requires, are references to Advantage Oil & Gas Ltd. and its predecessors; "Arrangement" means the transaction described under the heading "General Development of the Business - History and Development - Advantage Energy Income Fund"; "Arrangement Agreement" means the agreement dated April 18, 2001 between AOG, AcquisitionCo and the Trust pursuant to which such parties proposed to implement the Arrangement; "ARC" means credits or rebates in respect of Crown royalties which are paid or credited by the Crown, including those paid or credited under the Alberta Corporate Tax Act which are commonly known as "Alberta Royalty Credits"; 2 "Asset Transfer" means the transactions whereby the Vendors and Gascan transferred and assigned to Newco all of their respective right, title, estate and interest in and to the PNG Assets (as defined in the Share Purchase Agreement) in consideration of the issuance to the Vendors of common shares of Newco in accordance with the terms and conditions of the Asset Transfer Agreement; "Asset Transfer Agreement" means the agreement among the Vendors, Newco and Gascan providing for the Asset Transfer; "Audit Committee" means the audit committee of the Trust; "Best Pacific" means Best Pacific Resources Ltd., a corporation incorporated under the ABCA; "Best Pacific Acquisition" means the acquisition of Best Pacific by the Trust; "Board of Directors" or "Board" means the board of directors of AOG or its successors; "Business Day" means a day, which is not a Saturday, Sunday or statutory holiday, when banks in the place at which any action is required to be taken hereunder are generally open for the transaction of commercial banking business; "Common Shares" means voting common shares in the capital of AOG; "crude oil" or "oil" means a mixture, consisting mainly of pentanes and heavier hydrocarbons, that may contain sulphur compounds, that is liquid at the conditions under which its volume is measured or estimated, but excluding such liquids obtained from the processing of natural gas; "Debentures" means, collectively, the 8 1/4% Debentures, 9% Debentures and the 10% Debentures; "Distributable Income" means all amounts distributed or to be distributed in accordance with the Trust Indenture during any applicable period to Trust Unitholders; "Distribution Record Date" means, until otherwise determined by the Trustee, the last day of each month of each year, provided that if the last day of the month is not a Business Day, then the Distribution Record Date for such month will be the first Business Day following the last day of each month of the year or such other dates in any year determined from time to time by the Trustee, but December 31 in each year shall be a Distribution Record Date; "Due West" means Due West Resources Inc., a corporation incorporated under the ABCA, acquired by AOG on July 26, 2001 and amalgamated with AOG on August 1, 2001; "Gascan" means Gascan Resources Ltd., a corporation incorporated under the ABCA; "Gascan Acquisition" means the acquisition by AOG of all of the issued and outstanding securities of Newco pursuant to the Share Purchase Agreement; "Gascan Assets" means all of the PNG Assets (as defined in the Share Purchase Agreement); "General and Administrative Costs" means the amount in aggregate representing all expenditures and costs incurred by the Manager in carrying out its obligations or duties hereunder in respect of AOG, the Royalty or the Trust or in the management and administration of AOG, the Royalty and the Trust including, without limitation: (a) all reasonable costs and expenses relating to AOG, the Royalty and the Trust and paid directly to third parties by or on behalf of AOG, the Trust or their affiliates, including, without limitation, Trustee's fees; and (b) all reasonable costs and expenses incurred specifically for AOG or the Trust relating to AOG, the Royalty or the Trust including auditing, accounting, bookkeeping, rent and other leasehold expenses, legal, land administration, engineering, travel, telephone, data processing, reporting and all other reasonable costs and expenses approved by the Board, from time to time, and incurred by the Manager in discharging its obligations hereunder in respect of AOG, the Royalty or the Trust (other than the Management Fees). For greater clarity, employee bonuses and amounts paid to employees under incentive plans are not reimbursable; 3 "Initial Permitted Securities" means any equity or debt securities, or rights thereto, authorized or issued from time to time by AOG including, without limitation, the Common Shares, Preferred Shares and Notes; "Management Agreement" means the management, advisory and administration agreement dated May 24, 2001 among AcquisitionCo, the Manager and the Trustee on behalf of the Trust; "Management Fees" has the meaning set forth under the heading "Additional Information Respecting Advantage Investment Management Ltd. - Compensation and Term"; "Manager" means Advantage Investment Management Ltd., a corporation incorporated under the ABCA; "ManagementCo Group" means Affiliates and Associates of the Manager, and officers and directors (and their respective Associates) of the Manager and Affiliates of the Manager; "Market Capitalization" means an amount equal to the weighted average number of Trust Units outstanding for the Return Period times the Unit Market Price at the beginning of the Return Period; "MarkWest" means MarkWest Resources Canada Corp., a corporation incorporated under the ABCA; "MarkWest Properties" means the oil and natural gas properties that were owned by MarkWest; "Newco" means 960110 Alberta Ltd., being the wound-up, wholly-owned Subsidiary of AOG, which company was the legal and beneficial owner of the Gascan Assets upon completion of the Asset Transfer; "natural gas" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir which, under atmospheric conditions, is essentially gas but which may contain liquids. The natural gas reserve estimates are reported on a marketable basis; that is, the gas which is available to a transmission line after removal of certain hydrocarbons and non-hydrocarbon compounds present in the raw natural gas and which meets specifications for use as a domestic, commercial or industrial fuel; "natural gas liquids" or "NGLs" means those hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butanes and pentanes plus, or a combination thereof; "Note Indentures" means collectively, the 14% Note Indenture, 10 3/8% Note Indenture, 9 3/8% Note Indenture and the 8 1/2% Note Indenture; "Note Trustee" means Computershare Trust Company of Canada, or its successor as trustee under 14% Note Indenture, 10 3/8% Note Indenture, 9 3/8% Note Indenture and 8 1/2% Note Indenture; "Notes" means collectively, the 8 1/2% Notes, 9 3/8% Notes, 10 3/8% Notes and 14% Notes; "Oil and Natural Gas Properties" or "Properties" means the working, royalty or other interests of AOG in any petroleum and natural gas rights, tangibles and miscellaneous interests, including properties which may be acquired by AOG from time to time; "OPEC" means Organization of the Petroleum Exporting Countries; "Operating Cash Flow" means, in respect of any period for which Operating Cash Flow is calculated: (i) the amount received or receivable by AOG (on a consolidated basis) in respect of the sale of all Petroleum Substances from the Properties and any oil and gas revenue received in such period, including any commodity hedging gains and ARC but not including proceeds of the sale of Properties; plus (ii) income and distributions received by the Trust from any Permitted Investments, but not including any proceeds of sale of Permitted Investments; less (iii) expenditures paid or payable by or on behalf of AOG (on a consolidated basis) in respect of operating the Properties including, without limitation, the costs of gathering, compressing, processing, transporting and marketing all Petroleum Substances produced therefrom, commodity hedging losses and all other amounts paid to third parties which are calculated with reference to production from the Properties, including, without limitation, crown 4 royalties, gross overriding royalties and lessors' royalties, but for certainty not deducting the Royalty or any royalties payable to the Trust by AOG in all other respects; "Non-Voting Shares" means the non-voting common shares in the capital of AOG; "Permitted Investments" means, with respect to up to 25% of the total assets of the Trust, (unless otherwise approved by the Board of Directors from time to time): (i) obligations issued or guaranteed by the government of Canada or any province of Canada or any agency or instrumentality thereof; (ii) term deposits, guaranteed investment certificates, certificates of deposit or bankers' acceptances of or guaranteed by any Canadian chartered bank or other financial institutions (including the Trustee and any affiliate of the Trustee) the short-term debt or deposits of which have been rated at least A or the equivalent by Standard & Poor's Corporation, Moody's Investors Service, Inc. or Dominion Bond Rating Service Limited; (iii) commercial paper rated at least A or the equivalent by Dominion Bond Rating Service Limited, in each case maturing within 180 days after the date of acquisition; and (iv) trust units and limited partnership units in trusts and limited partnerships which invest in energy related assets including all types of petroleum and natural gas and energy related assets, and including, without limitation, facilities of any kind, oil sands interests, coal, electricity or power generating assets, and pipeline, gathering, processing and transportation assets; "person" means any individual, partnership, association, body corporate, trustee, executor, administrator, legal representative, government, regulatory authority or other entity; "Petroleum Substances" means petroleum, natural gas and related hydrocarbons (except coal) including, without limitation, all liquid hydrocarbons, and all other substances, including sulphur, whether gaseous, liquid or solid and whether hydrocarbon or not, produced in association with such petroleum, natural gas or related hydrocarbons; "Preferred Shares" means first preferred shares in the capital of AOG, which shares are issuable in series; "pro rata share" of any particular amount in respect of a holder of a Trust Unit at any time shall be the product obtained by multiplying the number of Trust Units that are owned by that Trust Unitholder at that time by the quotient obtained when the particular amount is divided by the total number of all Trust Units that are issued and outstanding at that time; "Reorganization" means the reorganization of AOG into an income trust structure; "Reorganization Agreement" means the reorganization letter agreement dated April 1, 2001 between AOG and the Manager; "Resource Properties" means Canadian resource properties as defined in the Tax Act; "Return Period" means the period for which the management fees under the Management Agreement are being calculated, which period shall be a calendar year, except for any year in which the Management Agreement is terminated, in which case the return period shall commence at the start of such year and end on the date of such termination; "Royalty" means the 95% interest in AOG 's Petroleum Substances within, upon or under certain of its Oil and Natural Gas Properties granted pursuant to the Royalty Agreement; "Royalty Agreement" means the amended and restated royalty agreement entered into between AOG and the Trust dated as of December 2, 2003 and providing for the creation of the Royalty; "Settled Amount" means the amount of one hundred dollars in lawful money of Canada paid by the settlor of the Trust to the Trustee for the purpose of settling the Trust; "Share Purchase Agreement" means the share purchase agreement between AOG and the Vendors dated November 28, 2001 providing for the purchase by AOG of all of the issued and outstanding shares of Newco; "Shareholder Agreement" means the shareholder agreement entered into as of May 24, 2001 between AOG and the Trustee, as trustee for and on behalf of the Trust; 5 "Sproule" means Sproule Associates Limited, independent geological and petroleum engineering consultants of Calgary, Alberta; "Sproule Report" means the independent engineering evaluation of AOG 's oil, NGL and natural gas interests prepared by Sproule dated April 19, 2004 and effective December 31, 2003; "Subsequent Investment" means those investments which the Trust is permitted to make pursuant to the Trust Indenture, namely royalties in respect of Properties and securities of AOG or any other Subsidiary of the Trust to fund the acquisition, development, exploitation and disposition of all types of petroleum and natural gas and energy related assets, including without limitation, facilities of any kind, oil sands interests, coal, electricity or power generating assets, and pipeline, gathering, processing and transportation assets and whether effected through an acquisition of assets or an acquisition of shares or other form of ownership interest in any entity the substantial majority of the assets of which are comprised of like assets; "Subsidiary" means, when used to indicate a relationship with another body corporate: (a) a body corporate which is controlled by (i) that other, or (ii) that other and one or more bodies corporate, each of which is controlled by that other, or (iii) two or more bodies corporate each of which is controlled by that other, or (b) a subsidiary of a body corporate that is the other's subsidiary; (c) and, in the case of the Trust, shall include AOG; "Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c.1, 5th Supplement, as amended; "Total Return Amount" means, in respect of any Return Period, an amount equal to the Total Return Percentage minus 8.0% if the Return Period is a full calendar year, and adjusted on a pro rata basis should the Return Period be less than a full calendar year, multiplied by the Market Capitalization for that Return Period; "Total Return Percentage" means the annual rate of return percentage to a holder of a Trust Unit for a particular Return Period based upon the difference between the Unit Market Price at the beginning and end of the Return Period plus the cash distributions per Trust Unit divided by the Unit Market Price at the beginning of the Return Period; "Trust", "Fund" or "Advantage" means Advantage Energy Income Fund, a trust established under the laws of Alberta pursuant to the Trust Indenture. All references to "Trust", "Advantage" or the "Fund", unless the context otherwise requires, are references to Advantage Energy Income Fund, its predecessors, and its subsidiaries; "Trustee" means Computershare Trust Company of Canada or such other trustee, from time to time, of Advantage Energy Income Fund; "Trust Fund", at any time, shall mean such of the following monies, properties and assets that are at such time held by the Trustee for the purposes of the Trust under the Trust Indenture: (i) the Settled Amount; (ii) the Initial Permitted Securities; (iii) the Royalty; (iv) all funds realized from the sale of, or Permitted Investments obtained in exchange for, Trust Units from time to time; (v) any Permitted Investments in which funds may from time to time be invested; (vi) any Subsequent Investments; (vii) any proceeds of disposition of any of the foregoing property including, without limitation, the Royalty but not Trust Units in the case of a redemption thereof to which Section 9.5 of the Trust Indenture applies; and (viii) all income, interest, dividends, return of capital, profit, gains and accretions and additional assets, rights and benefits of any kind or nature whatsoever arising directly or indirectly from or in connection with or accretions to or accruals in respect of any of the foregoing property or such proceeds of disposition from time to time; "Trust Indenture" means the amended and restated trust indenture dated as of May 28, 2003 between Computershare Trust Company of Canada and AOG; "Trust Unit" means a unit of the Trust, each unit representing an equal undivided beneficial interest therein; "Trust Unitholders" or "Unitholders" means the holders from time to time of the Trust Units; 6 "TSX" means the Toronto Stock Exchange; "Unit Market Price" of the Trust Units at any date means the weighted average of the trading price per Trust Unit for such Trust Units for the ten (10) consecutive trading days immediately preceding such date and the ten (10) consecutive trading days from and including such date, on the TSX or, if on such date the Trust Units are not listed on the TSX, on the principal stock exchange upon which such Trust Units are listed, or, if such Trust Units are not listed on any stock exchange, then on such over-the-counter market as may be selected for such purposes by the Board of Directors; "United States" or "US" means the United States of America; and "Vendors" means the holders of all of the issued and outstanding shares of Newco following the Asset Transfer and prior to the acquisition of Newco by AOG, and "Vendor" means any one of them. Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All dollar amounts set forth in this Annual Information Form are in Canadian dollars, except where otherwise indicated. ABBREVIATIONS
Oil and Natural Gas Liquids Natural Gas --------------------------- ----------- bbls barrels mcf thousand cubic feet mbbls thousand barrels mmcf million cubic feet mmbbls million barrels bcf billion cubic feet NGLs natural gas liquids mcf/d thousand cubic feet per day stb stock tank barrels of oil mmcf/d million cubic feet per day mstb thousand stock tank barrels of oil m(3) cubic metres mmboe million barrels of oil equivalent mmbtu million British Thermal Units boe/d barrels of oil equivalent per day GJ Gigajoule bbls/d barrels of oil per day Other ----- BOE or boe means barrel of oil equivalent, using the conversion factor of 6 mcf of natural gas being equivalent to one bbl of oil. The conversion factor used to convert natural gas to oil equivalent is not necessarily based upon either energy or price equivalents at this time. WTI means West Texas Intermediate. (Degree)API means the measure of the density or gravity of liquid petroleum products derived from a specific gravity. psi means pounds per square inch.
CONVERSION The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units). To Convert From To Multiply By --------------- -- ----------- mcf cubic metres 28.174 cubic metres cubic feet 35.494 bbls cubic metres 0.159 cubic metres bbls 6.289 feet metres 0.305 metres feet 3.281 miles kilometres 1.609 kilometres miles 0.621 acres hectares 0.405 hectares acres 2.471 gigajoules mmbtu 0.950 7 YOU SHOULD NOT RELY ON FORWARD-LOOKING STATEMENTS BECAUSE THEY ARE INHERENTLY UNCERTAIN This annual information form contains forward-looking statements. These statements relate to future events or the Trust's future performance. All statements other than statements of historical fact are forward-looking statements. The use of any of the words "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "should", "believe" and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Trust and AOG believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this annual information form should not be unduly relied upon. These statements speak only as of the date of this annual information form or as of the date specified in the documents incorporated by reference into this annual information form, as the case may be. In particular, this annual information form, and the documents incorporated by reference, contain forward-looking statements pertaining to the following: o oil and natural gas production levels; o the size of the oil and natural gas reserves; o projections of market prices and costs and the related sensitivities of distributions; o supply and demand for oil and natural gas; o expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; o treatment under governmental regulatory regimes; and o capital expenditures programs. The 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 annual information form: o volatility in market prices for oil and natural gas; o liabilities inherent in oil and natural gas operations; o uncertainties associated with estimating oil and natural gas reserves; o competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; o incorrect assessments of the value of acquisitions; o geological, technical, drilling and processing problems; and o the other factors discussed under "Risk Factors". These factors should not be construed as exhaustive. None of the Trust, the Manager, nor AOG undertakes any obligation to publicly update or revise any forward-looking statements. 8 ADVANTAGE ENERGY INCOME FUND Corporate Structure Advantage Energy Income Fund, Advantage Oil & Gas Ltd. and Advantage Investment Management Ltd. Advantage Energy Income Fund is an entity that provides monthly cash distributions to its Unitholders. Advantage was created under the laws of the province of Alberta pursuant to the Trust Indenture. It is, for Canadian tax purposes, an open-ended mutual fund trust and is categorized as a "natural resource issuer" for the purposes of Canadian securities laws. The Trust is administered by the Trustee. The beneficiaries of the Trust are the Unitholders. AOG is an oil and natural gas exploitation and development company that is wholly-owned by the Trust. It was originally incorporated in 1979 as Westrex Energy Corp. ("Westrex"). Through a plan of arrangement under the ABCA, Westrex merged with Search Energy Inc. on December 31, 1996, and changed its name to Search Energy Corp. ("Search") on January 2, 1997. The management of Westrex was, for the most part, replaced with the management of Search. The merger was accounted for as a "reverse take-over" in accordance with Canadian generally accepted accounting principles. Effective May 24, 2001, all of the issued and outstanding common shares of Search were acquired by AcquisitionCo, a corporation wholly-owned by the Trust, and Search and AcquisitionCo were then amalgamated and continued as "Search Energy Corp.". On July 26, 2001, Search acquired all of the shares of Due West. Due West's oil and natural gas properties were comprised of mainly long life natural gas and light oil reserves, many of which are operated by major exploration and development companies. Effective August 1, 2001, Search and Due West were amalgamated and continued as "Search Energy Corp.". Effective January 1, 2002 Search acquired the Gascan Assets. On June 26, 2002 Search changed its name to Advantage Oil & Gas Ltd. On November 18, 2002 AOG acquired all of the issued and outstanding shares of Best Pacific. On December 2, 2003 AOG acquired all of the issued and outstanding shares of Markwest Resources Canada Corp. In accordance with the Management Agreement, the Manager has agreed to act as manager of the Trust and AOG. The Manager is a Canadian-owned energy advisory management corporation, incorporated on March 19, 2001, pursuant to the provisions of the ABCA. The head office of the Trust and the Manager and the head office and the registered office of AOG is located at Suite 3100, 150 -6th Avenue S.W., Calgary, Alberta T2P 3H7. The registered office of the Manager is located at Suite 3700, 400 - 3rd Avenue S.W., Calgary, Alberta, T2P 4H2. Organizational Structure of the Trust The following diagram sets forth the organizational structure of the Trust as at the date hereof. 9 [GRAPHIC OMITTED] Notes: (1) The Unitholders own 100% of the Trust. (2) Cash distributions are made to Unitholders monthly based upon the Trust's cash flow. (3) AOG has two wholly-owned subsidiaries, namely Best Pacific Resources (U.S.) Inc. and Spirit Waste Management Inc., both of which corporations do not own any material assets. In accordance with the terms of the Trust Indenture and the Shareholder Agreement, holders of Trust Units are entitled to direct the Trust as to how to vote in respect of all matters to be placed before the Trust, including the selection of directors of AOG, approving AOG's financial statements, and appointing the auditors of AOG, who shall be the same as the auditors of the Trust. The Shareholder Agreement provides that the Unitholders are entitled to elect a majority of the Board of Directors and the Manager has the right to designate two of such directors. GENERAL DEVELOPMENT OF THE BUSINESS History and Development Search Energy Corp. 2001 During the fall of 2000 and in early 2001, management of Search reviewed strategic alternatives and considered possible methods for enhancing value for shareholders and ensuring the continued growth of Search. In February 2001, after reviewing a variety of alternatives and proposals, management of Search began to evaluate the benefits that might accrue to its shareholders if it reorganized itself into an income trust. Management requested that the Board of Directors give consideration to such reorganization. On February 23 and February 26, 2001, the Board of Directors met to consider various alternatives for Search, including the reorganization of Search into an income trust. After due deliberation and consideration of other alternatives available to Search, on February 28, 2001 the Board of Directors retained a third party advisor to assist Search in the evaluation of the reorganization proposal. The Board of Directors met on three further occasions and, after extensive review of Search's asset base and detailed production cash flow modeling, the Board of Directors concluded that the best alternative available to Search for maximizing value for shareholders would be to convert Search into an oil and gas income trust. See "General Development of the Business - History and Development - Advantage Energy Income Fund". On April 1, 2001, the Board of Directors unanimously approved the Reorganization Agreement and on April 12, 2001, the Board of Directors unanimously approved the Arrangement Agreement. 10 Advantage Energy Income Fund 2001 The Arrangement Agreement provided for implementation of the Arrangement pursuant to Section 193 of the ABCA. On May 24, 2001, each of the following events occurred in the following sequence: 1. the shareholder rights plan of Search and all outstanding rights issued pursuant thereto were terminated; 2. all of the right, title and interest of shareholders in the Common Shares were transferred to AcquisitionCo in exchange for AcquisitionCo Units on the basis of one AcquisitionCo Unit for every four Common Shares held, resulting in the acquisition by AcquisitionCo of all of the issued and outstanding Common Shares; 3. all of the right, title and interest of former shareholders in the AcquisitionCo Units were transferred to the Trust in exchange for Trust Units of the Trust on the basis of one Trust Unit for each AcquisitionCo Unit, resulting in the acquisition by the Trust of all of the issued and outstanding AcquisitionCo common shares and 14% Notes; 4. all right, title and interest of former Search optionholders who executed an option cancellation agreement exchanged their options with AcquisitionCo for AcquisitionCo Units which were, in turn, transferred to the Trust in exchange for Trust Units on the basis of one Trust Unit for each AcquisitionCo Unit. Any remaining options which were not subject to an option cancellation agreement and which had not, as at May 24, 2001, been exercised by the optionholder, were deemed to have been exchanged with the Trust for options to purchase Trust Units which were, in turn, exercised for Trust Units on May 25, 2001; and 5. Search and AcquisitionCo amalgamated and continued as one corporation, and: (a) all of the issued and outstanding Common Shares of Search, all of which were then held by AcquisitionCo, were cancelled without any repayment of capital; and (b) the amalgamated corporation continued as "Search Energy Corp." and adopted the articles of incorporation of AcquisitionCo. The Trust Units commenced trading on the TSX on May 29, 2001 under the symbol "AVN.UN". On July 26, 2001 Advantage acquired all of the issued and outstanding shares of Due West, a private light oil and natural gas company with working interests in several well-established properties. The Trust acquired all the shares of Due West at a price of $2.24 per share, for an aggregate cash consideration of $59.68 million (the "Due West Acquisition"). Advantage funded the Due West Acquisition using its existing credit facilities. On October 4, 2001, Advantage issued 5,000,000 Trust Units to the public at a price of $7.50 per Trust Unit for gross proceeds of $37,500,000. On October 11, 2001, Advantage issued an additional 750,000 Trust Units pursuant to the exercise of the underwriters' over-allotment option at a price of $7.50 per Trust Unit for additional gross proceeds of $5,625,000. The aggregate net proceeds of $43,125,000 were used by Advantage to reduce its debt (a substantial portion of which was incurred to fund the Due West Acquisition), to fund future acquisitions and capital expenditures, and for general corporate purposes. On November 28, 2001, Advantage and the Vendors entered into the Share Purchase Agreement providing for the acquisition by the Trust of all of the issued and outstanding securities of Newco, which company, as of the closing date of the Asset Transfer, was the legal and beneficial owner of the Gascan Assets. The effective date of the Gascan Acquisition was January 1, 2002 with closing occurring on January 4, 2002. The net cash consideration payable by the Trust in respect of the Gascan Acquisition was $69 million prior to adjustments. On December 18, 2001, Advantage issued 6,014,500 Trust Units to the public at a price of $7.65 per Trust Unit for gross proceeds of $46,010,925. The net proceeds of the issue were used by Advantage to repay a portion of Advantage's long term debt, some of which was incurred in connection with the acquisition of the Gascan Assets owned by Newco. 11 2002 On January 29, 2002, Advantage issued 2,500,000 Trust Units to the public at a price of $7.90 per Trust Unit for gross proceeds of $19,750,000. The net proceeds of the issue were used by Advantage to complete the acquisition of certain natural gas properties, to repay bank debt and to fund Advantage's 2002 capital expenditure program. The first annual and special meeting of Unitholders was held on June 25, 2002. At such meeting, Unitholders considered and approved various matters including the name change from "Search Energy Corp." to "Advantage Oil & Gas Ltd.", the addition of a class of non-voting common shares for AOG, certain amendments to the Trust Indenture and the pre-authorization of private placements of Trust Units during the ensuing 12-month period. On September 10, 2002, Advantage completed an asset exchange transaction whereby it acquired additional interests in producing natural gas properties at Vermilion, Alberta in consideration for Advantage's interest in heavy oil properties located in Wainwright, Alberta. The exchange was structured as a property swap with Advantage neither receiving nor paying any cash in relation to the transaction. Based upon the reserve engineering reports of Sproule dated July 1, 2002 and January 1, 2002, the Fund acquired approximately 14.7 bcf (2.5 mmboe) of established natural gas reserves at Vermilion in exchange for 2.2 mmboe of established heavy oil reserves, of which 61% were classified as proved. On September 30, 2002, Advantage announced that it had entered into an acquisition agreement with Best Pacific providing for the purchase of all of the issued and outstanding common shares of Best Pacific, including all shares issued upon the exercise of outstanding options and warrants (the "Best Pacific Shares"), on the basis of $1.25 cash consideration for each Best Pacific Share (the "Offer"). The Offer was made by formal take-over bid circular which was mailed on October 11, 2002. The Offer expired on November 18, 2002, with Advantage acquiring 95% of the Best Pacific Shares on such date and completing the compulsory acquisition of the remaining 5% of the Best Pacific Shares effective November 21, 2002. The acquisition of Best Pacific had a net purchase price, after adjustments and fees, of approximately $53.4 million, which amount includes the assumption of approximately $21.7 million of net debt. The properties owned by Best Pacific consisted primarily of high working interest natural gas and light oil properties located in southern Alberta and southeastern Saskatchewan. In conjunction with the acquisition of Best Pacific, Advantage announced on September 30, 2002 that it had signed an agreement providing for the offering on a bought deal basis of $55,000,000 aggregate principal amount of Debentures. The Debentures have a coupon of 10%, mature on November 1, 2007 and are convertible into Trust Units at a price of $13.30 per Trust Unit. Interest is payable on the Debentures semi-annually, with the first interest payment to occur on May 1, 2003. The offering of Debentures closed on October 18, 2002, with the net proceeds of the offering used to fund the acquisition of Best Pacific, to reduce bank indebtedness and for general corporate purposes. 2003 On January 24, 2003, Advantage announced the appointment of Peter Hanrahan to the position of Chief Financial Officer in addition to his prior position as Controller. At an annual and special meeting of Unitholders held on May 28, 2003, Unitholders considered and approved various matters including amendments to the Trust Indenture, the issuance of up to 1,500,000 Trust Units to the Manager in payment of its performance fee under the Management Agreement and the pre-authorization of private placements of Trust Units during the ensuing 12 month period. On July 8, 2003, Advantage completed the issue, by way of short form prospectus, of $30,000,000 principal amount of 9% convertible unsecured subordinated debentures through a syndicate of underwriters. The convertible debentures had a face value of $1,000 each with a coupon of 9%, maturing on August 1, 2008 and are convertible into Trust Units at $17.00 per Trust Unit. The net proceeds of the offering were used to fund an expanded capital expenditure program and to repay debt. On December 8, 2003, Advantage completed a second issue, by way of short form prospectus, of 5,100,000 Trust Units at $15.75 per Trust Unit for gross proceeds of $80,325,000 and $60,000,000 aggregate principal amount of 8 1/4% convertible unsecured 12 subordinated debentures through a syndicate of underwriters. The convertible debentures had a face value of $1,000 each with a coupon of 8 1/4%, maturing on February 1, 2009 and are convertible into Trust Units at $16.50 per Trust Unit. The net proceeds of the offering were used to fund the acquisition of MarkWest, to reduce amounts outstanding under Advantage's credit facility and to fund drilling and exploitation capital expenditures. In conjunction with the completion of the December financing, Advantage also announced the completion of the MarkWest acquisition. The acquisition was made for total cash consideration of $96,800,000 prior to adjustments. DESCRIPTION OF THE BUSINESS AND OPERATIONS Advantage Energy Income Fund The Trust is a limited purpose trust and is restricted to: 1. investing in the Initial Permitted Securities, the Permitted Investments, Subsequent Investments and such other securities and investments as AOG may determine, provided that under no circumstances shall the Trustee, AOG or the Manager purchase or authorize the purchase of any security, asset or investment (collectively a "Prohibited Investment") on behalf of the Trust or using any Trust assets or property which is defined as "foreign property" under subsection 206(1) of the Tax Act or is a "small business security" as that expression is used in Part LI of the Regulations to the Tax Act or would result in the Trust not being considered either a "unit trust" or a "mutual fund trust" for purposes of the Tax Act at the time such investment was made; 2. disposing of any part of the Trust Fund, including, without limitation, any Permitted Investments; 3. acquiring the Royalty and other royalties in respect of Resource Properties; 4. temporarily holding cash, and Permitted Investments (including investments in AOG) for the purposes of paying Trust expenses and Trust liabilities, paying amounts payable by the Trust in connection with the redemption of any Trust Units, and making distributions to Unitholders; 5. acquiring or investing in securities of AOG or any other Subsidiary of the Trust to fund the acquisition, development, exploitation and disposition of all types of petroleum and natural gas related assets, including, without limitation, facilities of any kind and whether effected through the acquisition of assets or the acquisition of shares or other form of ownership interest in any entity, the substantial majority of the assets of which are comprised of like assets; 6. undertaking such other business and activities including investing in securities as shall be approved by AOG from time to time provided that the Trust shall not undertake any business or activity which is a Prohibited Investment (as defined in the Trust Indenture); and to pay the costs, fees and expenses associated therewith or incidental thereto. In accordance with the terms of the Trust Indenture, the Trust will make cash distributions to Trust Unitholders of the interest income earned from the 14% Notes, royalty income earned on the Royalty, dividends (if any) received on, and amounts, if any, received on redemption of, Common Shares and Preferred Shares, and income and distributions received from any Permitted Investments after expenses and capital expenditures, any cash redemptions of Trust Units, and other expenditures. See "Additional Information Respecting Advantage Energy Income Fund - Cash Distributions". Advantage Oil & Gas Ltd. AOG is actively engaged in the business of oil and gas exploration, development, acquisition and production in the provinces of Alberta, British Columbia and Saskatchewan. The Trust employs a strategy to maintain production from AOG's existing production base while focusing capital expenditures on low-risk development opportunities. AOG utilizes financial hedges, when deemed appropriate, to manage and reduce the volatility in commodity prices. See "Risk Factors". AOG generally sells or farms out higher risk projects while actively pursuing 13 growth opportunities through oil and gas property acquisitions, as well as through corporate acquisitions. AOG targets acquisitions that are accretive to net asset value and that increase the Trust's reserve and production base per Trust Unit outstanding. Acquisitions must also meet reserve life index criteria and exhibit low risk opportunities to increase reserves and production. It is currently intended that AOG will finance acquisitions and investments through bank financing and the issuance of additional Trust Units from treasury, maintaining prudent leverage. Significant Acquisitions Effective October 1, 2003, Advantage acquired all of the shares of MarkWest, a wholly-owned subsidiary of MarkWest Hydrocarbon, Inc., for total cash consideration of $96,800,000 prior to adjustments. The MarkWest Properties consist primarily of natural gas assets located in southeast Alberta and central Alberta which at the date of acquisition was producing approximately 4,448 boe/d (approximately 91% of which is natural gas). Approximately 98% of the production from the MarkWest Properties is operated by MarkWest with MarkWest having approximately a 78% average working interest in such production. Audited financial statements as at and for the year ended December 31, 2002 and unaudited financial statements as at and for the six months ended June 30, 2003 are attached hereto as Schedule "A". Effective January 1, 2002, Advantage acquired the Gascan Assets. Selected pro-forma combined operational information, financial information, as well as production and drilling histories for the Gascan Assets on an historical basis are set forth in the Trust's Renewal Annual Information Form dated May 16, 2002. STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION The statement of reserves data and other oil and gas information set forth below (the "Statement") is dated December 31, 2003. The effective date of the Statement is December 31, 2003 and the preparation date of the Statement is April 19, 2004. Disclosure of Reserves Data The reserves data set forth below (the "Reserves Data") is based upon an evaluation by Sproule Associates Limited ("Sproule") with an effective date of December 31, 2003 contained in a report of Sproule dated April 19, 2004 (the "Sproule Report"). The Reserves Data summarizes the oil, liquids and natural gas reserves of the Corporation and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Reserves Data conforms with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional information not required by NI 51-101 has been presented to provide continuity and additional information which we believe is important to the readers of this information. Advantage Energy Income Fund engaged Sproule to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves. All of the Trust's reserves are in Canada and, specifically, in the provinces of Alberta, British Columbia and Saskatchewan. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the constant prices and costs assumptions and forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of the Trust's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. 14 Reserves Data (Constant Prices and Costs) SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE as of December 31, 2003 CONSTANT PRICES AND COSTS
Reserves --------------------------------------------------------------------------------------------------- Light And Medium Oil Heavy Oil Natural Gas Natural Gas Liquids --------------------- --------------------- --------------------- --------------------- Gross Net Gross Net Gross Net Gross Net RESERVES CATEGORY (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mbbl) (mbbl) -------------------------- -------- -------- -------- -------- -------- -------- -------- -------- PROVED Developed Producing 5,762.2 5,239.6 18.1 15.3 156,904 135,432 1,588.5 1,198.2 Developed Non-Producing 67.6 53.0 0.0 0.0 7,766 6,510 67.1 50.3 Undeveloped 734.3 618.5 0.0 0.0 21,161 17,084 197.3 141.0 -------- -------- -------- -------- -------- -------- -------- -------- TOTAL PROVED 6,564.1 5,911.1 18.1 15.3 185,830 159,026 1,853.0 1,389.5 PROBABLE 4,685.6 4,081.2 2.0 1.6 53,512 44,403 800.1 595.8 -------- -------- -------- -------- -------- -------- -------- -------- TOTAL PROVED PLUS PROBABLE 11,249.7 9,992.3 20.1 17.0 239,343 203,429 2,653.1 1,985.3 ======== ======== ======== ======== ======== ======== ======== ========
Net Present Values Of Future Net Revenue ----------------------------------------------------------------------------------------------------- Before Income Taxes Discounted at ($000's) After Income Taxes Discounted at ($000's) ------------------------------------------------- ------------------------------------------------- RESERVES CATEGORY 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% -------------------------- --------- ------- ------- ------- ------- --------- ------- ------- ------- ------- PROVED Developed Producing 741,476 544,378 441,520 377,541 333,278 741,476 544,378 441,520 377,541 333,278 Developed Non-Producing 36,615 31,451 26,569 22,829 20,004 36,615 31,451 26,569 22,829 20,004 Undeveloped 69,527 62,699 52,136 42,782 35,217 69,527 62,699 52,136 42,782 35,217 --------- ------- ------- ------- ------- --------- ------- ------- ------- ------- TOTAL PROVED 847,617 638,527 520,226 443,152 388,500 847,617 638,527 520,226 443,152 388,500 PROBABLE 302,928 178,492 125,592 96,293 77,518 302,928 178,492 125,592 96,293 77,518 --------- ------- ------- ------- ------- --------- ------- ------- ------- ------- TOTAL PROVED PLUS PROBABLE 1,150,545 817,018 645,818 539,446 466,018 1,150,545 817,018 645,818 539,446 466,018 ========= ======= ======= ======= ======= ========= ======= ======= ======= =======
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) as of December 31, 2003 CONSTANT PRICES AND COSTS ($000's)
Future Net Future Net Revenue Well Revenue After Reserves Operating Development Abandonment Before Income Income Category Revenue Royalties Costs Costs Costs Income Taxes Taxes Taxes ----------- --------- --------- --------- ----------- ---------- ------------ --------- ---------- PROVED 1,396,530 196,829 288,297 42,993 20,794 847,617 0 847,617 PROVED PLUS 1,911,541 281,772 401,264 56,425 21,537 1,150,545 0 1,150,545 PROBABLE
15 FUTURE NET REVENUE BY PRODUCTION GROUP as of December 31, 2003 CONSTANT PRICES AND COSTS
Future Net Revenue Before Income Taxes (Discounted At 10%/Year) Reserves Category Production Group ($000's) -------------------- ------------------------------------------------------------- ------------------------------ PROVED Light and Medium Crude Oil (including solution gas and other by-products) 87,023 Heavy Oil (including solution gas and other by-products) 123 Natural Gas (including by-products but excluding solution gas from oil wells) 428,619 PROVED PLUS PROBABLE Light and Medium Crude Oil (including solution gas and other by-products) 139,100 Heavy Oil (including solution gas and other by-products) 139 Natural Gas (including by-products but excluding solution gas from oil wells) 501,688
Reserves Data (Forecast Prices and Costs) SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE as of December 31, 2003 FORECAST PRICES AND COSTS
Reserves --------------------------------------------------------------------------------------------------- Light And Medium Oil Heavy Oil Natural Gas Natural Gas Liquids --------------------- --------------------- --------------------- --------------------- Gross Net Gross Net Gross Net Gross Net RESERVES CATEGORY (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mbbl) (mbbl) -------------------------- -------- -------- -------- -------- -------- -------- -------- -------- PROVED Developed Producing 5,613.6 5,115.6 5.1 4.3 155,000 133,801 1,575.5 1,188.1 Developed Non-Producing 67.6 53.3 -- -- 8,237 6,953 67.1 50.3 Undeveloped 734.2 621.5 -- -- 21,187 17,106 198.3 141.8 -------- -------- -------- -------- -------- -------- -------- -------- TOTAL PROVED 6415.4 5,790.3 5.1 4.3 184,423 157,860 1,840.8 1,380.2 PROBABLE 4,637.8 4,057.5 0.6 0.5 53,018 43,981 797.7 593.1 -------- -------- -------- -------- -------- -------- -------- -------- TOTAL PROVED PLUS PROBABLE 11,053.2 9,847.8 5.7 4.8 237,441 201,840 2,638.5 1,973.3 ======== ======== ======== ======== ======== ======== ======== ========
Net Present Values Of Future Net Revenue ----------------------------------------------------------------------------------------------------- Before Income Taxes Discounted at ($000's) After Income Taxes Discounted at ($000's) ------------------------------------------------- ------------------------------------------------- RESERVES CATEGORY 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% -------------------------- --------- ------- ------- ------- ------- --------- ------- ------- ------- ------- PROVED Developed Producing 611,535 449,966 366,835 315,828 280,866 611,535 449,966 366,835 315,828 280,866 Developed Non-Producing 30,982 26,048 22,038 19,029 16,769 30,982 26,048 22,038 19,029 16,769 Undeveloped 43,529 40,233 33,333 26,784 21,346 43,529 40,233 33,333 26,784 21,346 --------- ------- ------- ------- ------- --------- ------- ------- ------- ------- TOTAL PROVED 686,045 516,247 422,206 361,641 318,980 686,045 516,247 422,206 361,641 318,980 PROBABLE 260,192 143,230 97,844 73,969 59,088 260,192 143,230 97,844 73,969 59,088 --------- ------- ------- ------- ------- --------- ------- ------- ------- ------- TOTAL PROVED PLUS PROBABLE 946,237 659,477 520,050 435,610 378,068 946,237 659,477 520,050 435,610 378,068 ========= ======= ======= ======= ======= ========= ======= ======= ======= =======
16 TOTAL FUTURE NET REVENUE (UNDISCOUNTED) as of December 31, 2003 FORECAST PRICES AND COSTS ($000's)
Future Net Future Net Revenue Well Revenue After Reserves Operating Development Abandonment Before Income Income Category Revenue Royalties Costs Costs Costs Income Taxes Taxes Taxes ----------- --------- --------- --------- ----------- ---------- ------------ --------- ---------- PROVED 1,251,950 172,303 324,096 43,153 26,353 688,045 0 688,045 PROVED PLUS 1,745,915 247,767 466,072 56,745 29,093 946,238 0 946,238 PROBABLE
FUTURE NET REVENUE BY PRODUCTION GROUP as of December 31, 2003 FORECAST PRICES AND COSTS
Future Net Revenue Before Income Taxes (Discounted At 10%/Year) Reserves Category Production Group ($000's) -------------------- ------------------------------------------------------------- ------------------------------ PROVED Light and Medium Crude Oil (including solution gas and other by-products) 65,031 Heavy Oil (including solution gas and other by-products) (40) Natural Gas (including by-products but excluding solution gas from oil wells) 352,717 PROVED PLUS PROBABLE Light and Medium Crude Oil (including solution gas and other by-products) 102,678 Heavy Oil (including solution gas and other by-products) (39) Natural Gas (including by-products but excluding solution gas from oil wells) 412,484
Pricing Assumptions The following tables set forth the benchmark reference prices, as at December 31, 2003, reflected in the Reserves Data. These price assumptions were provided to the Trust by Sproule, the Trust's independent qualified reserves evaluator. 17 SUMMARY OF PRICING ASSUMPTIONS as of December 31, 2003 CONSTANT PRICES AND COSTS Natural Gas Edmonton Liquids Par Price Natural Gas(1) Fob(1) Exchange 40(degrees) Api Aeco Gas Price Field Gate Rate(2) Year ($Cdn/bbl) ($Cdn/mmbtu) ($Cdn/bbl) ($US/$Cdn) ------------- --------------- -------------- ----------- ---------- 2003 Year End $37.61 $ 5.87 $33.83 0.75 Notes: (1) The exchange rate used to generate the benchmark reference prices in this table. SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS as of December 31, 2003 FORECAST PRICES AND COSTS
Oil Pentanes Wti Edmonton Cromer Plus Cushing Par Price Medium Natural Gas Fob Oklahoma 40(degrees) Api 29.3(degrees) Api Aeco Gas Price Field Gate Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/Mmbtu) ($Cdn/bbl) ---------- --------- --------------- ----------------- -------------- ---------- Forecast 2004 29.63 37.99 32.99 6.04 38.91 2005 26.80 34.24 29.44 5.36 35.07 2006 25.76 32.87 28.47 4.80 33.67 2007 26.14 33.37 29.07 4.91 34.17 2008 26.53 33.87 29.54 4.98 34.69 Thereafter VARIOUS ESCALATION RATES Butanes Propanes Fob Fob Inflation Exchange Field Gate Field Gate Rates(1) Rate(2) Year ($Cdn/bbl) ($Cdn/bbl) %/Year ($US/$Cdn) ---------- ---------- ---------- -------- ---------- Forecast 2004 31.15 28.04 1.5 0.75 2005 25.52 22.56 1.5 0.75 2006 23.28 20.58 1.5 0.75 2007 23.63 20.89 1.5 0.75 2008 23.98 21.20 1.5 0.75 Thereafter
Notes: (1) Inflation rates for forecasting prices and costs. (2) Exchange rates used to generate the benchmark reference prices in this table. Weighted average historical prices realized by the Trust for the year ended December 31, 2003, were $6.07/mcf for natural gas, $39.32/bbl for crude oil, $32.54/bbl for natural gas liquids. Reconciliations of Changes in Reserves and Future Net Revenue The following table sets forth the reconciliation in the Trust's net reserves for the year ended December 31, 2003 using forecast price and cost estimates derived from the Sproule Report, reconciled to the Trust's net reserves at December 31, 2002. See the note following the table for a discussion of the basis upon which net reserves were calculated at December 31, 2002. 18 RECONCILIATION OF TRUST NET RESERVES BY PRINCIPAL PRODUCT TYPE FORECAST PRICES AND COSTS
Light And Medium Oil Heavy Oil ------------------------------------ ------------------------------------ Net Net Proved Proved Net Net Plus Net Net Plus Proved Probable Probable Proved Probable Probable FACTORS (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) ------------------- -------- -------- -------- -------- -------- -------- December 31 2002(1) 8,249 2,298 10,547 44 4 48 Extensions 280 511 791 0 0 0 Improved 0 0 0 0 0 0 Recovery Technical (1,986) 1,297 (689) (27) (3) (30) Revisions Discoveries 0 0 0 0 0 0 Acquisitions 395 62 457 0 0 0 Dispositions (453) (110) (563) 0 0 0 Economic 0 0 0 0 0 0 Factors Production(2) (695) 0 (695) (13) 0 (13) -------- -------- -------- -------- -------- -------- December 31, 2003 5,790 4,058 9,848 4 1 5 ======== ======== ======== ======== ======== ======== Associated And Non-Associated Gas Natural Gas Liquids ------------------------------------ ------------------------------------ Net Net Proved Proved Net Net Plus Net Net Plus Proved Probable Probable Proved Probable Probable FACTORS (mbbl) (mbbl) (mbbl) (mmcf) (mmcf) (mmcf) ------------------- -------- -------- -------- -------- -------- -------- December 31 2002(1) 152,933 37,808 190,741 1,130 542 1,672 Extensions 6,006 2,871 8,877 7 2 9 Improved 4,758 1,808 6,566 75 24 99 Recovery Technical (15,385) (4,817) (20,202) 96 (25) 71 Revisions Discoveries 4,908 977 5,885 0 0 0 Acquisitions 24,384 5,420 29,804 251 50 301 Dispositions (653) (86) (739) (19) 0 (19) Economic 0 0 0 0 0 0 Factors Production(2) (19,091) 0 (19,091) (160) 0 (160) -------- -------- -------- -------- -------- -------- December 31, 2003 157,860 43,981 201,840 1,380 593 1,973 ======== ======== ======== ======== ======== ========
Note: (1) The evaluation as at December 31, 2002 was prepared using National Policy 2-B reserves definitions. Under those definitions, probable reserves were adjusted by a factor to account for the risk associated with their recovery. The Trust previously applied a risk factor of 50% in reporting probable reserves. Under NI 51-101 reserves definitions, estimates are prepared such that the full proved plus probable reserves are estimated to be recoverable (proved plus probable reserves are effectively a "best estimate"). The above reconciliation reflects current probable reserves versus previous risk adjusted (50%) probable reserves reported by the Trust. (2) Includes Markwest production from Oct 1 - Dec 31, 2003. 19 The following table sets forth the reconciliation of the Trust's net present values of future net revenue for the year ended December 31, 2003 using constant price and cost estimates derived from the Sproule Report. RECONCILIATION OF CHANGES IN NET PRESENT VALUES OF FUTURE NET REVENUE DISCOUNTED AT 10% PER YEAR PROVED RESERVES CONSTANT PRICES AND COSTS ($000's)
Period And Factor 2003 --------------------------------------------------------------------------------------- ------ Estimated Future Net Revenue at Beginning of Year 522.5 Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (112.0) Net Change in Prices, Production Costs and Royalties Related to Future Production 5.3 Actual Development Costs Incurred During the Period 68.2 Changes in Estimated Future Development Costs (73.1) Extensions and Improved Recovery 36.3 Discoveries 17.4 Acquisitions of Reserves 95.2 Dispositions of Reserves (9.8) Net Change Resulting from Revisions in Quantity Estimates (82.1) Accretion of Discount 52.3 Net Change in Income Taxes -- ------ Estimated Future Net Revenue at End of Year 520.2 ======
Additional Information Relating to Reserves Data Undeveloped Reserves Proved and probable undeveloped reserves have been assigned in accordance with engineering and geological practices as defined under NI 51-101. In general, undeveloped reserves are planned to be developed over the next two years with close to 75 percent being completed in 2004. 20 Future Development Costs The following table sets forth development costs deducted in the estimation of the Trust's future net revenue attributable to the reserve categories noted below.
Forecast Prices And Costs Constant Prices And Costs ------------------------------------------- ------------------------------------------- Year Proved Plus Probable Proved Plus Probable Proved Reserves Reserves Proved Reserves Reserves ------------------ -------------------- ------------------ -------------------- 0% 10% 0% 10% 0% 10% 0% 10% ------ ------ ------ ------ ------ ------ ------ ------ 2004 34,165 32,312 39,782 37,750 34,165 32,312 39,782 37,750 2005 8,585 7,381 14,417 12,390 8,459 7,273 14,204 12,207 2006 41 32 2,050 1,602 40 31 1,990 1,555 2007 32 23 43 31 31 22 41 29 2008 0 0 0 0 0 0 0 0 Thereafter 330 174 453 220 298 158 408 197 ------ ------ ------ ------ ------ ------ ------ ------ Total 43,153 39,922 56,745 51,992 42,993 39,796 56,425 51,738 ====== ====== ====== ====== ====== ====== ====== ======
Other Oil and Gas Information Oil and Gas Properties The following is a description of Advantage's principal oil and natural gas properties on production or under development as at January 1, 2004. The term "net", when used to describe Advantage's share of production, means the total of Advantage's working interest share before deduction of royalties owned by others. Reserve amounts are stated, before deduction of royalties, at December 31, 2004, based upon escalating cost and price assumptions (gross) as evaluated in the Sproule Report (see "Description of the Business and Operations Oil and Natural Gas Reserves"). Unless otherwise specified, gross and net acres and well count information are as at January 1, 2004. Information in respect of current production is 2003 exit production, net to Advantage, except where otherwise indicated. Medicine Hat, Alberta The Medicine Hat area is located in southeastern Alberta where Advantage has a 100% working interest in 24 sections of land. Production in the area comes from all of the main shallow gas formations including the Medicine Hat "A", "C" and "D" sands, both the Upper and Lower Milk River, as well as the Second White Specks sands. When the property was acquired in January 2002 there were 115 wells producing 5.2 mmcf/d of natural gas. In 2002 and 2003, several recompletions along with an additional 164 wells were drilled on this property. Late in 2003 and continuing into early 2004, an additional 57 wells were drilled and will be completed during 2004. Exiting 2003, this property was producing 18.6 mmcf/d from approximately 300 wells. Another 43 wells are planned for drilling and are expected to be on-stream during the second half of 2004. Compression capacity was also increased in late 2003 by approximately 10 mmcf/d to accommodate added production from the 2004 drilling programs. Sproule evaluated Advantage's reserves in the area and assigned 73.8 bcf of proved natural gas reserves and 8.3 bcf of probable reserves. As such, this property is Advantage's largest property on an assigned reserves basis. Wainwright and Kinsella, Alberta These properties cover varying working interests averaging more than 80% in approximately 175 sections of land, located in east central Alberta, approximately 40 kilometers northwest of Wainwright, Alberta. Current combined production from these areas is 5.6 mmcf/d. In 2002, Advantage swapped out virtually all of its heavy oil assets which were concentrated in this area for producing natural gas assets in Advantage's other core area of Vermilion, immediately to the north of this property. Natural gas production occurs from the Manville Group and Viking Formations. All production occurs from shallow depths of between 450 and 700 meters. The Fund operates 95% of its natural gas production in this area and owns a majority interest in and operates an extensive gas gathering system tying into three Advantage-operated gas compression facilities 21 Advantage has downspaced almost a township of land to allow for the drilling of two Viking wells per section. In 2003, Advantage drilled 23.3 net wells which encountered a combination of Viking and Upper Mannville zones. The Viking zone represents long life reserves with moderate producing rates. Advantage has approximately 2 1/2 townships of land covered with three-dimensional ("3D") seismic to aid in the selection of these drilling locations. Sproule evaluated Advantage's proved reserves in the Wainwright and Kinsella areas and assigned 7.7 bcf of natural gas and 4.0 mbbls of oil. Probable reserves for Advantage in this area were evaluated by Sproule at 6.1 bcf of natural gas and 0.6 mbbls of oil. Stoddart/North Pine, British Columbia The Stoddart/North Pine area lies immediately northwest of the town of Fort St. John in northeast British Columbia. The area contains multiple producing horizons, predominantly natural gas from the Permian, Belloy formation and oil from the Triassic, Charlie Lake formation. Production from this area has very low decline rates, is low cost and required minimal capital expenditures. Advantage owns an interest in 30 producing wells (22 net) in the area. Advantage operates approximately 80% of the natural gas production and has a 40% working interest in the oil production. The area includes 12,000 gross (9,176 net) acres of undeveloped land. Current production from this area is 4.1 mmcf/d of natural gas and 233 bbls/d of light oil and NGLs. Sproule evaluated Advantage's proved reserves in the area and assigned 11.5 bcf of natural gas and 477.9 mbbls of crude oil and NGLs. In addition, 3.1 bcf of probable natural gas reserves and 164.7 mbbls of probable crude oil and NGLs reserves have been assigned to this property. Shouldice, Alberta The Shouldice area of southern Alberta is located approximately 45 kilometers southeast of the city of Calgary. Advantage has an average working interest of more than 85% in 34 sections of land and operates in excess of 90% of its production. Much of this acreage is downspaced to accommodate additional stepout and infill drilling. Natural gas production of approximately 7.0 mmcf/d is produced on a co-mingled basis from the Medicine Hat sand with various Belly River Formation sands. In addition to natural gas, Advantage also produced 57 bbls/d of medium gravity (33(degree) API) crude oil. This production is from the deeper, Mannville formation, Basal Quartz sands. During 2003, 20 net wells were added to the existing 70 producers. Both natural gas and crude oil are produced and gathered through company owned facilities of varying working interests. An additional 38 new locations are licenced for drilling which will commence in the second quarter of 2004. Theses will target the Medicine Hat and Belly River Formations with 5 targeting the deeper Bow Island Formation. Advantage is adding an additional 4 mmcf/d of new compression capacity to handle the expected production increase. The Sproule Report assigns 14.4 bcf of proven natural gas reserves and 100.2 mbbls of proven crude oil and NGLs to this property. In addition, 3.2 bcf of probable natural gas reserves and 16.0 mbbls of probable crude oil and NGLs reserves have been assigned to this property. Bantry, Alberta Bantry is located immediately east of the town of Brooks and consists of 86 sections of land ranging between 50 and 100% working interest, with over half at 100%. This property was acquired in December 2003 with the acquisition of MarkWest Resources. Since the acquisition, 25 new wells were drilled of which 18 earned additional acreage through a farm-in arrangement with a major integrated oil company. Eleven additional sections will be earned through this farm-in arrangement in the first half of 2004. Production occurs primarily from various sandstones within the Bow Island Formation as well as from Basal Colorado Formation channel sandstones. Drilling is shallow with average well depths less than 1,000 meters. Natural gas is gathered into Advantage operated compression and dehydration facilities and current net production from this area is approximately 14.7 mmcf/d. Advantage has added 15 mmcf/d gross of additional compression capacity in the first quarter of 2004 to handle additional volumes from the new drilling. Completion and tie-in of the new drills has been delayed due to spring break-up but production is anticipated to be on-stream by the end of the second quarter 2004. 22 The Sproule Report assigns 19.5 bcf of proven natural gas reserves and 35 mbbls of proven NGL reserves to this property. In addition, 6.0 bcf of probable natural gas reserves and 10.7 mbbls of probable NGL reserves have been assigned to this property. Nevis, Alberta The Nevis property was acquired in December 2003 with the acquisition of Markwest Resources. Situated 50 km east of Red Deer, Nevis consists of approximately 32 sections of land with an average working interest over 75%. Natural gas production occurs from numerous shallow depth horizons including the Edmonton, Belly River and Viking formations. Oil and natural gas is produced from several slightly deeper reservoirs in the Glauconite, Ostacod and Ellerslie formations of the Mannville Group. Recent drilling in the Wabamun formation is developing oil and natural gas production from 2 to 4 meter thick carbonate reservoirs at the top of the formation, which occurs at moderate depths of 1,600 meters. Current net production to Advantage is 3.6 mmcf/d of natural gas and 302 bbls/d of crude oil and NGLs. Advantage operates 90% of its Nevis properties. Natural gas is gathered through company owned pipelines and processed at a third party plant. Oil is trucked from single well batteries. The Sproule Report assigns 9.5 bcf of proven natural gas reserves and 917.3 mbbls of proven crude oil and NGLs reserves to this property. In addition, 4.5 bcf of probable natural gas reserves and 952.5 mbbls of risked probable crude oil and NGLs reserves have been assigned to this property. Oil And Gas Wells The following table sets forth the number and status of wells in which the Trust has a working interest as at December 31, 2003.
Oil Wells Natural Gas Wells ----------------------------------- ----------------------------------- Producing Non-Producing Producing Non-Producing --------------- --------------- --------------- --------------- Gross Net Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- ----- ----- Alberta 263.0 164.0 130.0 75.5 875.0 700.1 153.0 91.2 British Columbia 11.0 6.5 5.0 2.3 64.0 37.3 15.0 6.2 Saskatchewan 80.0 49.8 41.0 26.1 -- -- -- -- Manitoba 85.0 5.1 -- -- -- -- -- -- ----- ----- ----- ----- ----- ----- ----- ----- Total 439.0 225.4 176.0 103.9 939.0 737.4 168.0 97.4 ===== ===== ===== ===== ===== ===== ===== =====
Note: (1) Excluding minor interest in the following units (less than 5% working interest): Steelman Unit No. 3, Pine Creek Second White Specks Pool, Carrot Creek Cardium K Unit No. 1, Delburne Gas Unit, Nevis Unit No. 1, Bonnie Glen D-3A Gas Cap Unit, Bellis Gas Unit No. 2, Turner Valley Unit No. 5, Sunchild Gas Unit No. 1, North Pembina Cardium Unit, Kakwa Cardium A Unit, Bonanza Boundary A Pool Unit No. 1. and Boundary Lake Units No. 1 and No. 2. Injection Wells are categorized as Non-Producing Oil Wells. Properties with no Attributed Reserves The following table sets out the Trust's developed and undeveloped land holdings as at December 31, 2003.
Developed Acres Undeveloped Acres Total Acres ----------------------- ----------------------- ----------------------- Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Alberta 593,984 276,523 388,132 210,682 982,116 487,205 British Columbia 93,187 18,885 21,409 7,003 114,596 25,888 Saskatchewan 8,929 5,088 90,438 86,817 99,367 91,905 --------- --------- --------- --------- --------- --------- Total 696,100 300,496 499,979 304,502 1,196,079 604,998 ========= ========= ========= ========= ========= =========
The Trust expects that rights to explore, develop and exploit 37,969 net acres of its undeveloped land holdings will expire by December 31, 2004. 23 Forward Contracts In March and April of 2003 Advantage entered into costless collar contracts on approximately 60% of its natural gas production (net of royalties). Advantage does not currently have any oil hedges in place. The specific volumes and terms of such commitments are set forth below:
Type of Commitment Average Fixed Price Volume Term of Commitment ------------------------------- ------------------- ------------- -------------------------- Collar - Natural Gas - AECO 'c' $6.12/mcf 50.4 mmcf/day Apr 1, 2004 - Dec 31, 2004 Collar - Natural Gas - AECO 'c' $6.30/mcf 10.5 mmcf/day Jan 1, 2005 - Mar 31, 2005
Additional Information Concerning Abandonment and Reclamation Costs Advantage estimates the costs to abandon and reclaim all its shut in and producing wells, facilities, gas plants, pipelines, batteries and satellites. No estimate of salvage value is netted against the estimated cost. Advantage's model for estimating the amount and timing of future abandonment and reclamation expenditures was done on an operating area level. Estimated expenditures for each operating area are based upon Sproule's methodology, which details the cost of abandonment and reclamation for the major properties that Advantage holds. Each property was assigned an average cost per well to abandon and reclaim the wells in an area and abandonment and reclamation costs have been estimated over a 50 year period. Advantage estimates that they will incur reclamation and abandonment costs on 1,157.6 net producing and non-producing wells. Costs to abandon and reclaim these wells totals $38.9 million ($10.8 million discounted at 10%) and are included in the estimate of future net revenue. The additional liability associated with pipelines and facilities reclamation costs was estimated to be $60 million ($0.5 million discounted at 10%), and was not deducted in estimating future net revenue. Facility reclamation costs are scheduled to be incurred in the year following the end of the reserve life of its associated reserves under the assumption that decommissioning of plant/facilities are mobile assets with a long useful life. Abandonment and reclamation costs included in the estimate of future net revenue for the next three years are $0.7 million in 2004, $1.3 million in 2005 and $0.9 million in 2006. Capital Expenditures The following tables summarize capital expenditures (including capitalized general and administrative expenses) related to the Trust's activities for the year ended December 31, 2003: Capital Expenditures ($ thousands) 2003 -------------------------------------------------------------------------------- Land and seismic $ 7,502 Drilling, completions and workovers 47,123 Well equipping and facilities 21,094 Other 493 -------------------------------------------------------------------------------- $ 76,212 Acquisition of Best Pacific Resources Ltd. -- Acquisition of Gascan Resources Ltd. -- Acquisition of MarkWest Canada Resources Corp. 97,025 Property acquisitions 1,848 Property dispositions (6,112) -------------------------------------------------------------------------------- Total capital expenditures $ 168,973 -------------------------------------------------------------------------------- 24 Exploration and Development Activities The following table sets forth the gross and net wells in which the Trust participated during the year ended December 31, 2003: Gross Net ----- ----- Medicine Hat 97 97 Viking-Kinsella 26 23.3 Shouldice 20 19.1 Bantry 17 9.9 Vermillion 14 13.5 Other 18 11.0 --- ----- Total 192 173.8 === ===== In 2004, Advantage plans to drill and tie-in 100 net wells in Medicine Hat, 31 net wells in Bantry, 38 net wells in Shouldice, three horizontal wells at Nevis, Alberta, one at Benson, Saskatchewan and approximately 3.5 net wells on non-operated properties. Production Estimates The following table sets out the volume of the Trust's production estimated for the year ended December 31, 2004 reflected in the estimate of future net revenue disclosed in the tables contained under "Disclosure of Reserves Data".
Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids BOE (bbls/d) (bbls/d) (mcf/d) (bbls/d) (boe/d) ---------------- --------- ----------- ------------------- ------- 2004 2,474 0 84,056 791 17,274 ---------------- --------- ----------- ------------------- -------
Production History The following tables summarize certain information in respect of production, prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:
Three Months Three Months Three Months Ended Three Months Ended Ended March 31, Ended June 30, September 30, December 31, ------------------ ------------------ ------------------ ------------------ 2003 2002 2003 2002 2003 2002 2003 2002 ------ ------ ------ ------ ------ ------ ------ ------ Average Daily Production(1) Crude oil and NGLs (bbls/d) 2,946 2,991 2,746 3,081 2,623 2,628 2,714 2,618 Natural gas (mcf/d) 54,497 40,902 51,929 42,196 58,686 48,259 65,280 59,444 Combined (boe/d) 12,029 9,808 11,401 10,114 12,404 10,672 13,594 12,524 Average Net Prices Received(2) Crude oil and NGLs (bbls/d) 44.34 27.83 36.03 31.54 36.04 33.43 35.67 36.05 Natural gas (mcf/d) 6.18 3.02 6.49 3.55 5.96 3.01 5.76 4.87 Royalties(3)(5) Crude oil and NGLs (bbls/d) 7.41 4.13 5.88 5.07 5.94 5.30 6.26 7.05 Natural gas (mcf/d) 1.19 0.52 0.96 0.66 0.88 0.49 1.46 1.07 Combined (boe/d) 7.57 3.65 6.27 4.67 5.59 4.26 5.92 4.90 Operating Expenses(4)(5) Crude oil and NGLs (bbls/d) 7.93 6.67 7.78 9.41 10.27 9.18 7.61 9.48 Natural gas (mcf/d) 0.77 0.74 0.88 0.87 0.81 0.82 0.86 0.71 Combined (boe/d) 5.09 4.20 5.42 4.95 6.27 4.97 5.86 4.64 Netback Received(6) Crude oil and NGLs (bbls/d) 30.72 17.03 23.09 17.06 20.53 18.95 20.86 19.52 Natural gas (mcf/d) 5.69 1.76 4.58 2.02 4.16 1.70 3.04 3.09 Combined (boe/d) 26.21 13.25 26.53 14.80 23.95 12.63 22.98 21.08
25 Notes: (1) Before deduction of royalties. (2) Production prices are net of costs to transport the product to market and net of hedging gains and losses. (3) Royalties are net of ARC. (4) This figure includes all field operating expenses. (5) Advantage does not record royalties and operating expenses on a commodity basis. Information in respect of royalties and operating expenses for crude oil and NGLs ($/bbl) and natural gas ($/mcf) has been determined by allocating royalties and expenses on an area by area basis based upon the relative volume of production of crude oil and NGLs ($/bbl) and natural gas ($/mcf) in those areas. (6) Information in respect of netbacks received for crude oil & NGLs ($/bbl) and natural gas ($/mcf) is calculated using operating expense figures for crude oil and NGLs ($/bbl) and natural gas ($/mcf), which figures have been estimated. See note (5) above. The following table indicates the Trust's exit daily production from its important fields at December 31, 2003: Natural Gas Crude Oil & NGLs Total Properties (mcf/d) (bbls/d) (boe/d) -------------------------------------------------------------------------------- Medicine Hat 18,619 -- 3,103 Bantry 14,686 7 2,455 Shouldice 6,998 57 1,223 Wainwright 5,597 34 967 Stoddart/North Pine 4,122 233 920 Nevis 3,638 302 908 Legacy Units 2,012 522 857 -------------------------------------------------------------------------------- Major Properties 55,672 1155 10,434 Other 23,528 1645 5,566 -------------------------------------------------------------------------------- Total 79,200 2,800 16,000 Definitions and Other Notes 1. Columns may not add due to rounding. 2. The crude oil, natural gas liquids and natural gas reserve estimates presented in the McDaniel Report are based upon the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below. "COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum; "Development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly; (b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly; (c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (d) provide improved recovery systems. 26 "Exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies; (b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records; (c) dry hole contributions and bottom hole contributions; (d) costs of drilling and equipping exploratory wells; and (e) costs of drilling exploratory type stratigraphic test wells. "Gross" means: (a) in relation to the Trust's interest in production and reserves, its "Trust gross reserves", which are the Trust's interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Trust; (b) in relation to wells, the total number of wells in which the Trust has an interest; and (c) in relation to properties, the total area of properties in which the Trust has an interest. "Net" means: (a) in relation to the Trust's interest in production and reserves, the Trust's interest (operating and non-operating) share after deduction of royalties obligations, plus the Trust's royalty interest in production or reserves. (b) in relation to wells, the number of wells obtained by aggregating the Trust's working interest in each of its gross wells; and (c) in relation to the Trust's interest in a property, the total area in which the Trust has an interest multiplied by the working interest owned by the Trust. "NI 51-101" means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities; Reserve Categories Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based upon o analysis of drilling, geological, geophysical and engineering data; o the use of established technology; and o specified economic conditions. Reserves are classified according to the degree of certainty associated with the estimates. 27 (a) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. (b) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook. Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories: (a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. (i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainly. (ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. (b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned. Levels of Certainty for Reported Reserves The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions: (a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and (b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook. REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION Management of Advantage are responsible for the preparation and disclosure of information with respect to the Trust's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and 28 (ii) the related estimated future net revenue; and (iii) proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and (iv) the related estimated future net revenue. Sproule Associates Limited ("Sproule") has evaluated the Trust's reserves data. The report of Sproule is presented below. The independent reserves evaluation committee of the Trust has (b) reviewed the Trust's procedures for providing information to Sproule; (c) met with Sproule to determine whether any restrictions affected Sproule's ability to report without reservation; and (d) reviewed the reserves data with management and the independent qualified reserves evaluator. The independent reserves evaluation committee has reviewed the Trust's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the independent reserves evaluation committee, approved (e) the content and filing with securities regulatory authorities of the reserves data and other oil and gas information; (f) the filing of the report of the independent qualified reserves evaluator on the reserves data; and (g) the content and filing of this report. Because the reserves data are based upon judgments regarding future events, actual results will vary and the variations may be material. (signed) "Kelly I. Drader" (signed) "Peter A. Hanrahan" Kelly I. Drader Peter A. Hanrahan President and Chief Executive Officer Chief Financial Officer (signed) "Ronald A. McIntosh" (signed) "Rodger A. Tourigny" Ronald A. McIntosh Rodger A. Tourigny Director Director May 12, 2004 REPORT ON RESERVES DATA To the board of directors of Advantage Energy Income Fund (the "Trust"): 1. We have evaluated the Trust's reserves data as at December 31, 2003. The reserves data consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and (ii) the related estimated future net revenue; and (b) (i) proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and 29 (ii) the related estimated future net revenue. 2. The reserves data are the responsibility of the Trust's management. Our responsibility is to express an opinion on the reserves data based upon our evaluation. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). 3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook. 4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Trust evaluated by us for the year ended December 31, 2003, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Trust's board of directors:
Net Present Value of Future Net Revenue (before income Independent Qualified Location of Reserves taxes, 10% discount rate (000's)) Reserves Evaluator or Description and Preparation Date of (County or Foreign ----------------------------------------- Auditor Evaluation Report Geographic Area) Audited Evaluated Reviewed Total -------------------------- ----------------------------------- -------------------- ------- --------- -------- -------- Sproule Associates Limited Evaluation of the P&NG Reserves of Canada $75,876 $444,174 Nil $520,050 Advantage Energy Income Fund as of December 31, 2003 prepared December 2003 to April 2004
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate. 6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates. 7. Because the reserves data are based upon judgements regarding future events, actual results will vary and the variations may be material. (signed) "Sproule Associates Limited" Sproule Associates Limited Calgary, Alberta April 19, 2004 ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND Trust Units An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. As at April 30, 2004, 39,502,390 Trust Units were issued and outstanding. Each Trust Unit represents an equal fractional undivided beneficial interest in any distributions from, and in any net assets of, the Trust in the event of termination or winding-up of the Trust. The beneficial interests in the Trust are divided into interests in two classes as follows: (i) described and designated as "Trust Units", which are entitled to the rights, subject to limitations, restrictions and conditions set out in the Trust Indenture, as summarized herein; and (ii) described and designated as "Special Voting Units", which shall be issued to a trustee and shall be entitled to such number of votes at meetings of Trust Unitholders as is equal to the number of Trust Units reserved for issuance that such Special Voting Units represent, such number of votes and any other rights or limitations to be prescribed by the Board of Directors. The Special Voting Units give AOG the flexibility to acquire the securities of another issuer in consideration for securities which are ultimately exchangeable for Trust Units. All Trust Units are of the same class with equal rights and privileges. Each Trust Unit is 30 transferable, entitles the holder thereof to participate equally in distributions, including the distributions of net income and net realized capital gains of the Trust, and distributions upon liquidation, is fully paid and non-assessable and entitles the holder thereof to one vote at all meetings of Trust Unitholders. The Trust Units do not represent a traditional investment and should not be viewed by investors as "shares" in either AOG or the Trust. As holders of Trust Units in the Trust, the Trust Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring "oppression" or "derivative" actions. The price per Trust Unit is a function of anticipated distributable income from AOG and the combined ability of the Board of Directors and the Manager to effect long-term growth in the value of the Trust. The market price of the Trust Units is sensitive to a variety of market conditions including, but not limited to, interest rates, commodity prices and the ability of the Trust to acquire additional assets. Changes in market conditions may adversely affect the trading price of the Trust Units. The Trust Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that act or any other legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company. Trust Unitholder Limited Liability The Trust Indenture provides that no Trust Unitholder will be subject to any liability in connection with the Trust or its obligations and affairs and, in the event that a court determines Trust Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of the Trust Unitholder's share of the Trust's assets. Pursuant to the Trust Indenture, the Trust will indemnify and hold harmless each Trust Unitholder from any cost, damages, liabilities, expenses, charges and losses suffered by a Trust Unitholder resulting from or arising out of such Trust Unitholder not having such limited liability. The Trust Indenture provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon Trust Unitholders personally. Notwithstanding the terms of the Trust Indenture, Trust Unitholders may not be protected from liabilities of the Trust to the same extent as a shareholder is protected from the liabilities of a corporation. Personal liability may also arise in respect of claims against the Trust (to the extent that claims are not satisfied by the Trust Fund) that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability to Trust Unitholders of this nature arising is considered unlikely in view of the fact that the sole business activity of the Trust is to hold securities, and all of the business operations currently carried on by AOG will be carried on by a corporate entity, directly or indirectly. The business of the Trust and its wholly-owned Subsidiary, AOG, is conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability to the Trust Unitholders for claims against the Trust, including obtaining appropriate insurance, where available, for the operations of AOG and having written agreements, signed by or on behalf of the Trust, include a provision that such obligations are not binding upon Trust Unitholders personally. Issuance of Trust Units The Trust Indenture provides that Trust Units or rights to acquire Trust Units may be issued at the times, to the persons, for the consideration, and on the terms and conditions that the Board of Directors determines. The Trust Indenture also provides that immediately after any pro rata distribution of Trust Units to all Trust Unitholders in satisfaction of any non-cash distribution, the number of outstanding Trust Units will be consolidated such that each Trust Unitholder will hold, after the consolidation, the same number of Trust Units as the Trust Unitholder held before the non-cash distribution. In this case, each certificate representing a number of Trust Units prior to the non-cash distribution is deemed to represent the same number of Trust Units after the non-cash distribution and the consolidation. 31 Cash Distributions The amount of cash to be distributed annually per Trust Unit shall be equal to a pro rata share of interest on the 14% Notes, 10?% Notes, royalty income from the Royalty, dividends on or in respect of shares of AOG received by the Trust and income from the Permitted Investments; less: (i) administrative expenses and other obligations of the Trust; and (ii) amounts which may be paid by the Trust in connection with any cash redemptions of Trust Units. AOG may apply some or all of its cash flow to capital expenditures to develop the Oil and Natural Gas Properties of AOG or to acquire additional Oil and Natural Gas Properties prior to making any distributions to the Trust in the form of principal repayments on the Notes or dividends on the Common Shares, Non-Voting Shares or Preferred Shares. If, on any Distribution Record Date, the Trustee determines that the Trust does not have cash in an amount sufficient to pay the full distribution to be made on such Distribution Record Date in cash or if any cash distribution should be contrary to any subordination agreement, the distribution payable to Unitholders on such Distribution Record Date may, at the option of the Trustee, include a distribution of additional Trust Units having an equal value to the cash shortfall. Trust Units will be issued pursuant to exemptions under applicable securities laws, discretionary exemptions granted by applicable securities regulatory authorities or a prospectus or similar filing. The Trust derives interest income from its holdings of the Notes. The 14% Notes bear interest at 14% per annum, payable monthly and will mature on December 31, 2031, subject to extension for an additional 20-year term at the instance of the Board of Directors, with the approval thereof by resolution of the holders of the Notes if the Trust does not then hold substantially all of the 14% Notes. The 10?% Notes bear interest at 10?% per annum, payable on May 1 and November 1 in each calendar year and mature on December 31, 2012. The 9?% Notes bear interest at 9?% per annum while the 8 1/2% Notes bear interest at 8 1/2% per annum and both are payable on February 1 and August 1 in each calendar year and both mature on December 31, 2013. It is expected that the Trust's income will generally be limited to: (i) the interest received on the principal amount of the Notes; (ii) royalty income received on the Royalty; and (iii) dividends (if any) received on shares of AOG. See "Additional Information Respecting Advantage Oil & Gas Ltd. - Notes". The Board of Directors intends for the Trust to make monthly cash distributions. Cash distributions will be made monthly to the Trust Unitholders of record on the last day of each month (unless such day is not a Business Day, in which case the date of record shall be the next following Business Day) and shall be payable on the 15th day of each month or, if such day is not a Business Day, the following Business Day or such other date as determined from time to time by the Trustee. Redemption Right Trust Units are redeemable at any time on demand by the holders thereof upon delivery to the Trust of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requesting redemption. Upon receipt of the redemption request by the Trust, all rights to and under the Trust Units tendered for redemption shall be surrendered and the holder thereof shall be entitled to receive a price per Trust Unit (the "Redemption Price") equal to the lesser of: (i) 85% of the "market price" of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading-day period commencing immediately after the date on which the Trust Units are surrendered for redemption (the "Redemption Date"); and (ii) the "closing market price" on the principal market on which the Trust Units are quoted for trading on the Redemption Date. For the purposes of this calculation, "market price" is an amount equal to the simple average of the closing price of the Trust Units for each of the trading days on which there was a closing price; provided that, if the applicable exchange or market does not provide a closing price but only provides the highest and lowest prices of the Trust Units traded on a particular day, the market price shall be an amount equal to the simple average of the highest and lowest prices for each of the trading days on which there was a trade; and provided further that if there was trading on the applicable exchange or market for fewer than five of the 10 trading days, the market price shall be the simple average of the following prices established for each of the 10 trading days: the average of the last bid and last ask prices for each day on which there was no trading; the closing price of the Trust Units for each day that there was trading if the exchange or market provides a closing price; and the average of the highest and lowest prices of the Trust Units for each day that there was trading, if the market provides only the highest and lowest prices of Trust Units traded on a particular day. The "closing market price" shall be: an amount equal to the closing price of the Trust Units if there was a trade on the date; an amount equal to the average of the highest and lowest prices of the Trust Units if there was trading and the exchange or other market provides only the highest and lowest prices of Trust Units traded on a particular day; and the average of the last bid and last ask prices if there was no trading on the date. 32 The aggregate Redemption Price payable by the Trust in respect of any Trust Units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on or before the last day of the following month; provided that the entitlement of Trust Unitholders to receive cash upon the redemption of their Trust Units is subject to the limitations that: (i) the total amount payable by the Trust in respect of such Trust Units and all other Trust Units tendered for redemption in the same calendar month shall not exceed $100,000 (provided that the Trustee may, in its sole discretion, waive such limitation in respect of any calendar month); (ii) at the time such Trust Units are tendered for redemption the outstanding Trust Units shall be listed for trading on a stock exchange or traded or quoted on any other market which the Trustee considers, in its sole discretion, provides representative fair market value prices for the Trust Units; and (iii) the normal trading of Trust Units is not suspended or halted on any stock exchange on which the Trust Units are listed (or, if not listed on a stock exchange, on any market on which the Trust Units are quoted for trading) on the Redemption Date or for more than five trading days during the 10-day trading period commencing immediately after the Redemption Date. If a Trust Unitholder is not entitled to receive cash upon the redemption of Trust Units as a result of the foregoing limitations, then the Redemption Price for such Trust Units shall be the Fair Market Value thereof (as defined in the Trust Indenture), as determined by the Trustee in the circumstances described in subparagraphs (ii) and (iii) above, and shall, subject to any applicable regulatory approvals, be paid and satisfied by way of distribution in specie of a pro rata number of 14% Notes (in a minimum amount of $100.00 and integral multiples of $1.00), from time to time outstanding (i.e., in a principal amount equal to the Redemption Price). No fractional 14% Notes will be distributed and where the number of 14% Notes to be received by a Trust Unitholder includes a fraction, such number shall be rounded to the next lowest whole number. The Trust shall be entitled to all interest paid, or accrued and unpaid, on the 14% Notes on or before the date of the distribution in specie. If the Trust does not hold 14% Notes having a sufficient principal amount outstanding to effect such payment, the Trust will be entitled to create and, subject to any applicable regulatory approvals, issue in satisfaction of the Redemption Price its own debt securities (the "Redemption Notes") having terms and conditions substantially the same as the 14% Notes, and with recourse of the holder limited to the assets of the Trust. Holders of such 14% Notes and Redemption Notes will be required to acknowledge that they are subject to the subordination agreements described below under the heading "Additional Information Regarding Advantage Oil & Gas Ltd. - Notes". 14% Notes and Redemption Notes may not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds and deferred profit sharing plans if the Trust ceases to qualify as a mutual fund trust. It is anticipated that the redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. 14% Notes or Redemption Notes which may be distributed in specie to Trust Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such 14% Notes or Redemption Notes. Meetings of Trust Unitholders The Trust Indenture provides that meetings of Trust Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of the auditors of the Trust, the approval of amendments to the Trust Indenture (except as described under "Additional Information Respecting Advantage Energy Income Fund - Amendments to the Trust Indenture"), the sale of the assets of the Trust in their entirety or substantially in their entirety (other than as part of an internal reorganization), the termination of the Trust and the direction of the Trustee as to the selection of the directors of AOG. Meetings of Trust Unitholders will be called and held annually for, among other things, the election of the Trustee, the appointment of auditors of the Trust, and the direction of the Trustee as to the selection of the directors of AOG. A resolution appointing or removing a Trustee, the auditors of the Trust, or the direction of the Trustee as to the selection of the directors of AOG must be passed by a simple majority of the votes cast by Trust Unitholders. The balance of the foregoing matters must be passed by at least 66?% of the votes cast at a meeting of Trust Unitholders called for such purpose. A meeting of Trust Unitholders may be convened at any time and for any purpose by the Trustee and must be convened if requisitioned by the holders of not less than 20% of the Trust Units then outstanding by a written requisition. A requisition must, among other things, state in reasonable detail the business proposed to be transacted at the meeting. Trust Unitholders may attend and vote at all meetings of Trust Unitholders either in person or by proxy and a proxyholder need not be a Trust Unitholder. Two persons present in person or represented by proxy and representing, in the aggregate, at least 10% of the votes attaching to all outstanding Trust Units shall constitute a quorum for the transaction of business at all such meetings. The Trust Indenture contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of Trust Unitholders. The next annual and special meeting of Trust Unitholders is scheduled for May 26, 2004. 33 Information and Reports The Trust will furnish to Trust Unitholders such financial statements (including quarterly and annual financial statements) and other reports as are, from time to time, required by applicable law, including prescribed forms needed for the completion of Trust Unitholders' tax returns under the Tax Act and equivalent provincial legislation. Prior to each meeting of Trust Unitholders, the Trustee will provide the Trust Unitholders (along with notice of such meeting) a proxy form and an information circular containing information similar to that required to be provided to shareholders of a Canadian public corporation. The Board of Directors will ensure that AOG provides the Trust with proper disclosure as to its business and financial operations and sufficient information and materials on a timely basis to allow the Trust to meet its public reporting requirements. With respect to material changes, the Board of Directors will ensure that AOG provides timely disclosure to the Trust as if AOG were a public corporation. Takeover Bids The Trust Indenture contains provisions to the effect that if a takeover bid is made for the Trust Units and not less than 90% of the Trust Units (other than Trust Units held at the date of the takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units held by Trust Unitholders who did not accept the takeover bid on the terms offered by the offeror. The Trustee The Trust Indenture provides that the Trustee shall exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in the best interests of the Trust and the Trust Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances. The initial term of the Trustee's appointment is until the first annual meeting of Trust Unitholders. Thereafter, the trustee shall be reappointed or changed every year as may be determined by a majority of the votes cast at a meeting of the Trust Unitholders. The Trustee may resign upon 60 days' notice to the Trust. The Trustee may also be removed by special resolution of the Trust Unitholders. Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee. Delegation of Authority, Administration and Trust Governance The Board of Directors has generally been delegated the significant management decisions of the Trust and the Manager has been retained to administer the Trust on behalf of the Trustee. In particular, the Trustee has delegated to the Board of Directors responsibility for any and all matters relating to: (a) any offering of securities of the Trust, including: (i) ensuring compliance with all applicable laws; (ii) all matters relating to the content of any offering documents, the accuracy of the disclosure contained therein, and the certification thereof; (iii) all matters concerning any subscription agreements or underwriting or agency agreements providing for the sale of Trust Units or securities convertible for or exchangeable into Trust Units or rights to Trust Units; and (iv) all matters concerning the adoption of a unitholder rights plan; (b) all matters concerning the terms of, and amendment from time to time of, material contracts; (c) all matters relating to the redemption of Trust Units; (d) the determination of any Distribution Record Date other than the last day of each calendar month and the payment of cash distributions to Unitholders; (e) the determination of any borrowings under the Trust Indenture; (f) the acquisition of Permitted Investments and Subsequent Investments by the Trust and the negotiation of agreements respecting Subsequent Investments; (g) maintaining the books and records of the Trust and providing timely reports to Unitholders; (h) the financial statements of the Trust and AOG; (i) the continued listing of the Trust Units of the Trust on any exchange and to maintain the Trust's status as a reporting issuer, including press releases and material change reports as required by the continuous disclosure requirements of applicable securities legislation; and (j) the Initial Permitted Securities. Trust Unitholders are entitled to elect a majority of the Board of Directors pursuant to the terms of the Shareholder Agreement. Subject to the ultimate authority of the Board of Directors, AOG and the Trust will be managed by the Manager. For more information as to the Board of Directors, see "Additional Information Respecting Advantage Oil & Gas Ltd. - Management of AOG". 34 Decision-Making Although the Manager will provide certain advisory and management services to the Trust pursuant to the Management Agreement, the Board of Directors will supervise the management of the business and affairs of the Trust, including the business and affairs of the Trust delegated to AOG. In particular, significant operational decisions and all decisions relating to: (i) the acquisition and disposition of properties, assets or securities (individually or in the aggregate with respect to any single type of security) for a purchase price or proceeds in excess of $2,000,000; (ii) the approval of annual operating and capital expenditure budgets; and (iii) establishment of credit facilities, will be made by the Board of Directors. In addition, the Trustee has delegated certain matters to the Board of Directors, including making all decisions relating to: (i) issuance of additional Trust Units; and (ii) the determination of the amount of Distributable Income. Any amendment to any material contract to which the Trust is a party will require the approval of the Board of Directors on behalf of the Trust. The Board of Directors generally intends to hold regularly scheduled meetings to review the business and affairs of the Trust and AOG and to make any necessary decisions relating thereto. Liability of the Trustee The Trustee, its directors, officers, employees, shareholders and agents shall not be liable to any Trust Unitholder or any other person, in tort, contract or otherwise, in connection with any matter pertaining to the Trust or the Trust Fund, arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, any action taken or not taken in good faith in reliance upon any documents that are, prima facie, properly executed, any depreciation of, or loss to, the Trust Fund incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by the Manager or any other appropriately qualified person, any reliance upon any such evaluation, any action or failure to act of the Manager, AOG, or any other person to whom the Trustee has, with the consent of AOG, delegated any of its duties hereunder, or any other action or failure to act (including failure to compel in any way any former trustee to redress any breach of trust or any failure by the Manager or AOG to perform its duties under or delegated to it under the Trust Indenture or any material contract), unless such liabilities arise out of the gross negligence, wilful default or fraud of the Trustee or any of its directors, officers, employees, shareholders or agents. If the Trustee has retained an appropriate expert, adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture or any material contract, the Trustee may act or refuse to act based upon the advice of such expert, adviser or legal counsel, and the Trustee shall not be liable for and shall be fully protected from any loss or liability occasioned by any action or refusal to act based upon the advice of any such expert, adviser or legal counsel. In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the Trust and shall not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to the Trust or the Trust Fund. In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee. Amendments to the Trust Indenture The Trust Indenture may be amended or altered, from time to time, by at least 66?% of the votes cast at a meeting of the Trust Unitholders called for such purpose. The Trustee may, without the approval of the Trust Unitholders, make certain amendments to the Trust Indenture, including amendments: 1. for the purpose of ensuring continuing compliance with applicable laws (including the Tax Act), regulations, requirements or policies of any governmental or other authority having jurisdiction over the Trustee or over the Trust; 2. ensuring that the Trust will satisfy the provisions of each of Sections 108(2)(a) and 132(6) of the Tax Act, as from time to time amended or replaced; 3. which, in the opinion of the Trustee, provide additional protection for or benefit to the Trust Unitholders; 4. to remove any conflicts or inconsistencies in the Trust Indenture or making corrections, including the correction or rectification of any ambiguities, defective provisions, errors, mistakes or omissions, which are, in the opinion of the Trustee, necessary or desirable and not prejudicial to the Trust Unitholders; 35 5. which, in the opinion of the Trustee, are necessary or desirable as a result of changes in taxation laws; and 6. removing or curing inconsistencies between the Trust Indenture and the Material Contracts (as such term is defined in the Trust Indenture) which are, in the opinion of the Trustee, necessary or desirable and not prejudicial to the Unitholders. Unitholders will be asked to approve, by way of special resolution, certain proposed changes to the Trust Indenture at the annual and special meeting of Unitholders scheduled for May 26, 2004. The specific details of such amendments are set forth in the Trust's Information Circular - Proxy Statement dated April 16, 2004. Private Placements At the upcoming annual and special meeting of Unitholders, Unitholders will be asked to authorize the sale by the Trust in one or more private placements of up to 15,000,000 Trust Units on such terms as may be determined by the Board of Directors and by the Trust. It is anticipated that the Trust may undertake private placements to complete acquisitions or raise equity capital in order to fund capital expenditures or acquisitions that may enhance the Trust's business prospects. The Trust will regularly evaluate opportunities which will assist in enhancing Trust Unitholder value, and the private placement of Trust Units or instruments convertible into Trust Units will be routinely considered as a financing alternative, particularly as a private placement can typically be structured to reduce the market risk associated with traditional long form public financings. The Trust obtained such approval last year in order to retain the flexibility to issue up to 18,000,000 Trust Units by private placement in 2004. The Trust is not currently considering the specific terms of any private placement pursuant to which it may issue Trust Units. Any private placement must be undertaken in accordance with applicable corporate law, securities legislation and stock exchange by-laws, regulations and policies. Among other things, such regulations limit the discount to the market price at which the Trust Units may be sold pursuant to a private placement. Some or all of the Trust Units offered by private placement may be purchased by insiders of the Trust or AOG. The issuance of greater than 25% of the Trust's issued and outstanding Trust Units to a new or existing Unitholder or group of Unitholders may result in a change of control of the Trust or enhance an existing control position. To the extent that Trust Units are purchased by insiders, persons having a significant or controlling interest in the Trust may enhance their ownership position with respect to existing Unitholders who do not participate in the private placement. Where insiders of the Trust or AOG participate in any such private placement, the TSX may require evidence of the approval of the majority of Unitholders, excluding the participating insiders, to the private placement. Funds received from any private placement will be added to the Trust's working capital to be used for financing programs, projects, acquisitions, debt reduction or for general corporate purposes. Term of the Trust and Sale of Substantially All Assets The Trust has been established for a term ending December 31, 2095. Pursuant to the Trust Indenture, termination of the Trust or the sale or transfer of the assets of the Trust in their entirety or substantially in their entirety, except as part of an internal reorganization of the assets of the Trust as approved by the Board of Directors, requires approval by at least 66?% of the votes cast at a meeting of the Trust Unitholders. Exercise of Voting Rights Attached to Common Shares The Trust Indenture provides that the Trustee may vote securities of AOG held by it at any meeting of shareholders of AOG as well as any Permitted Investments held, from time to time, as part of the Trust Fund which carry voting rights. However, the Trustee may not, under any circumstances whatsoever, vote any AOG securities or any other Permitted Investments which carry voting rights to authorize the sale, lease or exchange of all or substantially all of the property of AOG or any other entity owned directly or indirectly by the Trust which represents more than 51% of the Trust Fund, except as part of a reorganization of AOG and any one or more directly or indirectly owned subsidiaries of the Trust without the approval of at least 66?% of the votes cast at a meeting of the Trust Unitholders called for such purpose. 36 ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD. Management of AOG Pursuant to the Shareholder Agreement, the Board of Directors is comprised of not more than nine nor less than five members. The Board of Directors is currently comprised of the seven members indicated below. Pursuant to the Management Agreement, the Manager will, at all times, have the right to designate two directors to the Board of Directors. The directors of AOG that were appointed by the Manager are Kelly Drader and Gary Bourgeois. Unitholders will always be entitled to select the majority of the Board of Directors. In addition, a majority of the Board of Directors must not be officers, employees or consultants of AOG, the Manager, or any of their respective affiliates, and the Chairman of the Board of Directors must be a director of the Board elected by the Unitholders. The following table sets forth certain information respecting AOG's directors and executive officers.
Name and Position Held and Period Served as Municipality of Residence a Director(6)(7) Principal Occupations During Past Five Years ------------------------- ---------------------------------- -------------------------------------------------------------- Gary F. Bourgeois Vice President, Corporate Vice President, Corporate Development of AOG since May 24, Toronto, Ontario Development and Director since 2001. Vice President of the Manager since March 2001. Prior May 24, 2001 thereto, Managing Director of the EnerPlus Group of Companies, which companies specialize in management of oil and gas income funds and royalty trusts (1998-2000). In addition, President of Queen-Yonge Investments Limited (since 1985), a private family-owned investment holding company with holdings in oil and gas royalty trusts, real estate income funds, direct oil and gas properties, private and public exploration and production companies, and direct commercial real estate holdings. Kelly I. Drader(2) President, Chief Executive Officer President and Chief Executive Officer of AOG since May 24, Calgary, Alberta and Director since May 24, 2001 2001. President of the Manager since March 2001. Prior thereto, Senior Vice President (1997-2001) and Vice President, Finance and Chief Financial Officer (1990-1997) of EnerPlus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts. Ronald A. McIntosh(3) Director since September 25, 1998 Chairman of Navigo Energy Inc. since December 2003. As of Calgary, Alberta December 29, 2003, Navigo Energy Inc. became a wholly-owned subsidiary of NAV Energy Trust and acts as administrator of NAV Energy Trust. President and Chief Executive Officer of Navigo Energy Inc. from October 2001 to December 2003. Prior to December, Chief Operating Officer of Gulf Canada Resources Ltd. since December, 2000. Prior thereto, Mr. McIntosh was Vice President, Exploration and International of Petro-Canada since May 1996. Roderick M. Myers(2)(3) Director since December 31, 1996 Since May 24, 2001, a self-employed businessman. Prior Calgary, Alberta thereto, Vice President, Business Development of Search Energy Corp.
37
Name and Position Held and Period Served as Municipality of Residence a Director(6)(7) Principal Occupations During Past Five Years ------------------------- ---------------------------------- -------------------------------------------------------------- Steven Sharpe(1)(2) Director since May 24, 2001 Managing Partner of Blair Franklin Capital Partners Inc., an Toronto, Ontario investment banking firm since May, 2003. Prior thereto, Mr. Sharpe was the Managing Director of The EBS Corporation, a management and strategic consulting firm, since June 2001. From July 1998 to June 2001, Executive Vice President or Vice President, Strategic Development of The Kroll-O'Gara Company, a NASDAQ listed professional consulting, manufacturing, Internet and electronic commerce security company. Prior thereto, Mr. Sharpe was a partner with Davies, Ward & Beck, a Toronto-based law firm. Rodger A. Tourigny(1)(3)(5) Director since December 31, 1996 President of Tourigny Management Ltd., a private oil and gas Calgary, Alberta consulting company. Lamont Tolley(1) Non-Executive Chairman and Independent businessman who has been active in the oil and gas Calgary, Alberta Director since May 24, 2001 industry for 20 years. Currently the President of Genex Energy Inc., a private oil and gas company. Prior to June 1999, he was a principal and operating manager of Starvest Capital Inc., a private company which managed both private institutional oil investments and two public royalty trusts: Starcor Energy Royalty Fund and Orion Energy Trust. Patrick J. Cairns Senior Vice President Senior Vice President of AOG since June 2001. Vice President Calgary, Alberta of the Manager since May 2001. Prior thereto, Mr. Cairns was Vice President, Evaluations with the Enerplus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts. Peter Hanrahan Chief Financial Officer and Chief Financial Officer of AOG since January 2003. Prior Calgary, Alberta Controller thereto, Controller of AOG since December 1999. Prior thereto, Manager of Financial Reporting with Numac Energy Inc. Toshiyuki Takahashi Vice President, Exploitation Vice President, Exploitation of AOG since August 2001. Vice Calgary, Alberta President of the Manager since May 2001. Prior thereto, Mr. Takahashi was Manager of Acquisitions with the Enerplus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts. Richard Mazurkewich Vice President, Operations Vice President, Operations of AOG since August 2001. Prior Calgary, Alberta thereto, Manager, Production and Facilities of AOG since March 1998. Prior thereto, Production Engineer with Canadian Natural Resources Limited. Jay P. Reid Corporate Secretary Partner, Burnet, Duckworth & Palmer LLP, a Calgary-based law Calgary, Alberta firm.
38 Notes: (1) Member of the Audit Committee. (2) Member of the Human Resources, Compensation and Corporate Governance Committee. (3) Member of the Independent Reserve Evaluation Committee. (4) The Corporation does not have an executive committee of the Board. (5) Mr. Tourigny was a director of Shenandoah Resources Ltd. ("Shenandoah") prior to it being placed into receivership on September 17, 2002 and prior to the issuance of cease trade orders in respect of Shenandoah's securities by the Alberta Securities Commission and the British Columbia Securities Commission on November 8, 2002 and October 23, 2002, respectively. Cease trade orders were issued because Shenandoah failed to file certain required financial statements. As of the date hereof, the cease trade orders remain outstanding. Shenandoah's common shares were suspended from trading on the TSX Venture Exchange on April 24, 2002. Mr. Tourigny resigned his directorship with Shenandoah effective September 17, 2002. Mr. Tourigny was also a director of Probe Exploration Inc. ("Probe") prior to its receivership and prior to the issuance of cease trade orders in respect of Probe's securities by the Alberta Securities Commission and the Ontario Securities Commission on July 7, 2000 and July 17, 2000, respectively. The cease trade orders were issued because Probe failed to file certain required financial statements. As at the date hereof, the cease trade orders remain outstanding. Probe's common shares were suspended from trading on the TSX on March 17, 2000, and were subsequently delisted from the TSX at the close of business on March 16, 2001. Mr. Tourigny resigned his directorship with Probe effective April 14, 2000. (6) The Corporation's directors shall hold office until the next annual general meeting of the Corporation's shareholders or until each director's successor is appointed or elected pursuant to the ABCA, the Shareholder Agreement and the Management Agreement. (7) The period of time served as a director of AOG includes the period of time served as a director of Search prior to the Amalgamation, where applicable. Each of the directors were appointed directors of post-Reorganization Search on May 24, 2001. As at March 31, 2004, the directors and executive officers of AOG, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 2,484,721 Trust Units, or approximately 6.5% of the issued and outstanding Trust Units. Distribution Policy It is anticipated that income to be received by the Trust will be from: (i) the interest received on the principal amount of the Notes; (ii) royalty income from the Royalty; and (iii) the dividends received from the shares of AOG. The Trustee makes monthly cash distributions to Trust Unitholders of the interest income earned from the Notes, royalty income from the Royalty and dividends, if any, received on Common Shares, after expenses, if any, and any cash redemptions of Trust Units. See "Risk Factors - Oil and Natural Gas Prices/Delay in Cash Distributions/Dependence on AOG". Share Capital AOG is authorized to issue an unlimited number of Common Shares, Non-Voting Shares and Preferred Shares. The Trust is the sole holder of the issued and outstanding Common Shares. There are no Non-Voting Shares or Preferred Shares issued and outstanding. The Trust is also the sole holder of the outstanding Notes. The following is a description of the rights attaching to the Common Shares, Non-Voting Shares, Preferred Shares and notes. Common Shares Each Common Share entitles its holder to receive notice of and to attend all meetings of the shareholders of AOG and to one vote at such meetings. The holders of Common Shares are, at the discretion of the Board of Directors and subject to applicable legal restrictions, entitled to receive any dividends declared by the Board of Directors on the Common Shares. The holders of Common Shares are entitled to share equally in any distribution of the assets of AOG upon the liquidation, dissolution, bankruptcy or winding-up of AOG or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to any instruments having priority over the Common Shares. Non-Voting Shares The Non-Voting Shares have identical rights to the Common Shares except that holders of Non-Voting Shares are not generally entitled to receive notice of or attend at meetings of shareholders of AOG or to vote their shares at such meetings. 39 Preferred Shares The Preferred Shares may be issued, from time to time, in one or more series, each series consisting of such number of Preferred Shares as determined by the Board of Directors, who may also fix the designations, rights, privileges, restrictions and conditions attached to the shares of each series of Preferred Shares. No Preferred Shares are presently issued and outstanding. The Preferred Shares of each series shall, with respect to payment of dividends and distributions of assets in the event of liquidation, dissolution or winding-up of AOG, whether voluntary or involuntary, or any other distribution of the assets of AOG among its shareholders for the purpose of winding-up its affairs, rank on a parity with the Preferred Shares of every other series and shall be entitled to preference over the Common Shares and the shares of any other class ranking junior to the Preferred Shares. 14% Notes The following is a summary of the material attributes and characteristics of the 14% Notes. This summary does not purport to be complete and is qualified in its entirety by reference to the provisions of 14% Note Indenture, pursuant to which the 14% Notes are issued. The aggregate principal amount of the 14% Notes as at December 31, 2003 was $314,239,188 and the 14% Notes mature on December 31, 2031, subject to an extension for an additional 20-year term. The 14% Notes bear interest at the rate of 14% per annum, payable monthly on the 15th day of the month (or, if such day is not a Business Day, the first Business Day thereafter) for interest earned during the preceding month. The principal and interest on the 14% Notes are payable in lawful money of Canada. The 14% Notes are issuable only as fully-registered notes in minimum denominations of $100.00 and integral multiples of $1.00. Payment upon Maturity On maturity and subject to any applicable subordination restrictions, AOG will repay the indebtedness represented by the 14% Notes by paying to the Note Trustee, in lawful money of Canada, an amount equal to the principal amount of the outstanding 14% Notes, together with accrued and unpaid interest thereon. Redemption The 14% Notes will not be redeemable at the option of AOG or by the holders thereof prior to maturity except in the limited circumstances prescribed by 14% Note Indenture, where the Board of Directors believe the indebtedness represented by the 14% Notes could not be refinanced on maturity, or where AOG is prevented by applicable law from paying dividends or making other distributions in respect of Common Shares. Ranking Payment of the principal and interest (other than regularly scheduled interest and principal at maturity, provided no default on Senior Indebtedness (as hereinafter defined) has occurred and payment of such interest or principal is not otherwise required to be suspended in accordance with the terms of subordination agreements which may be entered into with the holders of Senior Indebtedness (as herein defined)) on the 14% Notes will be subordinated in right of payment, as set forth in 14% Note Indenture, to the prior payment in full of the principal of and accrued and unpaid interest on, and all other amounts owing in respect of, all senior indebtedness ("Senior Indebtedness") which is defined as: (a) all indebtedness, obligations and liabilities of AOG in respect of borrowed money (including the deferred purchase price of property), other than: (i) indebtedness evidenced by the 14% Note Indenture; and (ii) indebtedness which, by the terms of the instrument creating or evidencing the same, is expressed to rank in right of payment equally with or subordinate to the indebtedness evidenced by the 14% Note Indenture; and (b) from and after the commencement of, and during the continuance of, any creditor proceedings (including bankruptcy, liquidation, winding-up, dissolution, restructuring or arrangement proceedings), all indebtedness, obligations and liabilities of AOG, other than indebtedness, obligations and liabilities of AOG represented by the 14% Notes. The 14% Note Indenture provides that in the event of any creditor proceedings relative to AOG, the holders of all Senior Indebtedness, which would include bank debt and suppliers of AOG, will be entitled to receive payment in full before the holders of the 14% Notes are entitled to receive any payment. Any amount of property received contrary to these provisions shall be held in trust for and paid over to the holders of Senior Indebtedness. 40 In the event of any creditor proceedings, the indebtedness represented by the 14% Notes is not to be classified with any Senior Indebtedness for voting or distribution, which means that holders of Senior Indebtedness may vote separately from the holders of 14% Notes in respect of any restructuring or arrangement proposal regarding AOG. Default The 14% Note Indenture provides that any of the following shall constitute an "Event of Default": (i) default in payment of the principal of the 14% Notes when the same becomes due; (ii) the failure to pay the interest obligations of the 14% Notes for a period of 12 months; (iii) default on any indebtedness exceeding $5,000,000; (iv) certain events of winding-up, liquidation, bankruptcy, insolvency or receivership; (v) the taking of possession by an encumbrancer of all or substantially all of the property of AOG; or (vi) default in the observance or performance of any other covenant or condition of 14% Note Indenture and the continuance of such default for a period of 30 days after notice in writing has been given by the Note Trustee to AOG specifying such default and requiring AOG to rectify the same. Subordination Agreements Pursuant to the terms of 14% Note Indenture, the Note Trustee may enter into subordination agreements with the holders of certain Senior Indebtedness under which the Note Trustee, on behalf of the holders of 14% Notes, may agree directly with a holder of Senior Indebtedness in implementation of and/or in addition to the subordination terms described under "Ranking" directly above. The Note Trustee may give a holder of Senior Indebtedness a power of attorney to be exercised in any creditor proceedings to enforce the terms thereof. The Note Trustee may also agree to ensure that any transferee of 14% Notes (or other securities of AOG) agrees to be bound by the provisions of the subordination agreements. 10 3/8% Notes The following is a summary of the material attributes and characteristics of the 10 3/8% Notes. This summary does not purport to be complete and is qualified in its entirety by reference to the provisions of 10 3/8% Note Indenture, pursuant to which the 10 3/8% Notes are issued. The aggregate principal amount of the 10 3/8% Notes as at December 31, 2003 was $25,798,756 and the 10 3/8% Notes mature on December 31, 2012. The 10 3/8% Notes bear interest at the rate of 10 3/8% per annum, payable on May 1 and November 1 in each year (or if such day is not a Business Day, the first Business Day thereafter) for interest earned during the preceding six-month period. The principal and interest on the 10 3/8% Notes are payable in lawful money of Canada. The 10 3/8% Notes are issuable only as fully-registered notes in minimum denominations of $100.00 and integral multiples of $1.00. Principal Repayments From time to time, and in any event, not less frequently than each anniversary of December 31, 2002, AOG must make principal repayments on the 10 3/8% Notes in an amount equal to not less than 5% of the original principal amount (being $52,800,000 - the "Original Principal Amount") provided, however, that during the period commencing from the date of issue to December 31, 2007 AOG shall make, in aggregate, principal repayments on the 10 3/8% Notes of an amount equal to not less than 50% of the Original Principal Amount. Ranking Payment of the principal and interest (other than regularly-scheduled interest and principal payments, provided no default on Senior Indebtedness has occurred and payment of such interest or principal is not otherwise required to be suspended, in accordance with the terms of subordination agreements which may be entered into with the holders of Senior Indebtedness) on the 10 3/8% Notes will be subordinated in right of payment, as set forth in 10 3/8% Note Indenture to the prior payment in full of the principal of and accrued and unpaid interest on all Senior Indebtedness. 41 Default 10 3/8% Note Indenture provides that following an event of default the defaulting party shall have 30 days from receipt of notice of the default to rectify same. Subordination Agreements Pursuant to the terms of 10 3/8% Note Indenture, the Note Trustee may enter into subordination agreements with the holders of certain Senior Indebtedness under which the Note Trustee, on behalf of the holders of the 10 3/8% Notes, may agree directly with a holder of Senior Indebtedness in the implementation of and/or in addition to the subordination terms described under "Ranking" directly above. 9 3/8% Notes and 8 1/2% Notes The following is a summary of the material attributes and characteristics of the 9 3/8% Notes and the 8 1/2% Notes (together the "2003 Notes"). This summary does not purport to be complete and is qualified in its entirety by reference to the provisions of 9 3/8% Note Indenture, and 8 1/2% Note Indenture pursuant to which the 9 3/8% Notes and the 8 1/2% Notes are issued, respectively. The aggregate principal amount of the 9 3/8% Notes as at December 31, 2003 was $16,513,000 while the aggregate principal amount of the 8 1/2% Notes as at December 31, 2003 was $45,313,000 . The 9 3/8% Notes bear interest at a rate of 9 3/8% per annum and the 8 1/2% Notes bear interest at a rate of 8 1/2% per annum, both are payable on February 1 and August 1 in each year (or if such day is not a Business Day, the first Business Day thereafter) for interest earned during the preceding 6 month period. The principal and interest on the 2003 Notes is payable in lawful money of Canada. The 2003 Notes mature on December 31, 2013. The 2003 Notes are issuable only as fully registered notes in minimum denominations of $100 and into multiples of $1.00. Principal Repayments From time to time, and in any event not less frequently than each anniversary of December 31, 2003, AOG must make principal repayments on the 2003 Notes in an amount equal to not less than 5% of the original principal amount (being $28,800,000 in connection with the 9 3/8% Notes and the $57,600,000 in connection with the 8 1/2% Notes - the "Original Principal Amounts") provided, however, that during the period commencing from the date of issue to December 31, 2008 AOG shall make, in aggregate, all principal repayments on the 2003 Notes of an amount equal to not less than 50% of the Original Principal Amounts. Ranking Payment of the principal and interest (other than regularly scheduled interest and principal payments, provided no default on Senior Indebtedness has occurred and payment of such interest or principal is not otherwise required to be suspended, in accordance with the terms of subordination agreements which may be entered into with the holders of Senior Indebtedness (on the 2003 Notes) will be subordinated in right of payment, as set forth in the 9 3/8% Note Indenture and 8 1/2% Note Indenture, respectively, to the prior payment in full of the principal of the accrued and unpaid interest on all Senior Indebtedness. Default 9 3/8% Note Indenture and 8 1/2% Note Indenture, each provide that following an event of default the defaulting party shall have 30 days from receipt of notice of the default to rectify same. Subordination Agreements Pursuant to the terms of 9 3/8% Note Indenture and 8 1/2% Note Indenture, the Note Trustee may enter into subordination agreements with the holders of certain Senior Indebtedness under which the Note Trustee, on behalf of the holders of the 2003 Notes, may agree directly with a holder of Senior Indebtedness in the implementation of and/or in addition to the subordination terms described under "Ranking" directly above. 42 The Royalty Agreement Pursuant to the Royalty Agreement, AOG has granted to the Trust the Royalty on AOG's interest in petroleum substances within, upon or under all of AOG's developed and undeveloped Canadian Oil and Natural Gas Properties The Royalty will consist of the right to receive a monthly payment from AOG equal to the "Royalty Production Income", which in respect of any period for which Royalty is calculated, means 95% of the production revenues from the Properties less an equivalent portion of the amount of all deductions permitted under the Royalty Agreement. The Royalty does not constitute an interest in land and the Trust is not entitled to take its share of production in kind or to separately sell or market its share of petroleum substances. Pursuant to the Royalty Agreement approximately 95% of the economic benefit derived from the assets of AOG accrues to the benefit of the Fund and ultimately to the Trust and its Unitholders. The term of the Royalty Agreement will be for so long as there are Properties to which the Royalty Agreement applies. If AOG wishes to dispose of any properties that will result in proceeds in excess of $5 million, AOG's board of directors is required to approve such disposition. Shareholder Agreement Pursuant to the Shareholder Agreement, prior to the Trust voting its shares in AOG, each Trust Unitholder shall be entitled to vote in respect of the matter on the basis of one vote per Trust Unit held and the Trust shall be required to vote its shares in AOG in accordance with the result of the vote of Trust Unitholders. Holders of Trust Units shall be entitled to direct the Trust as to how to vote in respect of all matters placed before the shareholder of AOG, including, subject to the right of the Manager to designate two directors, the election of the directors of AOG, approving its financial statements, and appointing auditors of AOG, who shall be the same as the auditors of the Trust. In addition, Trust Unitholders will be entitled to direct the Trust as to how to vote its shares in AOG on any proposed amendment to the Shareholder Agreement, where such amendment affects the rights of Unitholders to elect a majority of the Board of Directors. The Trust will not be entitled, without the direction of Trust Unitholders, to exercise its rights as the sole shareholder of AOG except as set forth above. It is a term of the Shareholder Agreement that the Board of Directors shall consist of a minimum of five and a maximum of nine directors, with the present number of directors set at seven. The Shareholder Agreement provides that Trust Unitholders are entitled to select a majority of the Board of Directors. Under the terms of the Shareholder Agreement, the Manager has the right to designate two directors to be elected to the Board of Directors. ADDITIONAL INFORMATION RESPECTING ADVANTAGE INVESTMENT MANAGEMENT LTD. Pursuant to the Management Agreement, the Manager has agreed to act as manager of the Trust and AOG. The Board of Directors has retained the Manager to provide comprehensive management services and has delegated certain authority to the Manager to assist in the administration and regulation of the day-to-day operations of the Trust and AOG and to assist in making executive decisions which conform to the general policies and general principles previously established by the Board of Directors. The Manager will provide executive officers to AOG, subject to the approval of the Board of Directors. 43 Management of the Manager The following table outlines the names and municipalities of residence and principal occupations of the officers of the Manager who will be responsible for the provision of such executive services.
Name and Municipality of Residence Office Principal Occupation During the Past Five Years ---------------- -------------- -------------------------------------------------------------------------------- Kelly Drader President President and Chief Executive Officer of AOG since May 2001. President of the Calgary, Alberta Manager since March 2001. Prior thereto, Senior Vice President (1997-2001) and Vice President, Finance and Chief Financial Officer (1990-1997) of EnerPlus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts. Gary Bourgeois Vice President Vice President, Corporate Development of AOG since May 2001. Vice President of Toronto, Ontario the Manager since March 2001. Prior thereto, Managing Director of the EnerPlus Group of Companies, which companies specialize in management of oil and gas income funds and royalty trusts (1998-2000). In addition, President of Queen-Yonge Investments Limited (since 1985), a private family-owned investment holding company with holdings in oil and gas royalty trusts, real estate income funds, direct oil and gas properties, private and public exploration and production companies, and direct commercial real estate holdings. Patrick J. Cairns Vice President Senior Vice President of AOG since June 2001. Vice President of the Manager Calgary, Alberta since May 2001. Prior thereto, Mr. Cairns was Vice President, Evaluations with the Enerplus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts. Toshiyuki Takahashi Vice President Vice President, Exploitation of AOG since August 2001. Vice President of the Calgary, Alberta Manager since May 2001. Prior thereto, Mr. Takahashi was Manager of Acquisitions with the Enerplus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts.
Management Agreement The Management Agreement provides that during the term of the Management Agreement, and any renewal thereof, the Manager shall provide recommendations, assistance and advisory services as requested or required by AOG and the Trust, respecting the following: 1. to AOG: (a) keep and maintain at its offices, at all times, books, records and accounts which shall contain particulars of operations, receipts, disbursements and investments relating to the Properties and AOG; (b) make available, in performing its obligations under the Management Agreement, office space, equipment and qualified personnel, including all engineering, geological, geophysical, accounting, clerical, secretarial, corporate and administrative services as may be necessary to perform its obligations; (c) arrange or provide for the payment of all costs and expenses incurred by or on behalf of AOG in connection with the Properties upon receipt of monies from AOG; (d) provide or arrange for the administration of all of the records and documents for the Properties including establishing and maintaining documents, correspondence files, land files and records; 44 (e) provide or arrange to provide such audit, legal, geological, engineering, geophysical, financial, insurance and other professional services or advice and analysis as the officers or directors of AOG may require or desire to permit any of them to make informed decisions in connection with the discharge by them of their responsibilities as officers or directors, to the extent such advice and analysis can be reasonably provided or arranged by the Manager; (f) at least annually, and at other times as requested by the Board of Directors, prepare all production, capital and expense budgets and business plans in connection with the Properties and also provide quarterly progress reports to the Board of Directors; (g) provide or cause to be provided to AOG any services or analysis reasonably necessary for AOG to be able to consider or participate in any acquisition, development or disposition by AOG of an interest in the Properties or other interests in assets; (h) provide or arrange for such additional administrative services as AOG may reasonably request in connection with the Properties, including services relating to the administration of credit facilities obtained by AOG; (i) review opportunities to acquire additional Properties which, acting reasonably, it believes AOG might reasonably be interested in acquiring and, from time to time, to present AOG with opportunities to acquire Properties consistent with the investment criteria of AOG; (j) conduct negotiations for the acquisition of Properties, provide lease and land services related to such acquisitions (including examination and evaluation of any title documents) and arrange for examination and preparation of legal documents or such other services required in connection with such acquisitions, provided that the Manager shall be deemed not to make any warranty of title with respect to any Properties acquired by AOG; (k) provide or arrange for all necessary exploitation, development and other services in respect of acting as operator of any of the Properties; (l) review all data, information, notices and requests tendered by any third party operator, advise AOG as to the appropriate action to be taken and provide or arrange for any required expertise on behalf of AOG to facilitate the proper conduct of operations in respect thereof; (m) arrange for and negotiate, on behalf of and in the name of AOG, all contracts with third parties for the proper management and operations of the Properties; (n) supervise the disposition and marketing of petroleum substances from the Properties, invoice third parties as required and effect the collection of receivables relating thereto; (o) ensure that AOG complies with all material regulations, statutes and reporting requirements in connection with the Properties; (p) carry out the functions and obligations of AOG contained in the Royalty Agreement with respect to operation of the Properties; and (q) negotiate all borrowings required by AOG to purchase Properties or to fund capital expenditures; 2. to the Trust: (a) ensure compliance by the Trust with its legal obligations, including its continuous disclosure obligations under all applicable securities legislation; (b) provide investor relations services; 45 (c) provide the holders of Trust Units with financial reports and tax information relating to the Properties, the Notes, the Royalty and the Trust; (d) call, hold and distribute materials including notices of meetings and information circulars in respect of all necessary meetings of Unitholders; (e) recommend the amounts payable, from time to time, to Unitholders and to arrange for distributions to Unitholders of distributable income; (f) recommend the timing and terms of future offerings of Trust Units or securities convertible or exchangeable into Trust Units or other public or private securities, if any; and (g) recommend investments in Permitted Investments. The Manager is paid fees for providing all of the services in items 1 and 2 above. See "Additional Information Respecting Advantage Investment Management Ltd. - Compensation and Term". Notwithstanding the delegations provided in items 1 and 2 above, the Board of Directors will supervise the management of the business and affairs of AOG, including the business and affairs of the Trust delegated to AOG, and, in particular: 3. significant operational decisions in respect of AOG as identified by the Manager, acting reasonably; and 4. decisions relating to: (a) any offerings, including the issuance of additional Trust Units or securities convertible into or exchangeable for Trust Units; (b) the acquisition and disposition of properties, assets, securities (individually or in the aggregate with respect to any single type of security) for a purchase price or proceeds in excess of $2,000,000; (c) the approval of operating and capital expenditure budgets; (d) the establishment of credit facilities; (e) all matters to do with the continued listing of the Trust Units on any exchange and to maintain the Trust's status as a reporting issuer, including press releases and material change reports as required by continuous disclosure requirements of applicable securities legislation; (f) the determination of the amount of Distributable Income; and (g) the approval of any amendment to the Management Agreement, the Royalty Agreement, the Note Indentures or the Shareholder Agreement on behalf of the Trust, and those matters as set forth in the Trust Indenture, that may be amended without the approval of Unitholders; shall be subject to the approval of the Board of Directors. The Manager and the Trust are responsible for ensuring compliance with the continuous disclosure obligations under all applicable securities legislation. The Manager has been indemnified by AOG and the Trust in respect of damages suffered relating to the performance of services under the Management Agreement provided that the Manager is in compliance with the standard of care described below, and any of its directors, officers or employees have been indemnified by AOG and the Trust provided that such person shall not be found to be liable for or guilty of wilful misfeasance, bad faith, gross negligence or reckless disregard of his or her duty to AOG or the Trust. In exercising its powers and discharging its duties under the Management Agreement, the Manager is required to exercise that degree of care, diligence and skill that a reasonably-prudent operator and manager in respect of oil and gas properties in western 46 Canada and a manager of a publicly-traded reporting issuer, having responsibility for the subject management, advisory and administrative services, would exercise in comparable circumstances. Acquisition and Disposition Strategy The strategy employed by the Manager is to maintain the level of production of oil and natural gas from AOG's existing properties and to supplement production by reserve acquisitions. To maintain production, capital expenditures are focused on development activity as opposed to exploration. Exploration properties are generally sold, farmed out or developed using third party resources. Reserve replacement and additions are achieved through development activity and acquisitions. In addition, as part of the services to be provided by the Manager to AOG and the Trust, the Manager may recommend that AOG enter into agreements to dispose of Oil and Natural Gas Properties and make farmouts and other dispositions of such properties. Approval by the Board of Directors of any acquisitions or dispositions is required where the properties being acquired or disposed of have a purchase price or proceeds in excess of $2,000,000. Compensation and Term In its role under the Management Agreement as manager and administrator of AOG and the Trust, the Manager receives the following: 1. a fee in an amount equal to 1.5% of Operating Cash Flow, such amount to be calculated as at the end of each calendar quarter or portion thereof, if applicable, and paid on the 15th day following any such calendar quarter, or, if such day is not a Business Day, on the next Business Day; and 2. a fee in an amount equal to 10% of the Total Return Amount (which means, in respect of any Return Period, an amount equal to the Total Return Percentage minus 8% if the Return Period is a full calendar year, and adjusted appropriately should the Return Period be less than a full calendar year, multiplied by the Market Capitalization for that Return Period), such amount to be calculated as at the end of each Return Period and paid on the 15th day following the end of each such Return Period, or, if such day is not a Business Day, on the next Business Day. In addition, the Manager has the option (subject to any necessary regulatory approval) of receiving all or part of the fee provided in paragraph 2 above in Trust Units at the Unit Market Price calculated as at the end of the relevant period. To date, no such election has been made. The Manager representatives who act as employees or officers of AOG are entitled to participate in any benefit plans in place for AOG employees (including under any incentive plan) and are entitled to industry-competitive salaries (as approved by the Board of Directors) for acting in such capacity. The Manager does not receive any acquisition or disposition fees. It is the intention of the Manager that the management fees referred to in paragraphs 1 and 2 above (collectively, the "Management Fees") will fund all employee bonuses and incentive plans and, to date, such fees have been allocated by the Manager on the following basis: Manager Shareholders 66 2/3% Employees of AOG 33 1/3% The allocation of the Management Fees and the Termination Fees (as defined below) amongst the employees of AOG will be based upon the recommendations of the Manager as approved by the Board of Directors. The initial term (the "Initial Term") of the Management Agreement is 3 years, and on each anniversary date of the Management Agreement it automatically renews on an "evergreen" basis for additional one-year periods, provided that the Board of Directors has not provided notice to the Manager prior to any such renewal that such renewal shall not occur. In all instances of termination (except where the Management Agreement terminates at the end of the term), a termination fee (the "Initial Termination Fee") equal to the Management Fees paid for the immediately-prior two years shall be payable, which will be adjusted on a pro rata 47 basis to reflect a full two-year period if a two-year time period has not yet passed. Upon completion of the Initial Term, in all instances of termination (except where the Management Agreement terminates at the end of the term), a termination fee ("Subsequent Termination Fee") equal to the Management Fees paid for the immediately-prior 2 1/2 years shall be payable. In no instance shall the Manager be entitled to both the Initial Termination Fee and the Subsequent Termination Fee. The Initial Termination Fee and the Subsequent Termination Fee are, collectively, referred to herein as the "Termination Fees". Notwithstanding the foregoing, if, during the Initial Term, Kelly Drader (or an alternative individual with comparable skill and experience who is acceptable to the Board of Directors) no longer provides all or substantially all of his work time to AOG and the Trust, the Management Agreement can be terminated by AOG and the Trust and the Manager will not be entitled to any Termination Fees. In addition, the Manager is entitled to reimbursement, by the Trust and AOG, of General and Administrative Costs and expenses related to the Manager's performance under the Management Agreement, other than costs related solely to the Manager and costs related to employee bonuses and incentive plans. Conflicts of Interest The executive officers of the Manager have extensive experience in the oil and gas business and in the management of private and public entities. As a result, certain of the directors, officers and employees of the Manager, and certain of the consultants retained by the Manager, from time to time, may also be directors, officers and employees of affiliates of the Manager or may be consultants retained by affiliates of the Manager. The Management Agreement contains provisions which require the Manager to make disclosure to the Trustee and the Board of Directors of the fact and substance of any particular conflict of interest, if one should occur, and to use all reasonable efforts to resolve such conflict of interest in a manner which will treat the Trust or AOG, as the case may be, and the other interested party in an even-handed manner, taking into account all of the circumstances of the Trust or AOG, as the case may be, and such interested party, and to act honestly and in good faith in resolving such matters. Pursuant to the Management Agreement, the Manager has agreed to make Kelly Drader available for the performance of the services to be provided to the Trust and AOG, and Mr. Drader will, during the Initial Term, commit substantially all of his work time on an annual basis to AOG and the Trust in performing the services to be provided under the Management Agreement and in acting as AOG's President and Chief Executive Officer. The Management Agreement also provides that the Manager and the ManagementCo Group agree that during the Initial Term: 1. they will not manage another oil and gas income fund or royalty trust; 2. they will not, without prior approval of the Trust and AOG, acting reasonably, as determined by the Board of Directors, make investments in or acquire oil and gas assets or income funds, royalty trusts or companies owning oil and gas assets, except for the purchase of securities of public oil and gas companies, income funds or royalty trusts on a recognized stock exchange for investment purposes. Such shareholding in each such investment shall not exceed 10% of the issued and outstanding securities of any such issuer; and 3. they will not, without prior approval of the Trust and AOG, acting reasonably, as determined by the Board of Directors, conduct any other business activities relating to Canadian resource properties or rendering services or acting as advisor or manager to any other person or entity that may have investment or business interests similar to those of AOG or the Trust; and thereafter they will not do any of the foregoing except with prior disclosure to the Board of Directors of the nature and extent of their interest in such activities and a description of such activities and unless, in each case, the consent of the Board of Directors is first obtained. As at the date hereof, neither the Trust, AOG nor the Manager is aware of any existing or potential material conflicts of interest between the Trust and/or AOG and a director or officer of the Manager. 48 Cash Distributions The following is a summary of the distribution made by Advantage from its inception in May of 2001 to December 31, 2003.
For the 2001 Period Ended Distributions per Unit Payment Date ------------------------- ---------------------- ------------------ June 30 $0.28 July 16, 2001 July 31 0.28 August 15, 2001 August 31 0.22 September 17, 2001 September 30 0.22 October 15, 2001 October 31 0.15 November 15, 2001 November 30 0.15 December 17, 2001 December 31 0.15 January 15, 2002 ----- Total: $1.45 For the 2002 Period Ended Distributions per Unit Payment Date ------------------------- ---------------------- ------------------ January 31 $0.15 February 15, 2002 February 28 0.13 March 15, 2002 March 31 0.13 April 15, 2002 April 30 0.13 May 15, 2002 May 31 0.13 June 17, 2002 June 30 0.13 July 15, 2002 July 31 0.13 August 15, 2002 August 31 0.13 September 16, 2002 September 30 0.13 October 15, 2002 October 31 0.18 November 15, 2002 November 30 0.18 December 16, 2002 December 31 0.18 January 15, 2003 ----- Total: $1.73 For the 2003 Period Ended Distributions per Unit Payment Date ------------------------- ---------------------- ------------------ January 31 $0.18 February 18, 2003 February 28 0.23 March 17, 2003 March 31 0.23 April 15, 2003 April 30 0.23 May 15, 2003 May 31 0.23 June 16, 2003 June 30 0.23 July 15, 2003 July 31 0.23 August 15, 2003 August 31 0.23 September 15, 2003 September 30 0.23 October 15, 2003 October 31 0.23 November 17, 2003 November 30 0.23 December 15, 2003 December 31 0.23 January 15, 2004 ----- Total: $2.71
MARKET FOR SECURITIES The Trust Units are listed for trading on the TSX under the symbol "AVN.UN". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the Trust Units as reported by the TSX for the periods indicated. 49
Price Range ----------------- High Low ($) ($) Volume ----- ----- --------- 2003 ---- January .......... 13.73 12.86 2,153,333 February ......... 15.58 13.10 2,736,450 March ............ 15.59 11.80 2,732,097 April ............ 16.15 14.15 2,320,369 May .............. 16.55 15.30 2,579,951 June ............. 16.95 15.60 3,094,752 July ............. 16.30 14.92 2,625,024 August ........... 17.25 15.60 2,967,978 September ........ 17.20 16.01 2,408,053 October .......... 16.80 16.10 2,618,497 November ......... 16.60 15.68 2,854,848 December ......... 17.95 15.65 4,210,860
PROMOTERS Advantage Investment Management Ltd. could be considered the promoter of the Trust for the years 2001 and 2002. The Manager holds 732,737 Trust Units or 1.8% of the issued and outstanding Trust Units as at April 30, 2004. The Manager is a party to the Management Agreement with the Trust. See "Additional Information Respecting Advantage Investment Management Ltd.". LEGAL PROCEEDINGS There are no outstanding legal proceedings which are for claims in excess of 10% of the current asset value of the Trust to which the Trust is a party or in respect of which any of its properties are subject, nor are there any such proceedings known to be contemplated. INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS There were no material interests, direct or indirect, of directors of AOG or directors and senior officers of the Manager, nominees for director of AOG, any Unitholder who beneficially owns more than 10% of the Trust Units or any known associate or affiliate of such persons in any transaction during 2003 or in any proposed transaction which has materially affected or would materially affect the Trust or AOG other than (i) certain insiders purchasing Trust Units or Debentures under the public offerings of such securities completed during 2003, and (ii) as disclosed herein. AUDITORS, TRANSFER AGENT AND REGISTRAR The auditors of the Trust are KPMG LLP, Chartered Accountants, Calgary, Alberta. Computershare Trust Company of Canada at its offices in Calgary, Alberta and Toronto, Ontario acts as the transfer agent and registrar for the Trust Units, 8 1/4% Debentures, 9% Debentures and 10% Debentures. MATERIAL CONTRACTS Except for contracts entered into by the Trust in the ordinary course of business or otherwise disclosed herein, the only material contracts entered into by the Trust are the Trust Indenture described herein under the heading "Additional Information Respecting Advantage Energy Income Fund" and the Management Agreement described herein under the heading "Additional Information Respecting Advantage Investment Management Ltd. - Management Agreement". Copies of the Trust Indenture and Management Agreement were filed publicly on June 23, 2003 and November 21, 2003, respectively, and are available on the Trust's SEDAR profile at www.sedar.com. 50 INTEREST OF EXPERTS Burnet, Duckworth & Palmer LLP, Calgary, Alberta has helped prepare this annual information form and Sproule Associates Limited, has certified certain of the contents herein. No person or company whose profession or business gives authority to a statement made by such person or company and who is named in this annual information form or in a document that is specifically incorporated by reference into this annual information form as having prepared or certified a part of this annual information form, or a report or valuation described in this annual information form or in a document specifically incorporated by reference into this annual information form, has received or shall receive a direct or indirect interest in the property of the Trust or of any associate or affiliate of the Trust. As at the date hereof, the aforementioned persons and companies beneficially own, directly or indirectly, less than 1% of the securities of the Trust and its associates and affiliates. In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of the Trust or of any associates or affiliates of the Trust, except for Jay P. Reid, the Corporate Secretary of AOG, who is a partner at Burnet, Duckworth & Palmer LLP, which law firm renders legal services to the Trust. RISK FACTORS The following is a summary of certain risk factors relating to the business of AOG and the Trust. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this Annual Information Form. Dependence on AOG The Trust is an open-ended, limited purpose trust which will be entirely dependent upon the operations and assets of AOG through its ownership of the Common Shares, the Notes and the Royalty. Accordingly, the cash distributions to the Trust Unitholders will be dependent upon the ability of AOG to meet its interest and principal repayment obligations under the Notes to declare and pay dividends on the Common Shares, and to pay the Royalty. AOG's income will be received from the production of oil and natural gas from AOG's existing Canadian resource properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. AOG is generally not involved in the exploration for oil and natural gas. As a result, if the oil and natural gas reserves associated with AOG's Canadian resource properties are not supplemented through additional development or the acquisition of additional Oil and Natural Gas Properties, the ability of AOG to meet its obligations to the Trust may be adversely affected. Exploitation and Development Exploitation and development risks are due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. These risks are mitigated by using highly skilled staff, focusing exploitation efforts in areas in which Advantage has existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods, and controlling costs to maximize returns. Advanced oil and natural gas related technologies such as three-dimensional seismography, reservoir simulation studies and horizontal drilling have been and will be used by Advantage to improve its ability to find, develop and produce oil and natural gas. Operations AOG's operations are subject to all of the risks normally incident to the operation and development of Oil and Natural Gas Properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blow-outs, craterings and fires, all of which could result in personal injuries, loss of life and damage to the property of AOG and others. AOG has both safety and environmental policies in place to protect its operators and employees, as well as to meet the regulatory requirements in those areas where it operates. In addition, AOG has liability insurance policies in place, in such amounts as it considers adequate, however, it will not be fully insured against all of these risks, nor are all such risks insurable. Costs incurred to repair any of such damage or pay any of such liabilities will reduce Royalty Income. Continuing production from a property, and, to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in 51 receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of AOG to certain Properties. A reduction of the income from the Royalty could result in such circumstances. Expansion of Operations The operations and expertise of management of the Trust are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin. In the future, the Trust may acquire oil and gas properties outside this geographic area. In addition, the Trust Indenture does not limit the activities of the Trust to oil and gas production and development, and the Trust could acquire other energy related assets, such as oil and natural gas processing plants or pipelines, or an interest in an oil sands project. Expansion of our activities into new areas may present new additional risks or alternatively, may significantly increase the exposure to one or more of the present risk factors which may result in future operational and financial conditions of the Trust being adversely affected. Oil and Natural Gas Prices The monthly cash distributions the Trust pays to Unitholders are highly dependent upon the prices received for AOG's oil and natural gas production. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and AOG. These factors include, among others: o political conditions throughout the world; o worldwide economic conditions; o weather conditions; o the supply and price of foreign oil and natural gas; o the level of consumer demand; o the price and availability of alternative fuels; o the proximity to, and capacity of, transportation facilities; o the effect of worldwide energy conservation measures; and o government regulations. Declines in oil or natural gas prices will have an adverse effect upon the Trust's operations, financial condition, reserves and ultimately on its ability to pay distributions to Unitholders. The Trust may manage the risk associated with changes in commodity prices by entering into oil or natural gas price hedges. If the Trust hedges its commodity price exposure, it will forego the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity hedging activities could expose the Trust to losses. To the extent that the Trust engages in risk management activities related to commodity prices, it will be subject to credit risks associated with counterparties with which it contracts. Oil prices were relatively high throughout 2003 averaging US$31.04 WTI as compared to and average of US$26.08 WTI in 2002. The only quarter in the last two years that saw relatively low prices was the first quarter of 2002 when oil prices averaged US$21.64 WTI. Monthly AECO prices averaged $6.71/mcf in 2003 as compared to $4.07/mcf in 2002, an increase of 65%. The AECO gas price was weak throughout the first nine months of 2002 averaging $3.67/mcf; however, such price increased significantly to $5.26/mcf in the fourth quarter. The monthly AECO price in 2003 ranged from a high of $10.13/mcf in March to a low of $5.48/mcf in November. The price of oil and natural gas will fluctuate and price and demand are factors beyond Advantage's control. Such fluctuations will have a positive or negative effect upon the revenue to be received by it. Such fluctuations will also have an effect upon the acquisition costs of any future Oil and Natural Gas Properties that Advantage may acquire. As well, cash distributions from the Trust will be highly sensitive to the prevailing price of crude oil and natural gas. 52 Marketing The marketability and price of oil and natural gas that may be acquired or discovered by Advantage will be affected by numerous factors beyond Advantage's control. These factors include demand for oil and natural gas, market fluctuations, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to environmental protection, royalties, allowable production, pricing, importing and exporting of oil and natural gas. Capital Investment To the extent that AOG uses cash flow to finance acquisitions, development costs and other significant expenditures, the net cash flow of the Trust will be reduced. Hence, the timing and amount of capital expenditures may affect the amount of net cash flow available to the Trust and, as a consequence, the amount of cash available to distribute to Unitholders. Therefore, distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made. The Board of Directors has the discretion to determine the extent to which cash flow will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including under the credit facility. As a consequence, the amount of funds retained by AOG to pay debt services charges or reduce debt will reduce the amount of cash distributed to Unitholders during those periods in which funds are so retained. Assessments of Value of Acquisitions Acquisitions of resource issuers and resource assets will be based in large part upon engineering and economic assessments made by independent engineers. These assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the Trust's control. In particular, the prices of and markets for resource products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based upon reports by a firm of independent engineers that are not the same as the firm that the Trust uses for its year end reserve evaluations. Because each of these firms may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm used by the Trust. Any such instance may offset the return on and value of the Trust Units. Possible Changes in Accounting Standards Applicable to Convertible Debentures On November 3, 2003 the Accounting Standards Board of the Canadian Institute of Chartered Accountants approved, subject to a written ballot, a change to the accounting standards applicable to convertible debentures such as those proposed to be issued by the Trust. If approved, the new standard would require that the amounts outstanding under the Debentures be classified as liabilities and that the interest costs on the Debentures be included as interest expense in the determination of net income. The new standards would be effective for fiscal periods beginning on or after November 1, 2004. Debt Service AOG has credit facilities in the amount of $180,000,000. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to the Trust. Although it is believed that the bank line of credit is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of AOG or that additional funds can be obtained. The lenders have been provided with security over substantially all of the assets of AOG. If AOG becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lenders may foreclose on or sell the Properties free from or together with the Royalty. The payment of interest and principal on debt may also result in the Trust or its subsidiaries having taxable income and cash taxes payable as taxable income would no longer be reduced by royalty payments at the time debt repayment occurs. 53 Prior Ranking Indebtedness; Absence of Covenant Protection The Debentures will be subordinate to all Senior Indebtedness and to any indebtedness of creditors of Advantage. The payment of principal and interest on the Debentures will be subordinated to the Senior Indebtedness of Advantage and to indebtedness of trade creditors of Advantage. The Debentures will also be effectively subordinate to claims of creditors of Advantage's subsidiaries except to the extent Advantage is a creditor of such subsidiaries ranking at least pari passu with such other creditors. The Indentures will not limit the ability of Advantage to incur additional liabilities (including Senior Indebtedness) or to make distributions, except, in respect of distributions, where an Event of Default has occurred or would occur and such default has not been cured or waived. The Indentures do not contain any provision specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving Advantage. However, the Indentures, among other things, restrict the Trust's level of indebtedness, provides operating investment guidelines, mandates the making of distributions and specify the nature of the Trust's business. The economic impact on Advantage of claims of aboriginal title is unknown. Aboriginal people have claimed aboriginal title and rights to a substantial portion of western Canada. Advantage is unable to assess the effect, if any, that any such claim would have on its business and operations. Environmental Concerns The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. A breach of such legislation may result in the imposition of fines or issuance of clean-up orders in respect of AOG or the Properties. Such legislation may be changed to impose higher standards and potentially more costly obligations on AOG. Although AOG has established a reclamation fund for the purpose of funding its currently estimated future environmental and reclamation obligations based upon its current knowledge, there can be no assurance that the Trust will be able to satisfy its actual future environmental and reclamation obligations. Although AOG maintains insurance coverage considered to be customary in the industry, it is not fully insured against certain environmental risks, either because such insurance is not available, or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (compared to sudden and catastrophic damages) is not available. Accordingly, AOG's properties may be subject to liability due to hazards which cannot be insured against, or have not been insured against due to prohibitive premium costs or for other reasons. In such an event, these environmental obligations will be funded out of AOG's cash flow and could therefore reduce distributable income payable to Unitholders. Additionally, the potential impact on the Trust's operations and business of the December 1997 Kyoto Protocol, which has now been ratified by Canada, with respect to instituting reductions of greenhouse gases is difficult to quantify at this time as specific measures for meeting Canada's commitments have not been developed. Unforeseen Title Defects Although title reviews are generally conducted prior to any purchase of resource issuers or resource assets, such reviews do not guarantee that an unforeseen defect in the chain of title will not arise to defeat AOG's title to certain assets. A reduction of the distributable cash flow of the Trust and possible reduction of capital could result from such defects. Any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period will be funded out of cash flow and, therefore, will reduce the amounts available for distribution to Unitholders. Should the Trust be unable to fully fund the cost of remedying an environmental problem, it might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy. Delay in Cash Distributions In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of the Properties, and by the operator to the Manager or AOG, payments between any of such parties may also be delayed by restrictions imposed by lenders, delays in the sale or delivery of products, delays in the connection of wells to a gathering system, blowouts or other accidents, 54 recovery by the operator of expenses incurred in the operation of the Properties, or the establishment by the operator of reserves for such expenses. Any of these delays could adversely affect distributions to Unitholders. Foreign Currency Exchange Rates and Interest Rates World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the $US/$CAN exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar, which occurred in 2003, negatively impacted the Trust's net production revenue and may affect the future value of the Trust's reserves as determined by independent evaluations at this time. The impact is reduced to the extent that the Trust has engaged in, or in the future will engage in risk management activities related to commodity prices and foreign exchange rates. The Trust will be subject to unfavourable price changes and credit risks associated with the counterparties with which it contracts. The Trust has not entered into any foreign exchange contracts at this time. Variations in interest rates could result in a significant increase in the amount the Trust pays to service debt which may result in a decrease in distributions to Unitholders, as well as impact the market price of the Trust Units on the TSX. Reliance upon the Manager and Senior Executives of AOG Unitholders will be dependent upon the management of the Manager and AOG in respect of the administration and management of all matters relating to the Properties, the Royalty, the Trust and the Trust Units. The loss of the services of key individuals who currently comprise the management team of the Trust could have a detrimental effect upon the Trust. Investors who are not willing to rely on the management of the Manager and AOG should not invest in the Trust Units. Reserves The value of the Trust Units will depend upon, among other things, the reserves attributable to the Trust's properties. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the Trust's properties will vary from estimates and those variations could be material. The reserve and cash flow information contained in this annual information form represent estimates only. Reserves and estimated future net cash flow from the Trust's properties have been independently evaluated at the dates indicated by independent oil and gas reservoir engineering firms. These firms consider a number of factors and make assumptions when estimating reserves. These factors and assumptions include: o historical production in the area compared with production rates from similar producing areas; o the assumed effect of governmental regulation; o assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures; o initial production rates; o production decline rates; o ultimate recovery of reserves; o timing and amount of capital expenditures; o marketability of production; o future prices of oil and natural gas; o operating costs and royalties; and o other government levies that may be imposed over the producing life of reserves. These factors and assumptions were based upon prices at the date the relevant evaluations were prepared. If these factors and assumptions prove to be inaccurate, actual results may vary materially from the reserve estimates. Many of these factors are subject to change and are beyond the Trust's control. For example, evaluations are based in part upon the assumed success of exploitation activities intended to be undertaken in future years. Actual reserves and estimated cash flows will be less than those contained in the evaluations to the extent that such exploitation activities do not achieve the level of success assumed in the evaluations. Furthermore, cash flows may differ from those contained in the evaluations depending upon whether capital expenditures and operating costs differ from those estimated in the evaluations. 55 Depletion of Reserves The Trust has certain unique attributes that differentiate it from other oil and gas industry participants. Distributions of Distributable Income in respect of Properties, absent commodity price increases or cost effective acquisition and development activities will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. AOG will not be reinvesting cash flow in the same manner as other industry participants. Accordingly, absent capital injections, AOG's initial production levels and reserves will decline. AOG's future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent upon AOG's success in exploiting its reserve base and acquiring additional reserves. Without reserve additions through acquisition or development activities, AOG's reserves and production will decline over time as reserves are exploited. To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, AOG's ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. To the extent that AOG is required to use cash flow to finance capital expenditures or property acquisitions, the level of Distributable Income will be reduced. There can be no assurance that the Trust, will be successful in developing or acquiring additional reserves on terms that meet the Trust's investment objectives. Reliance upon Third Party Operators Continuing production from a property and marketing of product produced from the property are dependent to a large extent upon the ability of the operator of the property. The Trust currently operates properties that represent approximately 85% of its total daily production. To the extent the operator fails to perform these functions properly or becomes insolvent, revenue may be reduced. Accounting Write-Downs as a Result of GAAP Canadian Generally Accepted Accounting Principles ("GAAP") require that management apply certain accounting policies and make certain estimates and assumptions that affect reported amounts in the consolidated financial statements of the trust. The accounting policies may result in non-cash charges to net income and write-downs of net assets in the financial statements. Such non-cash charges and write-downs may be viewed unfavourably by the market and may result in an inability to borrow funds and/or may result in a decline in the Trust Unit price. Under GAAP, the net amounts at which petroleum and natural gas costs on a property or project basis are carried are subject to a cost-recovery test that is based in part upon estimated future net cash flow from reserves. If net capitalized costs exceed the estimated recoverable amounts, the Trust will have to charge the amounts of the excess to earnings. A decline in the net value of oil and natural gas properties could cause capitalized costs to exceed the cost ceiling, resulting in a charge against earnings. Emerging GAAP surrounding hedge accounting may result in non-cash charges against net income as a result of changes in the fair market value of hedging instruments. A decrease in the fair market value of the hedging instruments as the result of fluctuations in commodity prices and foreign exchange rates may result in a write-down of net assets and a non-cash charge against net income. Such write-downs and non-cash charges may be temporary in nature if the fair market value subsequently increases. Enforcement of Operating Agreements Operations of the wells on properties not operated by the Trust are generally governed by operating agreements, which typically require the operator to conduct operations in a good and workmanlike manner. Operating agreements generally provide, however, that the operator will have no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except such as may result from gross negligence or wilful misconduct. In addition, third-party operators are generally not fiduciaries with respect to the Trust or the Unitholders. The Trust, as owner of working interests in properties not operated by it, will generally have a cause of action for damages arising from a breach of such duty. Although not established by definitive legal precedent, it is unlikely that the Trust or Unitholders would be entitled to bring suit against third-party operators to enforce 56 the terms of the operating agreements; thus, Unitholders will be dependent upon the Trust, as owner of the working interest, to enforce such rights. Changes in Legislation There can be no assurance that the treatment of mutual fund trusts will not be changed in a manner adversely affecting Trust Unitholders. If the Trust ceases to qualify as a "mutual fund trust" under the Tax Act, the Trust Units will cease to be qualified investments for registered retirement savings plans, registered education savings plans, deferred profit sharing plans and registered retirement income funds. Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource taxation, may in the future be changed or interpreted in a manner that adversely affects the Trust and its Unitholders. Tax authorities having jurisdiction over the Trust or the Unitholders may disagree with how the Trust calculates its income for tax purposes or could change administrative practises to the detriment of the Trust or the detriment of its Unitholders. The Trust expects that it will continue to qualify as a mutual fund trust for purposes of the Tax Act. The Trust may not, however, always be able to satisfy any future requirements for the maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for the Trust and its Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows: o The Trust would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties held by the Trust. Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax. o The Trust would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws if it ceased to be a mutual fund trust. o Trust Units held by Unitholders that are not residents of Canada would become taxable Canadian property. These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them. o Trust Units would not constitute qualified investments for registered retirement savings plans ("RRSPs"), registered retirement income funds ("RRIFs"), registered education savings plans ("RESTs") or deferred profit sharing plans ("DPSPs"). If, at the end of any month, one of these exempt plans holds Trust Units that are not qualified investments, the plan must pay a tax equal to 1% of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan. An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units. If an RESP holds non-qualified Trust Units, it may have its registration revoked by the Canada Customs and Revenue Agency. In addition, the Trust may take certain measures in the future to the extent it believes necessary to ensure that the Trust maintains its status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units, particularly "non-residents" of Canada as defined in the Tax Act. See "Risk Factors - Non Resident Ownership of Trust Units". Investment Eligibility The Trust will endeavour to ensure that the Trust Units continue to be qualified investments for registered retirement savings plans, registered education savings plans, deferred profit sharing plans and registered retirement income funds. The Tax Act imposes penalties for the acquisition or holding of non-qualified or ineligible investments and there is no assurance that the conditions prescribed for such qualified or eligible investments will be adhered to at any particular time. 57 Nature of Trust Units The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in AOG. The Trust Units represent a fractional interest in the Trust. As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring "oppression" or "derivative" actions. The Trust's primary assets will be the Notes, the Common Shares, the Royalty and other investments in securities. The price per Trust Unit is a function of anticipated Distributable Income, the Properties acquired by AOG, and the Manager's ability to effect long-term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and the ability of the Trust to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the Trust Units. The Trust Units are also unlike conventional debt instruments in that there is no principal amount owing to Unitholders. The Trust Units will have minimal value when reserves from Advantage's properties can no longer be economically produced or marketed. Unitholders will only be able to obtain a return of the capital they invested during the period when reserves may be economically recovered and sold. Accordingly, the distributions received over the life of the investment may not be equal to or greater than the initial capital investment. The Trust Units are not "deposits" within the meaning of the Canada Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company. Net Asset Value The net asset value of the assets of the Trust from time to time will vary depending upon a number of factors beyond the control of management, including oil and gas prices. The trading prices of the Trust Units from time to time is also determined by a number of factors which are beyond the control of management and such trading prices may be greater than the net asset value of the Trust's assets. Additional Financing In the normal course of making capital investments to maintain and expand the oil and gas reserves of the Trust, additional Trust Units are issued from treasury which may result in a decline in production per Trust Unit and reserves per Trust Unit. Additionally, from time to time the Trust issues Trust Units from treasury in order to reduce debt and maintain a more optimal capital structure. To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, the Trust's and AOG's ability to make the necessary capital investments to maintain or expand its oil and gas reserves will be impaired. To the extent that the Trust and AOG are required to use cash flow to finance capital expenditures or property acquisitions or to pay debt service charges or to reduce debt, the level of Distributable Income will be reduced. Competition There is strong competition relating to all aspects of the oil and gas industry. There are numerous trusts in the oil and gas industry, who are competing for the acquisitions of properties with longer life reserves and properties with exploitation and development opportunities. As a result of such increasing competition, it will be more difficult to acquire reserves on beneficial terms. The Trust and AOG also compete for reserve acquisitions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial and other resources than the Trust and AOG. Return of Capital Trust Units will have no value when reserves from the Properties can no longer be economically produced and, as a result, cash distributions do not represent a "yield" in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Distributions represent a blend of a return of Unitholders' initial investment and a return on Unitholders' initial investment. 58 Unitholders have a limited right to require the Trust to repurchase their Trust Units, which is referred to as a redemption right. See "Information Relating to the Trust - Right of Redemption". It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investment. The right to receive cash in connection with a redemption is subject to limitations. Any securities which may be distributed in specie to Unitholders in connection with a redemption may not be listed on any stock exchange and a market may not develop for such securities. In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right. Redemption Right It is anticipated that the redemption right will not be the primary mechanism for Trust Unitholders to liquidate their investments. 14% Notes or Redemption Notes which may be distributed in specie to Trust Unitholders in connection with a redemption will not be listed on any stock exchange and no established market is expected to develop for such 14% Notes or Redemption Notes. Cash redemptions are subject to limitations. See "Additional Information Respecting Advantage Energy Income Fund - Redemption Right". Non-resident Ownership of Trust Units In order for the Trust to maintain its status as a mutual fund trust under the Tax Act, the Trust must not be established or maintained primarily for the benefit of non-residents of Canada ("non-residents") within the meaning of the Tax Act. The Board is proposing that certain changes be made to the Trust Indenture to provide that if at any time AOG becomes aware that the beneficial owners of 45% or more of the Trust Units then outstanding are or may be non-residents or that such a situation is imminent, AOG, on the Trust's behalf, shall review such actions as may be necessary to carry out the foregoing intention. Unitholder Limited Liability The Trust Indenture provides that no Trust Unitholder will be subject to any liability in connection with the Trust or its affairs or obligations and, in the event that a court determines that Trust Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of, such Unitholder's share of the Trust's assets. The Trust Indenture provides that all written instruments signed by or on behalf of the Trust must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. Personal liability may also arise in respect of claims against the Trust that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely. The operations of the Trust will be conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability on the Trust Unitholders for claims against the Trust. Future Dilution An objective of the Trust is to continually add to its reserves through acquisitions and through development, and because the Trust does not reinvest its cash flow, the success of the Trust is in part dependent upon its ability to raise capital from time to time. Holders of Trust Units may also suffer dilution in connection with future issuances of Trust Units, whether issued pursuant to a financing or acquisition or otherwise. Regulatory Matters The Trust's operations are subject to a variety of federal and provincial laws and regulations, including laws and regulations relating to the protection of the environment. Conflicts of Interest The directors and officers of the Corporation are engaged in and will continue to be engaged in other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of the Corporation may become subject to conflicts of interest. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in 59 respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA. ADDITIONAL INFORMATION Additional information, including directors' and officers' remuneration and indebtedness, principal holders of securities and interests of insiders in material transactions, where applicable, is contained in the Information Circular of the Trust dated April 16, 2004. Additional financial information is provided in Advantage's financial statements for the year ended December 31, 2003. The Trust shall provide to any person, upon request to the Chief Financial Officer of the Corporation: 1. when the securities of the Trust are in the course of a distribution pursuant to a preliminary short form prospectus or a short form prospectus: (a) one copy of the Annual Information Form of the Trust, together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form; (b) one copy of the comparative financial statements of Advantage for its most recently completed fiscal period for which financial statements have been filed, together with the accompanying report of the auditor and one copy of the most recent interim financial statements of the Trust that have been filed, if any, for any period after the end of its most recently completed financial year; (c) one copy of the Information Circular of the Trust in respect of its most recent annual and special meeting of Unitholders; and (d) one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus and which are not required to be provided under items (a) to (c) above; or 2. at any other time, one copy of any documents referred to in items (1)(a), (b) and (c) above, provided that the Trust may require the payment of a reasonable charge if the request is made by a person who is not a security holder of the Trust. For additional copies of this Annual Information Form and the materials listed in the preceding paragraphs, please contact: Advantage Energy Income Fund Suite 3100, 150 - 6th Avenue S.W. Calgary, Alberta T2P 3H7 Phone: (403) 261-8810 Fax: (403) 262-0723 A-1 SCHEDULE "A" FINANCIAL STATEMENTS OF MARKWEST RESOURCES CANADA CORP. November 12, 2003 Auditors' Report To the Directors of MarkWest Resources Canada Corp. We have audited the balance sheet of MarkWest Resources Canada Corp. (the "Company") as at December 31, 2002 and the statements of earnings and retained earnings (deficit) and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based upon our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2002 and the results of its operations and its cash flows for the year then ended in accordance with Canadian generally accepted accounting principles. "PricewaterhouseCoopers LLP" Chartered Accountants A-2 MarkWest Resources Canada Corp. Balance Sheet June 30, December 31, 2003 2002 $ $ (unaudited) Assets Current assets Cash 1,726,092 3,345,099 Accounts receivable 6,033,365 5,238,507 Prepaids and other current assets 677,276 574,714 ----------------------------- 8,436,733 9,158,320 Deferred financing costs 218,654 319,571 Property, plant and equipment (note 3) 152,640,666 142,334,142 ----------------------------- 161,296,053 151,812,033 ============================= Liabilities Current liabilities Accounts payable and accrued liabilities 14,099,386 9,948,858 Current portion of capital lease obligations 312,499 -- Advances from parent (note 6) 51,788,151 16,265,710 ----------------------------- 66,200,036 26,214,568 Long-term debt (note 4) 18,000,000 53,000,000 Capital lease obligation (note 5) 2,206,068 -- Provision for future site restoration (note 7) 1,386,888 1,159,212 Future income tax 39,091,849 45,360,728 ----------------------------- 126,884,841 125,734,508 ----------------------------- Shareholders' Equity Share capital (note 8) 28,542,263 28,542,263 Retained earnings 5,868,949 (2,464,738) ----------------------------- 34,411,212 26,077,525 ----------------------------- 161,296,053 151,812,033 ============================= Approved by the Board of Directors "Larry Strong" Director "Harvey Nelson" Director ------------------ ------------------- A-3
MarkWest Resources Canada Corp. Statement of Earnings and Retained Earnings (Deficit) For the six month period For the year ended ended June 30, December 31, 2003 2002 $ $ (unaudited) Revenue Petroleum and natural gas revenue 24,973,852 41,747,575 Royalties, net of Alberta Royalty Tax Credit (7,583,945) (10,026,021) ---------------------------- 17,389,907 31,721,554 Other Income 34,498 33,967 ---------------------------- 17,424,405 31,755,521 ---------------------------- Expenses Production 4,613,846 7,244,966 General and administrative 1,322,183 2,629,180 Depletion, depreciation, amortization and site restoration 8,291,569 21,248,048 Interest expense 878,873 1,596,929 Other 100,917 1,079,330 ---------------------------- 15,207,388 33,798,453 ---------------------------- Earnings (loss) before income taxes 2,217,017 (2,042,932) ---------------------------- Income taxes Current tax expense (recovery) 152,209 (160,291) Future tax recovery (6,268,879) (2,445,256) ---------------------------- (6,116,670) (2,605,547) ---------------------------- Net earnings for the period 8,333,687 562,615 Deficit - As at January 1 (2,464,738) (3,027,353) ---------------------------- Retained earnings (deficit) - End of period 5,868,969 (2,464,738) ============================
A-4
MarkWest Resources Canada Corp. Statement of Cash Flows For the six month period For the year ended ended June 30, December 31, 2003 2002 $ $ (unaudited) Cash provided by (used in) Net earnings for the period 8,333,687 562,615 Items not affecting cash Depreciation, depletion and amortization 8,291,569 21,248,048 Future income taxes (6,268,879) (2,445,256) Amortization of deferred financing costs 100,917 1,079,330 ---------------------------- 10,457,294 20,444,737 Net change in non-cash working capital items 4,032,286 2,265,829 ---------------------------- 14,489,580 22,710,566 ---------------------------- Investing activities Property, plant and equipment additions (18,215,689) (25,490,063) Proceeds on disposition of property, plant and equipment 2,579,439 -- Abandonment expenditures (103,183) (5,151) Change in capital accrual (236,478) (1,637,235) ---------------------------- (15,975,911) (27,132,449) ---------------------------- Financing activities Repayment of long-term debt (35,000,000) -- Advances from parent 34,979,741 5,646,530 Decrease in capital lease obligations (112,417) -- ---------------------------- (132,676) 5,646,530 ---------------------------- (Decrease) increase in cash (1,619,007) 1,224,647 Cash - Beginning of period 3,345,099 2,120,452 ---------------------------- Cash - End of period 1,726,092 3,345,099 ============================ Supplementary information Interest paid on long-term debt 1,495,649 2,692,095 Income taxes paid (received) 199,369 (500,783) Non-cash items Assets acquired under capital lease 2,630,984 --
A-5 MarkWest Resources Canada Corp. Notes to Financial Statements (Information as at and for the period ended June 30, 2003 is unaudited) June 30, 2003 (unaudited) and December 31, 2002 -------------------------------------------------------------------------------- 1. Nature of operations MarkWest Resources Canada Corp. (the "Company") explores for and produces oil and natural gas and is a wholly owned subsidiary of MarkWest Hydrocarbon, Inc. 2. Significant accounting policies Cash Cash consists of the balance with the bank, cash on hand and short-term investments with a maturity of three months or less when purchased. Property, plant and equipment The Company follows the full cost method of accounting for oil and gas operations, whereby all costs of exploring for and developing oil and gas properties and related reserves are capitalized. Such costs include land acquisition costs, costs of drilling both productive and non-productive wells, and geological and geophysical expenses and related overhead. Proceeds of disposition are applied against the cost pools with no gain or loss recognized except where the disposition results in a significant change in the rate of depletion. The carrying value is limited to the recoverable amount as determined by estimating the future net revenues from proven properties (based on period end prices and costs) and the value of unproven properties (at the lower of cost and net realizable value) less estimated future site restoration costs, general and administrative expenses and financing costs. Capitalized costs, excluding costs relating to unproven properties, are depleted using the unit-of-production method based on estimated proven reserves of oil and gas before royalties as determined by independent petroleum engineers. For purposes of the depletion calculation, oil and natural gas reserves and production are converted to a common unit-of-measure. Other assets are depreciated on a straight-line basis over the estimated service lives of the assets. Assets under capital lease are recorded at the present value of the lease payments at the inception of the lease. Provision for future site restoration The Company estimates its future site restoration and abandonment costs for its oil and gas properties. The costs represent management's best estimate of the future restoration and abandonment costs based upon current legislation and industry practices. The total estimated costs are being provided for on a unit-of-production basis. The annual provision is included in amortization expense and actual site restoration costs are charged to the liability account as incurred. Joint ventures Certain of the Company's activities are conducted jointly with other parties. These financial statements reflect the Company's proportionate interest in such activities. A-6 MarkWest Resources Canada Corp. Notes to Financial Statements (Information as at and for the period ended June 30, 2003 is unaudited) June 30, 2003 (unaudited) and December 31, 2002 -------------------------------------------------------------------------------- Financial instruments The Company's financial instruments are comprised of cash, accounts receivable, accounts payable, advances from parent, long term debt and commodity instruments (note 10). The fair value of the financial instruments approximates their carrying amount. A significant portion of the Company's accounts receivable is from oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting this industry, the risk of significant loss is considered remote. Income taxes The Company follows the liability method of accounting for income taxes. Under this method, the Company records future income taxes for the effect of any differences between the accounting and the income tax basis of an asset or liability using income tax rates substantially enacted on the balance sheet date. The effect of a change in income tax rates on the future income tax assets and liabilities is recognized in income in the period of the change. Measurement uncertainty The amount recorded for depletion and depreciation of capital assets and the provision for future site restoration costs are based on estimates. The ceiling test calculation is based on estimates of proven reserves, production rates, oil and gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect upon the financial statements from changes in such estimates in future periods could be significant. 3. Property, plant and equipment
June 30, 2003 ------------------------------------------- Accumulated Cost amortization Net $ $ $ Petroleum and natural gas properties and equipment 187,196,766 37,321,667 149,875,099 Furniture and equipment 354,338 186,868 167,470 Assets under capital lease 2,630,984 32,887 2,598,097 ------------------------------------------- 190,182,088 37,541,422 152,640,666 =========================================== December 31, 2002 ------------------------------------------- Accumulated Cost amortization Net $ $ $ Petroleum and natural gas properties and equipment 171,592,526 29,430,588 142,161,938 Furniture and equipment 322,328 150,124 172,204 ------------------------------------------- 171,914,854 29,580,712 142,334,142 ===========================================
A-7 MarkWest Resources Canada Corp. Notes to Financial Statements (Information as at and for the period ended June 30, 2003 is unaudited) June 30, 2003 (unaudited) and December 31, 2002 -------------------------------------------------------------------------------- Costs for unproven properties of $45,443,638 at June 30, 2003 and $48,420,924 at December 31, 2002 have been excluded from the depletion calculation. During the six month period ended June 30, 2003 and the year ended December 31, 2002, the Company capitalized no overhead costs related to exploration and development activities and capitalized $1,109,482 and $2,251,374 of interest expense respectively. Month end prices of $29.16/bbl (December 31, 2002 - $33.49/bbl) for oil and $6.34/mcf (December 31, 2002 -$5.66/mcf) for gas resulted in no ceiling test deficiency at June 30, 2003 or December 31, 2002. 4. Long-term debt On May 24, 2002, the Company amended its credit agreement ("Canadian Credit Facility") with various financial institutions for an amount of US$35,000,000. This facility is a component of the overall debt facility of the parent company, MarkWest Hydrocarbons, Inc. ("Parent") of Denver, Colorado. The overall amount of the Parent's facility ("Credit Facility") is US$60,000,000. Available borrowings under the Credit Facility are determined by a borrowing base that is determined by the value of the proved reserves of oil and gas owned by the Parent (directly or indirectly through subsidiaries, including MarkWest Resources Canada Corp.), and also on the working capital of the Parent, the level of which is determined by NGL product accounts receivable and inventory levels. The borrowing base on proved reserves is calculated semi-annually, while the borrowing base on working capital is calculated monthly. Actual borrowing limits for the Credit Facility may be less than US$60,000,000, depending on proved reserves, working capital levels, and financial covenants. The Company had outstanding borrowings of C$18,000,000, or approximately US$13,320,000, at June 30, 2003, and C$53,000,000, or approximately US$33,758,000, at December 31, 2002 of the US$35,000,000 available. The Canadian Credit Facility permits MarkWest Resources Canada Corp. to borrow money at a rate equal to the London Interbank Offered Rate ("LIBOR") plus an applicable margin of between 1.75% and 2.75% based on a certain leverage ratio, which is determined as the ratio of total funded debt to EBITDA. Funds can also be borrowed at the Canadian Prime Rate plus an applicable margin of between 0.375% and 1.375%, based on the leverage ratio. There is a fee on the unused portion of the Canadian Credit Facility of between 0.25% and 0.50%, based on the leverage ratio. The weighted average interest rate was 5.32% for the period ended June 30, 2003, and 5.02% for the year ended December 31, 2002. The Credit Facility is a revolving facility, with a maturity and expiry date of August 9, 2004. The entire outstanding principal balance is due in full on this date. The Credit Facility is collateralized by a first lien on substantially all the Company's assets. A-8 MarkWest Resources Canada Corp. Notes to Financial Statements (Information as at and for the period ended June 30, 2003 is unaudited) June 30, 2003 (unaudited) and December 31, 2002 -------------------------------------------------------------------------------- 5. Capital Lease obligations Future minimum annual lease payments at June 30, 2003 (December 31, 2002 - $nil) consist of the following: June 30, 2003 $ 2004 443,220 2005 443,220 2006 443,220 2007 and thereafter 1,585,200 ---------- 2,914,860 Less amounts representing interest at 5.5% (396,293) ---------- 2,518,567 Current portion (312,499) ---------- 2,206,068 ========== Interest of $35,323 relating to capital lease obligations is included in interest expense for the period ended June 30, 2003. 6. Advances from parent The advances from parent bear interest at 7% per annum, are due on demand and are unsecured. 7. Provision for future site restoration June 30, December 31, 2003 2002 $ $ Balance - Beginning of period 1,159,212 222,958 Current period provisions 330,859 941,405 Current period expenditures (103,183) (5,151) ---------- ---------- 1,386,888 1,159,212 ========== ========== The provision for future site restoration costs is recorded in the statement of income as a component of depletion, depreciation and amortization expense and on the balance sheet as a long-term liability. The total estimated liability is $4,700,000 at June 30, 2003 (December 31, 2002 - $3,960,000). A-9 MarkWest Resources Canada Corp. Notes to Financial Statements (Information as at and for the period ended June 30, 2003 is unaudited) June 30, 2003 (unaudited) and December 31, 2002 -------------------------------------------------------------------------------- 8. Share capital Authorized Unlimited number of common shares without nominal or par value Issued Number of Amount As at June 30, 2003 and December 31, 2002 shares $ Class A common shares 26,399,363 28,542,263 9. Commitments The Company has committed to certain payments for office space over the next four years as follows: June 30, 2003 $ 2004 188,348 2005 188,348 2006 188,348 2007 172,652 10. Commodity instruments Derivative commodity instruments may be used from time to time by the Company to manage its exposure to price risks relating to natural gas prices. The Company's policy is to not utilize derivative commodity instruments for trading or speculative purposes. Realized gains and losses on derivative instruments used as hedges are recognized in income in the period that the hedge is settled. The Company had the following natural gas hedge agreements outstanding at June 30, 2003 and December 31, 2002:
Volume Price Type (gj/day) ($/gj) Term Fixed price 2,462 4.62 Jan. 1, 2003 to Dec. 31, 2003 Fixed price 2,462 4.82 Jan. 1, 2003 to Dec. 31, 2003 Fixed price 1,758 4.65 Jan. 1, 2004 to Dec. 31, 2004 Fixed price 1,758 4.87 Jan. 1, 2004 to Dec. 31, 2004 Costless collar 2,462 4.09 - 5.24 Jan. 1, 2003 to Dec. 31, 2003 Costless collar 1,758 4.10 - 5.25 Jan. 1, 2004 to Dec. 31, 2004 Basis swap 6,330 Nymex/AECO Apr. 1, 2003 to Oct. 31, 2003 Basis swap 5,275 Nymex/AECO Apr. 1, 2003 to Oct. 31, 2003
The unrealized loss on these contracts was $6,105,538 as at June 30, 2003 and $4,117,199 as at December 31, 2002. B-1 SCHEDULE B - UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS COMPILATION REPORT The Board of Directors of Advantage Oil & Gas Ltd. We have read the accompanying unaudited pro forma consolidated balance sheet of Advantage Energy Income Fund (the "Fund") as at June 30, 2003 and unaudited pro forma consolidated statement of operations for the six months then ended and for the year ended December 31, 2002, and have performed the following procedures: 1. Compared the figures in the columns captioned "Advantage" to the unaudited consolidated financial statements of the Fund as at June 30, 2003 and for the six months then ended, and the audited consolidated financial statements of the Fund for the year ended December 31, 2002, respectively, and found them to be in agreement. 2. Compared the figures in the columns captioned "MarkWest" to the unaudited financial statements of MarkWest Resources Canada Corp. as at June 30, 2003 and for the six months then ended, and the audited financial statements of MarkWest Resources Canada Corp. for the year ended December 31, 2002, respectively, and found them to be in agreement. 3. Made enquiries of certain officials of the Fund who have responsibility for financial and accounting matters about: (a) The basis for determination of the pro forma adjustments; and (b) Whether the pro forma consolidated financial statements comply as to form in all material respects with the securities regulations of various provinces. The officials: (a) described to us the basis for determination of the pro forma adjustments, and (b) stated that the pro forma consolidated financial statements comply as to form in all material respects with the securities regulations of various provinces. 4. Read the notes to the pro forma consolidated financial statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments. 5. Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the columns captioned "Advantage" and "MarkWest" as at June 30, 2003 and for the six months then ended, and for the year ended December 31, 2002, and found the amounts in the column captioned "Pro forma" to be arithmetically correct. A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management's assumptions, the pro forma adjustments, and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma consolidated financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements. "KPMG LLP" Chartered Accountants Calgary, Canada November 21, 2003 B-2 ADVANTAGE ENERGY INCOME FUND PROFORMA CONSOLIDATED BALANCE SHEET (thousands of dollars) (unaudited)
Advantage MarkWest June 30, June 30, Pro Forma Pro Forma 2003 2003 Adjustments Consolidated -------------------------------------------------------------------------- Assets Current Accounts receivable 22,730 8,655 31,385 ------------------------------------------ --------- 22,730 8,655 -- 31,385 Property and equipment 403,980 152,641 (47,641) (note 2a) 508,980 Goodwill -- -- 27,146 (note 2a) 27,146 ------------------------------------------ --------- $ 426,710 $ 161,296 $ (20,495) $ 567,511 ========================================== ========= Liabilities Current Bank indebtedness $ 139,359 $ 18,000 79,037 (note 2a) $ 73,687 (133,909) (note 2a) (28,800) (note 2h) Accounts payable and accrued liabilities 28,306 14,412 2,000 (note 2a) 44,718 Advances from parent -- 51,788 (51,788) (note 2a) Cash distribution to Unitholders 7,116 -- 7,116 ------------------------------------------ --------- 174,781 84,200 (133,460) 125,521 Capital lease obligation -- 2,206 -- 2,206 Provision for future site restoration 5,968 1,387 -- 7,355 Future income taxes 62,057 39,092 (15,333) (note 2a) 85,816 ------------------------------------------ --------- $ 242,806 $ 126,885 $ (148,793) $ 220,898 ------------------------------------------ --------- Unitholders' Equity Unitholders' capital 202,658 28,542 (28,542) (note 2a) 278,967 76,309 (note 2a) Convertible debentures 18,556 -- 60,000 (note 2a) 108,556 30,000 (note 2h) Accumulated income 70,640 5,869 (5,869) (note 2a) 67,040 (3,600) (note 2h) Accumulated cash distributions (107,950) -- (note 2a) (107,950) ------------------------------------------ --------- 183,904 34,411 128,298 346,613 ------------------------------------------ --------- $ 426,710 $ 161,296 $ (20,495) $ 567,511 ========================================== =========
see accompanying notes to the unaudited proforma consolidated financial statements B-3 ADVANTAGE ENERGY INCOME FUND. PROFORMA CONSOLIDATED STATEMENT OF OPERATIONS (thousands of dollars) (unaudited)
Advantage MarkWest Six months Six months ended ended June 30, June 30, Pro Forma 2003 2003 Adjustments Pro Forma -------------------------------------------------------------------- Revenue Petroleum and natural gas sales $ 81,733 $ 25,009 $ 106,742 Royalties, net of ARC (14,706) (7,584) (50) (note 2b) (22,340) -------------------------------------------------------------------- 67,027 17,425 (50) 84,402 -------------------------------------------------------------------- Expenses Operating 11,138 4,715 15,853 General and administrative 1,740 1,322 3,062 Management fee 838 -- 838 Interest 3,387 879 (2,075) (note 2c) 2,191 Depletion, depreciation and site restoration 23,083 8,292 417 (note 2d) 31,792 Non-cash performance incentive 4,840 -- 4,840 -------------------------------------------------------------------- 45,026 15,208 (1,658) 58,576 -------------------------------------------------------------------- Income before taxes 22,001 2,217 1,608 25,826 Taxes Current income taxes 573 152 236 (note 2e) 961 Future income taxes (recovery) (15,007) (6,269) 701 (note 2f) (20,575) -------------------------------------------------------------------- (14,434) (6,117) 937 (19,614) -------------------------------------------------------------------- Net income $ 36,435 $ 8,334 $ 671 $ 45,440 ==================================================================== Net income per trust unit (note 2g) Basic $ 1.15 Diluted $ 1.06
see accompanying notes to the unaudited pro forma consolidated financial statements B-4 ADVANTAGE ENERGY INCOME FUND. PROFORMA CONSOLIDATED STATEMENT OF OPERATIONS (thousands of dollars) (unaudited)
Advantage MarkWest Six months Six months ended ended June 30, June 30, Pro Forma 2002 2002 Adjustments Pro Forma -------------------------------------------------------------------- Revenue Petroleum and natural gas sales $ 97,837 $ 41,782 $ 139,619 Royalties, net of ARC (17,344) (10,026) (50) (note 2b) (27,420) -------------------------------------------------------------------- 80,493 31,756 (50) 112,199 -------------------------------------------------------------------- Expenses Operating 18,486 7,245 25,731 General and administrative 2,624 2,629 5,253 Management fee 930 -- 930 Interest 4,272 1,597 (4,184) (note 2c) 1,685 Non-cash performance incentive 16,475 -- 16,475 Depletion, depreciation and site restoration 41,074 21,248 (4,373) (note 2d) 57,949 Other -- 1,079 1,079 -------------------------------------------------------------------- 83,861 33,798 (8,557) 109,102 -------------------------------------------------------------------- Income (loss) before taxes (3,368) (2,042) 8,507 3,097 Taxes Current income taxes 529 (160) 236 (note 2e) 605 Future income taxes (recovery) (15,992) (2,445) 3,619 (note 2f) (14,818) -------------------------------------------------------------------- (15,463) (2,605) 3,855 (14,213) -------------------------------------------------------------------- Net income $ 12,095 $ 563 $4,652 $ 17,310 ==================================================================== Net income per trust unit (note 2g) Basic $ 0.27 Diluted $ 0.27
see accompanying notes to the unaudited pro forma consolidated financial statements B-5 ADVANTAGE ENERGY INCOME FUND Notes to Pro Forma Consolidated Financial Statements Six months Ended June 30, 2003 and Year Ended December 31, 2002 (unaudited) 1. Basis of Presentation On November 12, 2003 Advantage Oil & Gas Ltd. entered into a Share Purchase Agreement to purchase all of the issued and outstanding shares of MarkWest Resources Canada Corp ("MarkWest"). The acquisition is expected to close on or before December 16, 2003. The accompanying unaudited pro forma consolidated balance sheet and pro forma consolidated statements of operations ("pro forma consolidated financial statements") have been prepared based on the unaudited balance sheets as at June 30, 2003 and the statement of operations of MarkWest and Advantage for the six months ended June 30, 2003 and the year ended December 31, 2002. The accompanying unaudited pro forma consolidated financial statements have been prepared by management of Advantage Energy Income Fund ("Advantage") in accordance with Canadian generally accepted accounting principles. In the opinion of management, the pro forma consolidated financial statements include all material adjustments necessary for fair presentation in accordance with Canadian generally accepted accounting principles. The pro forma consolidated balance sheet gives effect to the transactions described in Note 2 as if they occurred on the balance sheet date while the pro forma consolidated statements of operations give effect to these transactions as if they had occurred at the beginning of the period. These pro forma consolidated financial statements may not be indicative either of the results that actually would have occurred if the events reflected herein had been in effect upon the dates indicated or of the results which may be obtained in the future. Accounting policies used in the preparation of the pro forma financial statements are consistent with those used in the audited financial statements for Advantage prepared for the year ended December 31, 2002. This financial information should be read in conjunction with Advantage's audited financial statements for that year. 2. Pro forma transactions and assumptions (a) Under the terms of the agreement, Advantage would acquire all of the issued and outstanding shares of MarkWest for total cash consideration of $81,037,000. The acquisition is being accounted for under the purchase method. Net assets acquired at fair market value are as follows: ($000's) Working capital (deficiency) $ (5,757) Site restoration liability (1,387) Bank indebtedness (18,000) Capital lease obligation (2,206) Future income taxes (23,759) Goodwill 27,146 Property and equipment 105,000 --------- $ 81,037 --------- B-6 ADVANTAGE ENERGY INCOME FUND Notes to Pro Forma Consolidated Financial Statements Six months Ended June 30, 2003 and Year Ended December 31, 2002 (unaudited) The above represents management's preliminary assessment of assets acquired. The allocation of the purchase price will be finalized after the business combination has been completed and the fair values of the assets and liabilities have been determined, accordingly the above allocation is subject to change. Transaction costs incurred by Advantage in connection with the acquisition include legal, advisory and other professional costs of $2,000,000 and have been included in accounts payable and accrued liabilities. Consideration comprised of: Cash $79,037 Transaction costs 2,000 ------- $81,037 ======= The acquisition is to be financed through the issuance of $60,000,000 of 8 1/4% subordinated convertible debentures and the issuance of 5.1 million trust units issued at a price of $15.75 per unit. Associated underwriters' fees of $2,400,000 are included in accumulated income. Excess proceeds over the purchase price of MarkWest will be used to reduce bank debt. (b) Alberta Royalty Credit has been reduced to reflect the requirement of Advantage to share the maximum annual limit with its subsidiaries. (c) A reduction of interest expense has been calculated by applying applicable bank interest rates averaging 5.0% for the period to the decrease in the bank loan with respect to the proceeds raised in excess of the purchase price. (d) Depletion, depreciation has been adjusted on a consolidated basis incorporating the fair value of the assets of MarkWest determined under the purchase method as set out in note 2(a) and incorporating the combined reserves and production. (e) Current taxes have been adjusted to reflect changes in large corporations tax. (f) Future income tax expense has been adjusted to tax effect the pro forma income statement adjustments. (g) Pro forma basic per unit amounts are based on the weighted average number of Advantage units outstanding for the period plus the additional units issued pursuant to the prospectus. Pro forma diluted per unit amounts are based on the weighted average number of diluted Advantage units outstanding for the period plus the additional units that would be issued on the conversion of the convertible debentures referenced under 2(a) and 2(h). (h) Convertible debentures and bank debt have been adjusted to reflect Advantage's issuance of $30,000,000 of 9.00% subordinated convertible debentures on July 8, 2003. Associated underwriters' fees of $1,200,000 are included in accumulated income. 3. Convertible Debentures The convertible debentures and related interest obligations have been classified as equity on the balance sheet as the Trust may elect to satisfy the debenture interest and principle obligation by the issuance of Trust Units. Issue costs associated with the debentures have been treated as a reduction to retained earnings. When calculating cash available for distribution to Unitholders, interest on the convertible debentures is deducted from cash flow from operations.