EX-99 4 ex99-1form40_f.txt EXHIBIT 99.1 EXHIBIT 99.1 ------------ ADVANTAGE ENERGY INCOME FUND RENEWAL ANNUAL INFORMATION FORM 2004 MARCH 21, 2005 TABLE OF CONTENTS PAGE GLOSSARY OF TERMS..............................................................1 ABBREVIATIONS..................................................................4 CONVERSION.....................................................................4 ADVANTAGE ENERGY INCOME FUND...................................................6 GENERAL DEVELOPMENT OF THE BUSINESS............................................7 RECENT DEVELOPMENTS............................................................9 DESCRIPTION OF OUR BUSINESS AND OPERATIONS.....................................9 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION..................10 ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND................28 ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD.....................34 ADDITIONAL INFORMATION RESPECTING ADVANTAGE INVESTMENT MANAGEMENT LTD.........41 MARKET FOR SECURITIES.........................................................48 ESCROWED SECURITIES...........................................................50 PAST PROMOTER.................................................................50 LEGAL PROCEEDINGS.............................................................50 INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS......................50 MATERIAL CONTRACTS............................................................50 INTEREST OF EXPERTS...........................................................51 AUDITORS, TRANSFER AGENT AND REGISTRAR........................................51 AUDIT COMMITTEE INFORMATION...................................................51 AUDIT COMMITTEE CHARTER.......................................................52 AUDIT SERVICE FEES............................................................56 RISK FACTORS..................................................................56 ADDITIONAL INFORMATION........................................................64 SCHEDULES "A" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION "B" - REPORT ON RESERVES DATA GLOSSARY OF TERMS "DEBENTURES" means, collectively, the 7.50% Debentures, 7.75% Debentures, 8.25% Debentures, 9% Debentures and 10% Debentures; "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; "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 us or in the management and administration of AOG, the Royalty and us including, without limitation: (a) all reasonable costs and expenses relating to AOG, the Royalty and us and paid directly to third parties by or on behalf of AOG, us or our affiliates, including, without limitation, Trustee's fees; and (b) all reasonable costs and expenses incurred specifically for AOG or us relating to AOG, the Royalty or us 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 us (other than the Management Fees). For greater clarity, employee bonuses and amounts paid to employees under incentive plans are not reimbursable; "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; "LONG TERM NOTE INDENTURE" means the master note indenture dated September 30, 2004 between AOG and Computershare Trust Company of Canada providing for the issuance of the Long Term Notes; "LONG TERM NOTES" means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Long Term Note Indenture; "MANAGEMENT AGREEMENT" means the amended and restated management agreement dated October 4, 2004 among AOG, the Manager and the Trustee on our behalf; "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; "MEDIUM TERM NOTE INDENTURE" means the master note indenture dated September 30, 2004 between AOG and Computershare Trust Company of Canada providing for the issue of Medium Term Notes; "MEDIUM TERM NOTES" means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Medium Term Note Indenture; "NOTE INDENTURES" means, collectively, the Long Term Note Indenture and the Medium Term Note Indenture; "NOTE TRUSTEE" means Computershare Trust Company of Canada, or its successor as trustee under the Note Indentures; "NOTES" means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Note Indentures; "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; 2 "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 we receive 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 royalties, gross overriding royalties and lessors' royalties, but for certainty not deducting the Royalty or any royalties payable to us by AOG in all other respects; "PERMITTED INVESTMENTS" means, with respect to up to 25% of our total assets, (unless otherwise approved by the board of directors of AOG 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; "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; "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 us dated as of December 1, 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 our settlor to the Trustee for the purpose of settling the Trust; "SHAREHOLDER AGREEMENT" means the shareholder agreement entered into as of May 24, 2001 between AOG and the Trustee, as our trustee for and on our behalf; "SUBSEQUENT INVESTMENT" means those investments which we are 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; 3 "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", 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 trust indenture between Computershare Trust Company of Canada and AOG made effective as of April 17, 2001, supplemented as of May 22, 2002 and amended and restated as of June 25, 2002, May 28, 2002 and May 26, 2004, pursuant to which Advantage was formed, as the same may be further amended, restated or replaced from time to time; "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 of AOG; and "UNITHOLDERS" means the holders from time to time of one or more Trust Units, as shown on the register of such holders maintained by the Trust or by the Transfer Agent on behalf of the Trust. 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 renewal annual information form are in Canadian dollars, except where otherwise indicated. 4 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 6.293 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 5 YOU SHOULD NOT RELY ON FORWARD-LOOKING STATEMENTS BECAUSE THEY ARE INHERENTLY UNCERTAIN Certain statements contained in this renewal annual information form, and in certain documents incorporated by reference into this renewal annual information form, constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. 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. We 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 renewal annual information form should not be unduly relied upon. These statements speak only as of the date of this renewal annual information form or as of the date specified in the documents incorporated by reference into this renewal annual information form, as the case may be. In particular, this renewal annual information form, and the documents incorporated by reference, contain forward-looking statements pertaining to the following: o the performance characteristics of our assets; 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 renewal 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 fluctuation in foreign exchange or interest rates; o stock market volatility and market valuations; o changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts; o geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and o the other factors discussed under "Risk Factors". Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward looking statements contained in this renewal annual information form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Neither the Trust, the Manager, nor AOG undertakes any obligation to publicly update or revise any forward-looking statements and readers should also carefully consider the matters discussed under the heading "Risk Factors" in this renewal annual information form. 6 ADVANTAGE ENERGY INCOME FUND GENERAL Advantage Energy Income Fund ("ADVANTAGE", the "TRUST", the "FUND", "US", "WE", or "OUR" and, where the context requires, also includes the Trust's subsidiaries) is an entity that provides monthly cash distributions to its holders ("UNITHOLDERS") of trust units ("TRUST UNITS") of the Trust. 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. Advantage Oil & Gas Ltd. ("AOG") is an oil and natural gas exploitation and development company that is wholly-owned by us. It was originally incorporated in 1979 as Westrex Energy Corp. ("WESTREX"). Through a plan of arrangement under the BUSINESS CORPORATIONS ACT (Alberta) ("ABCA"), Westrex merged with Search Energy Inc. on December 31, 1996, and changed its name to Search Energy Corp. ("SEARCH") on January 2, 1997. Effective May 24, 2001, all of the issued and outstanding common shares of Search were acquired by 925212 Alberta Ltd. ("ACQUISITIONCO"), a corporation wholly-owned by us. 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 Resources Inc. ("DUE WEST"). Effective August 1, 2001, Search and Due West were amalgamated and continued as "Search Energy Corp.". Effective January 1, 2002, Search acquired a number of natural gas properties located primarily in southern Alberta formerly administered by Gascan Resources Ltd. 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 Resources Ltd. ("BEST PACIFIC"). On December 2, 2003, AOG acquired all of the issued and outstanding shares of MarkWest Resources Canada Corp. ("MARKWEST"). MarkWest was amalgamated with AOG effective January 1, 2004. On September 15, 2004, we indirectly acquired certain petroleum and natural gas properties and related assets from Anadarko Canada Corporation ("ANADARKO") for approximately $186,000,000 before closing adjustments. On December 21, 2004, we indirectly acquired Defiant Energy Corporation ("DEFIANT") by way of the Arrangement (as defined herein) involving a combination of cash consideration, Trust Units and Exchangeable Shares of AOG. Effective January 1, 2005, Defiant amalgamated with AOG. In accordance with the Management Agreement, Advantage Investment Management Ltd. (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. Our head office, the head office of the Manager and AOG and the registered office of AOG is located at Suite 3100, 150 - 6th Avenue S.W., Calgary, Alberta, T2P 3Y7. The registered office of the Manager is located at Suite 1400, 350 - 7th Avenue S.W., Calgary, Alberta, T2P 3N9. OUR ORGANIZATIONAL STRUCTURE The following diagram sets forth our organizational structure as at the date hereof. [GRAPHIC OMITTED] [ORGANIZATIONAL CHART] Notes: (1) The Unitholders own 100% of the Trust. (2) Cash distributions are made to Unitholders monthly based upon our 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 us as to how to vote in respect of all matters to be placed before us, including the selection of directors of AOG, approving AOG's financial statements, and appointing the auditors of AOG, who shall be the same as our auditors. The Shareholder Agreement provides that the Unitholders are entitled to elect a majority of the board of directors of AOG and the Manager has the right to designate two of such directors. GENERAL DEVELOPMENT OF THE BUSINESS 2002 On January 29, 2002, we 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. We used the net proceeds of the issue to complete the acquisition of certain natural gas properties, to repay bank debt and to fund our 2002 capital expenditure program. The first annual and special meeting of Unitholders was held on June 25, 2002 at which, among other things, Unitholders considered and approved the name change from "Search Energy Corp." to "Advantage Oil & Gas Ltd." and the addition of a class of non-voting common shares for AOG. On September 10, 2002, we completed an asset exchange transaction whereby it acquired additional interests in producing natural gas properties at Vermilion, Alberta in consideration for our interest in heavy oil properties located in Wainwright, Alberta. The exchange was structured as a property swap with us neither receiving nor paying any cash in relation to the transaction. On September 30, 2002, we announced that it had entered into an acquisition agreement providing for an offer to purchase, by way of formal take-over bid, all of the issued and outstanding common shares of Best Pacific, including all shares issued upon the exercise of outstanding options and warrants, on the basis of $1.25 cash consideration for each share. We acquired 95% of the shares and completed the compulsory acquisition of the remaining shares effective November 21, 2002. The acquisition of Best Pacific had a net purchase price, after adjustments and fees, of 8 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. On October 18, 2002, in conjunction with the acquisition of Best Pacific, we closed an offering, on a bought deal basis by way of short form prospectus, of $55,000,000 aggregate principal amount of debentures, which 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 (the "10% DEBENTURES"). Interest is payable on the 10% Debentures semi-annually and commenced on May 1, 2003. The net proceeds of the offering were used to fund the acquisition of Best Pacific, to reduce bank indebtedness and for general corporate purposes. 2003 On July 8, 2003, we completed the issue, by way of short form prospectus, of $30,000,000 principal amount of 9% convertible unsecured subordinated debentures, which debentures mature on August 1, 2008 and are convertible into Trust Units at $17.00 per Trust Unit (the "9% DEBENTURES"). The net proceeds of the offering were used to fund an expanded capital expenditure program and to repay debt. On December 8, 2003, we 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 subordinated debentures, which debentures mature on February 1, 2009 and are convertible into Trust Units at $16.50 per Trust Unit (the "8 1/4% DEBENTURES"). The net proceeds of the offering were used to fund the acquisition of MarkWest, to reduce amounts outstanding under our credit facility and to fund drilling and exploitation capital expenditures. In conjunction with the completion of the financing, we also announced the completion of the MarkWest acquisition for total cash consideration of $96,800,000 prior to adjustments. 2004 On September 15, 2004, we completed an issue, by way of short form prospectus, of 3,500,000 Trust Units and $75 million aggregate principal amount of 7.50% convertible unsecured subordinated debentures (the "7.50% Debentures") and $50 million aggregate principal amount of 7.75% convertible unsecured subordinated debentures (the "7.75% DEBENTURES") to partially finance the acquisition of certain petroleum and natural gas properties and related assets from Anadarko. On December 21, 2004, we closed the Defiant Acquisition in exchange for a combination of cash consideration, Trust Units and Exchangeable Shares of AOG. See "Significant Acquisitions" for further details. On December 21, 2004, we announced the closing of our acquisition of Defiant (the "DEFIANT ACQUISITION") by way of plan of arrangement (the "ARRANGEMENT") under section 193 of the ABCA. Pursuant to the Arrangement, shareholders of Defiant could elect to receive (i) 0.201373 of a Trust Unit for each Defiant share, (ii) 0.201373 of an AOG exchangeable share for each Defiant share, or (iii) $2.79889 per Defiant share and the balance of the consideration in Trust Units as set out in option (i). In addition, Defiant shareholders received one sixth of one common share of Defiant Resources Corporation, a newly incorporated exploration company. The Defiant Acquisition is consistent with our strategy of focusing on natural gas and light oil properties that provide low risk drilling upside. The transaction is accretive to our 2005 cash flow and production per unit and provides us with additional lower risk drilling and recompletion opportunities. The asset base acquired from Defiant is highly concentrated consisting of three core areas located in central Alberta in close proximity to our existing operations and approximately 90% of the production is operated, with four projects representing 85% of the current production. SIGNIFICANT ACQUISITIONS On September 15, 2004, we indirectly acquired certain petroleum and natural gas properties and related assets from Anadarko Canada Corporation (the "ACQUIRED ASSETS") for total consideration of approximately $186 million before closing adjustments (the "ASSET ACQUISITION"). The Asset Acquisition has an effective date of July 1, 2004. The Business Acquisition Report in respect of the Asset Acquisition, dated September 30, 2004, was filed in accordance with Part 8 of National Instrument 51-102 Continuous Disclosure Obligations ("NI 51-102") and is incorporated herein by reference. 9 ANTICIPATED CHANGES IN THE BUSINESS As at the date hereof, we do not anticipate that any material change in our business shall occur during the balance of the 2005 financial year. RECENT DEVELOPMENTS On February 9, 2005, we completed an issue, by way of short form prospectus, of 5,250,000 Trust Units at $21.65 per Trust Unit for gross proceeds of $113,662,500. We initially used the net proceeds of the offering to repay a portion of our indebtedness under our credit facilities incurred in connection with, among other things, the Defiant Acquisition. The net proceeds will ultimately be used for our 2005 capital expenditure program and for general purposes. As at the closing of the offering, 56,575,489 Trust Units were issued and outstanding. DESCRIPTION OF OUR BUSINESS AND OPERATIONS ADVANTAGE ENERGY INCOME FUND We are a limited purpose trust and are 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 our behalf or using any of our assets or property which are defined as "foreign property" under subsection 206(1) of the INCOME TAX ACT (Canada) ("TAX ACT") or are a "small business security" as that expression is used in Part LI of the Regulations to the Tax Act or would result in us 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 us 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 ours 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 we 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, we will make cash distributions to our Unitholders of the interest income earned from the Long Term 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". 10 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. We employ 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 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 our 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, the issuance of additional Trust Units from treasury and the issuance of subordinated convertible debentures, maintaining prudent leverage. 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 of AOG 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 assist in executive decisions which conform to the general policies and general principles previously established by the board of directors. The Manager is entitled to designate two directors to serve on the board of directors. The Manager also provides executive officers to AOG, subject to the approval of the board of directors of AOG. STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION The report of management and directors on oil and gas disclosure in Form 51-101F3 and the report on reserves data by Sproule Associates Limited ("SPROULE") in Form 51-101F2 are attached as Schedules "A" and "B" to this renewal annual information form, which forms are incorporated herein by reference. The statement of reserves data and other oil and gas information set forth below (the "STATEMENT") is dated December 31, 2004. The effective date of the Statement is December 31, 2004 and the preparation date of the Statement is February 17, 2005. DISCLOSURE OF RESERVES DATA The reserves data set forth below (the "RESERVES DATA") is based upon an evaluation by Sproule with an effective date of December 31, 2004 contained in a report of Sproule dated February 17, 2005 (the "SPROULE REPORT"). The Reserves Data summarizes our oil, liquids and natural gas reserves 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 our 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 OUR 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. 11 RESERVES DATA (CONSTANT PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE as of December 31, 2004 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 11,880.9 10,400.1 1,456.2 1,300.2 189,026 159,160 2,628.9 1,945.4 Developed Non-Producing 491.0 398.7 0.0 0.0 9,497 7,703 134.8 98.6 Undeveloped 3,271.1 2,900.4 0.0 0.0 15,813 12,334 376.5 275.8 Total Proved 15,643.0 13,699.2 1,456.2 1,300.2 214,335 179,197 3,140.2 2,319.8 -------- -------- ------- ------- ------- ------- ------- ------- Probable 11,501.6 10,042.8 597.1 536.8 85,562 69,139 1,897.7 1,391.1 -------- -------- ------- ------- ------- ------- ------- ------- Total Proved Plus Probable 27,144.6 23,742.0 2,053.3 1,837.0 299,897 248,335 5,037.9 3,710.9 ======== ======== ======= ======= ======= ======= ======= =======
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 1,146,393 843,443 684,199 584,120 514,455 1,146,393 843,443 684,199 584,120 514,455 Developed Non- 47,966 37,858 31,125 26,314 22,708 47,966 37,858 31,125 26,314 22,708 Producing Undeveloped 112,906 79,814 56,660 40,864 29,626 112,906 79,814 56,660 40,864 29,626 Total Proved 1,307,266 961,114 771,984 651,299 566,788 1,307,266 961,114 771,984 651,299 566,788 --------- --------- --------- ------- ------- --------- --------- --------- ------- ------- Probable 654,920 361,057 240,149 176,219 136,995 654,920 361,057 240,149 176,219 136,995 --------- --------- --------- ------- ------- --------- --------- --------- ------- ------- Total Proved Plus Probable 1,962,185 1,322,172 1,012,134 827,519 703,783 1,962,185 1,322,172 1,012,134 827,519 703,783 ========= ========= ========= ======= ======= ========= ========= ========= ======= =======
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) as of December 31, 2004 CONSTANT PRICES AND COSTS ($000's) Future Net Future Net Well Sask. Revenue Revenue Reserves Operating Development Abandonment Corp. Before Income Income After Income Category Revenue Royalties Costs Costs Costs Capital Tax Taxes Taxes Taxes -------- ------- --------- ----- ----- ----- ----------- ----- ----- ----- Proved 2,249,881 357,089 485,710 65,829 29,524 4,463 1,307,266 0 1,307,266 Proved Plus Probable 3,394,537 555,981 741,478 96,565 30,576 7,753 1,962,185 0 1,962,185
12
FUTURE NET REVENUE BY PRODUCTION GROUP as of December 31, 2004 CONSTANT PRICES AND COSTS Future Net Revenue Before Income Taxes (Discounted At Reserves Category Production Group 10%/Year) ----------------- ---------------- --------- ($000's) Proved Light and Medium Crude Oil (including solution gas and other 245,588 by-products) Heavy Oil (including solution gas and other by-products) 4,504 Natural Gas (including by-products but excluding solution gas 513,826 from oil wells) Proved Plus Probable Light and Medium Crude Oil (including solution gas and other 364,482 by-products) Heavy Oil (including solution gas and other by-products) 7,333 Natural Gas (including by-products but excluding solution gas 631,877 from oil wells)
RESERVES DATA (FORECAST PRICES AND COSTS)
SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE as of December 31, 2004 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 11,714.2 10,292.0 1,562.4 1,359.8 186,137 156,849 2,601.3 1,928.6 Developed Non-Producing 490.8 399.5 0.0 0.0 9,494 7,701 134.8 98.7 Undeveloped 3,262.6 2,903.6 0.0 0.0 15,764 12,292 376.7 276.1 Total Proved 15,467.6 13,595.1 1,562.4 1,359.8 211,395 176,841 3,112.8 2,303.5 -------- -------- ------- ------- ------- ------- ------- ------- Probable 11,318.6 9,953.6 624.1 539.7 82,552 66,598 1,874.1 1,378.5 -------- -------- ------- ------- ------- ------- ------- ------- Total Proved Plus Probable 26,786.2 23,548.7 2,186.5 1,899.5 293,946 243,439 4,986.9 3,682.0 ======== ======== ======= ======= ======= ======= ======= =======
Net Present Values Of Future Net Revenue ------------------------------------------------------------------------------------------------ Before Income Taxed 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 984,488 739,592 613,438 534,063 478,300 984,488 739,592 613,438 534,063 478,300 Producing Developed 38,209 30,840 25,880 22,283 19,543 38,209 30,840 25,880 22,283 19,543 Non-Producing Undeveloped 83,899 62,321 44,808 32,454 23,510 83,899 62,321 44,808 32,454 23,510 Total Proved 1,106,596 832,752 684,126 588,800 521,354 1,106,596 832,752 684,126 588,800 521,354 --------- --------- ------- ------- ------- --------- --------- ------- ------- ------- Probable 563,511 302,458 200,968 148,757 117,031 563,511 302,458 200,968 148,757 117,031 --------- --------- ------- ------- ------- --------- --------- ------- ------- ------- Total Proved Plus Probable 1,670,108 1,135,209 885,094 737,557 638,385 1,670,108 1,135,209 885,094 737,557 638,385 ========= ========= ======= ======= ======= ========= ========= ======= ======= =======
13
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) as of December 31, 2004 FORECAST PRICES AND COSTS ($000's) Future Net Future Net Well Revenue Revenue Reserves Operating Development Abandonment Sask. Corp. Before Income After Income Category Revenue Royalties Costs Costs Costs Capital Tax Income Taxes Taxes Taxes -------- ------- --------- ----- ----- ----- ----------- ------------ ----- ----- Proved 2,097,734 325,069 556,424 66,184 38,527 4,936 1,106,596 0 1,106,596 Proved Plus Probable 3,198,813 504,336 875,288 97,277 43,451 8,371 1,670,108 0 1,670,108
FUTURE NET REVENUE BY PRODUCTION GROUP as of December 31, 2004 FORECAST PRICES AND COSTS Future Net Revenue Before Income Taxes (Discounted At Reserves Category Production Group 10%/Year) ----------------- ---------------- --------- ($000's) Proved Light and Medium Crude Oil (including solution gas and other 222,377 by-products) Heavy Oil (including solution gas and other by-products) 9,750 Natural Gas (including by-products but excluding solution gas 444,090 from oil wells) Proved Plus Probable Light and Medium Crude Oil (including solution gas and other 323,969 by-products) Heavy Oil (including solution gas and other by-products) 13,500 Natural Gas (including by-products but excluding solution gas 539,228 from oil wells)
PRICING ASSUMPTIONS The following tables set forth the benchmark reference prices, as at December 31, 2004, reflected in the Reserves Data. These price assumptions were provided to us by Sproule and were Sproule's then current forecasts at the date of the Sproule Report.
SUMMARY OF PRICING ASSUMPTIONS as of December 31, 2004 CONSTANT PRICES AND COSTS Oil(1) ----------------------------------------------------- Natural Gas(1) WTI Edmonton Hardisty AECO Gas Pentanes Propanes Cushing Par Price Heavy Cromer Medium Price Plus Fob Butanes Fob Fob Field Exchange Oklahoma 40(degree)API 12(degree)API 29.3(degree)API ($Cdn/ Field Gate Field Gate Gate Rate(2) Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) MMBtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/$Cdn) ---- --------- ---------- ---------- ---------- ------ ---------- ---------- ---------- ---------- Historical (3) 2004 44.04 46.51 15.26 32.10 6.78 51.80 39.78 36.11 0.8319
Notes: (1) This summary table identifies benchmark reference pricing schedules that might apply to a REPORTING ISSUER. (2) The exchange rate used to generate the benchmark reference prices in this table. (3) As at December 31. 14
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS as of December 31, 2004 FORECAST PRICES AND COSTS Oil(1) ----------------------------------------------------- Natural Pentanes Propane Gas(1) Plus Fob Butanes Fob WTI Edmonton Hardisty Cromer Aeco Gas Field Fob Field Cushing Par Price Heavy Medium Price Gate Field Gate Inflation Exchange Oklahoma 40(degree)API 12(degree)API 29.3(degree)API ($Cdn/ ($Cdn/ Gate ($Cdn/ Rates(2) Rate(3) Year ($US/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) ($Cdn/Bbl) MMbtu) Bbl) ($Cdn/Bbl) bbl) %/Year ($US/$Cdn) ---- --------- ---------- ---------- ---------- ------ ---- ---------- ---- ------ ---------- Forecast 2005 44.29 51.25 28.91 44.53 6.97 52.49 38.20 32.09 2.5 0.840 2006 41.60 48.03 28.12 41.87 6.66 49.19 34.01 30.07 2.5 0.840 2007 37.09 42.64 26.19 37.27 6.21 43.67 30.20 26.70 2.5 0.840 2008 33.46 38.31 25.06 33.43 5.73 39.23 27.13 23.98 2.5 0.840 2009 31.84 36.36 23.60 31.70 5.37 37.24 25.75 22.76 1.5 0.840 2010 32.32 36.91 24.12 32.22 5.47 37.80 26.13 23.11 1.5 0.840 2011 32.80 37.47 24.64 32.75 5.57 38.37 26.53 23.46 1.5 0.840 2012 33.30 38.03 25.17 33.29 5.67 38.95 26.93 23.81 1.5 0.840 2013 33.79 38.61 25.71 33.83 5.77 39.54 27.34 24.17 1.5 0.840 2014 34.30 39.19 26.26 34.38 5.87 40.14 27.75 24.53 1.5 0.840 Thereafter 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5 0.840
Notes: (1) This summary table identifies benchmark reference pricing schedules that might apply to a REPORTING ISSUER. (2) Inflation rates for forecasting prices and costs. (3) Exchange rates used to generate the benchmark reference prices in this table. Weighted average historical prices realized by us for the year ended December 31, 2004, were $6.43/Mcf for natural gas, $47.62/bbl for crude oil, $41.91/bbl for natural gas liquids. 15 RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE
RECONCILIATION OF TRUST NET RESERVES BY PRINCIPAL PRODUCT TYPE FORECAST PRICES AND COSTS Light And Medium Oil Heavy Oil Natural Gas Liquids ------------------------------ -------------------------------- -------------------------------- Net Net Net Proved Proved Proved Net Net Plus Net Plus Net Net Plus Proved Probable Probable Net Proved Probable Probable Proved Probable Probable --------- --------- --------- ---------- --------- --------- --------- ---------- --------- FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) December 31, 2003 5,790 4,058 9,848 4 1 5 1,380 593 1,973 Extensions 1,794 1,050 2,844 0 0 0 318 234 552 Improved Recovery 0 0 0 0 0 0 0 0 0 Technical Revisions 637 (153) 484 318 301 619 98 146 244 Discoveries 0 0 0 0 0 0 0 0 0 Acquisitions 6,750 5,202 11,952 1,149 238 1,387 726 405 1,131 Dispositions (187) (237) (424) 0 0 0 (5) (7) (12) Economic Factors 137 34 171 0 0 0 8 7 15 Production (1)(2) (1,326) 0 (1,326) (111) 0 (111) (221) 0 (221) ------ ----- ------ ----- --- ----- ----- ----- ----- December 31, 2004 13,595 9,954 23,549 1,360 540 1,900 2,304 1,378 3,682 ====== ===== ====== ===== === ===== ===== ===== =====
Associated and Non-Associated Gas Solution Gas --------------------------------- -------------------------------- Net Net Proved Proved Net Net Plus Net Net Plus Proved Probable Probable Proved Probable Probable --------- ---------- --------- --------- ---------- --------- FACTORS (mmcf) (mmcf) (mmcf) (mmcf) (mmcf) (mmcf) December 31, 2003 152,850 40,074 192,924 5,010 3,906 8,916 Extensions 219 197 416 5,414 3,960 9,374 Improved Recovery 0 0 0 0 0 0 Technical Revisions 1,794 (379) 1,415 527 288 815 Discoveries 0 0 0 0 0 0 Acquisitions 27,986 14,348 42,334 8,285 3,683 11,968 Dispositions 0 0 0 (60) (99) (159) Economic Factors 1,197 534 1,731 220 86 306 Production (1)(2) (25,575) 0 (25,575) (1,026) 0 (1,026) ------- ------ ------- ------ ------ ------ December 31, 2004 158,471 54,774 213,245 18,370 11,824 30,194 ======= ====== ======= ====== ====== ======
Note: (1) Includes production from the Anadarko properties from September 15 - December 31, 2004. (2) Includes Defiant production from December 21 - December 31, 2004. 16
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 2004 ----------------------------------------------------------------------------------------- -------- Estimated Future Net Revenue at Beginning of Year 520,226 Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties (154,631) Net Change in Prices, Production Costs and Royalties Related to Future Production 33,225 Actual Development Costs Incurred During the Period 107,893 Changes in Estimated Future Development Costs (54,083) Extensions and Improved Recovery 39,407 Discoveries 0 Acquisitions of Reserves 245,905 Dispositions of Reserves (4,342) Net Change Resulting from Revisions in Quantity Estimates 20,074 Accretion of Discount 18,310 Net Change in Income Taxes 0 - Estimated Future Net Revenue at End of Year 771,984 =======
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 2005. The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each by product type, attributed to us in the most recent financial year.
PROVED UNDEVELOPED RESERVES Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids Year (Mbbl) (Mbbl) (MMcf) (Mbbl) Mboe ---- ------ ------ ------ ------ ---- 2004 3,263 0 15,765 377 6,267 PROBABLE UNDEVELOPED RESERVES Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids Year (Mbbl) (Mbbl) (MMcf) (Mbbl) Mboe ---- ------ ------ ------ ------ ---- 2004 5,757 35 15,685 579 8,985
SIGNIFICANT FACTORS OR UNCERTAINTIES High operating costs substantially reduce our netback, which in turn reduces the amount of cash available for reinvestment in drilling opportunities. This becomes most relevant during periods of low commodity prices when profits are more significantly impacted by high costs. FUTURE DEVELOPMENT COSTS The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserve categories noted below. 17
Constant Prices and Costs Forecast Prices and Costs ($000's) ($000's) -------------------------------------------------------- ------------------------- Year Proved Reserves Proved Plus Probable Reserves Proved Reserves ---- --------------- ----------------------------- --------------- 0% 10% 0% 10% 0% 10% -- --- -- --- -- --- 2005 56,467 54,715 81,205 78,187 56,467 54,715 2006 6,408 5,554 12,219 10,591 6,252 5,421 2007 2,158 1,701 2,267 1,786 2,054 1,621 2008 811 581 822 589 753 539 Additional years 340 179 764 371 303 160 Total 66,184 62,730 97,277 91,524 65,829 62,456
To fund our capital program, including future development costs, we have many financing alternatives available including partial retention of cash flow from operations, bank debt financing, issuance of additional Trust Units, and convertible debentures. We evaluate the appropriate financing alternatives closely and have made use of all these options dependent on the given investment situation and the capital markets. We maintain a capital structure that is similar to our industry peer group and that will maximize the investment return to Unitholders as compared to the cost of financing. We expect to continue using all financing alternatives available to continue pursuing our oil and gas development strategy. The assorted financing instruments have certain inherent costs which we consider in the economic evaluation of pursuing any development opportunity. OTHER OIL AND GAS INFORMATION OIL AND GAS PROPERTIES The following is a description of our principal oil and natural gas properties on production or under development as at January 1, 2005. The term "net", when used to describe our share of production, means the total of our working interest share before deduction of royalties owned by others. Reserve amounts are stated, before deduction of royalties, at December 31, 2004, based upon forecast cost and price assumptions (gross) as evaluated in the Sproule Report. Unless otherwise specified, gross and net acres and well count information are as at January 1, 2005. Information in respect of current production is 2004 exit production, net to us, except where otherwise indicated. MEDICINE HAT, ALBERTA The Medicine Hat (Bowmanton) property is located 20 km northeast of the City of Medicine Hat in the heart of the southeastern shallow gas area. We have a 100% working interest in 24 sections of land from which production is taken from all of the main shallow gas producing formations including the Medicine Hat "A", "C" and "D" sands, as well as both the Upper and Lower Milk River 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. Late in 2003 an additional 57 wells were drilled and completed in 2004. In 2004 a further 68 wells were drilled and completed. As a result, in January 2005 this property was producing 21.2 MMcf/d from approximately 380 wells. Compression capacity was increased in late 2003 by approximately 10 MMcf/d to accommodate added production from the drilling programs. No additional compression was added in 2004. Sproule evaluated our reserves in the area and assigned 65.6 bcf of proved natural gas reserves and 8.2 bcf of probable reserves. As such, this property is our largest property on an assigned reserves basis. NEVIS, ALBERTA The Nevis property is situated 50 km east of Red Deer. Nevis consists of approximately 35 sections of land with an average working interest over 75% and is 90% operated. Natural gas production occurs from numerous shallow depth horizons including the Edmonton, Belly River and Viking formations. Oil and natural gas is produced from the slightly deeper reservoirs (1,200 m) of the Glauconite, Ostacod and Ellerslie formations within the Mannville Group. The main zone of interest however occurs at 1,600 meters in Devonian aged carbonates of the Big Valley Member of the Wabamun Formation. In 2004, Wabamun oil was principally targeted, although gas was also drilled in both the Wabamun and shallower horizons. Development of the oil is being accomplished by horizontal drilling into the average 3 meter thick 18 carbonate. Completion of wells is accomplished with selective acid squeezes over the main porous intervals. Crude quality is exceptional ranging in the most part between 36 and 42o API. Natural gas is gathered through AOG owned pipelines and processed at a third party plant. Oil is trucked from single well batteries. In 2004, 16 horizontal wells and 5 vertical wells were drilled. We currently have on production, or awaiting imminent tie-in, 14 horizontal wells, which were all drilled prior to year end of 2004. Production at the end of January 2005 is 2,039 boe/d. An additional 12 wells have been drilled in 2005 to the end of February. Currently the pool is spaced to allow for 4 wells per section. Drilling continues at the current spacing; however, the property is being reviewed for down spacing to 8 wells per section in the second half of 2005. In addition a study is underway to evaluate the potential waterflood of this reservoir to increase future recoveries. The Sproule Report assigns 13 bcf of proven natural gas reserves and 3,314 Mbbls of proven crude oil and NGL reserves to this property. In addition, 8.4 bcf of probable natural gas reserves and 2,445 Mbbls of risked probable crude oil and NGL reserves have been assigned to this property. BANTRY, ALBERTA Bantry is located immediately east of the town of Brooks straddling the TransCanada Highway. The property consists of 86 sections of land ranging between 50% and 100% working interest. Since the acquisition of this property in November 2003, 48 (gross) new wells were drilled. Production occurs primarily from Basal Colorado Formation channel sandstones and various sandstones within the Bow Island Formation. Drilling depth is shallow with average wells less than 1,000 meters. Natural gas is gathered into our operated compression and dehydration facilities. Current net production from this area is approximately 1.6 Mboe/d. Additional compression capacity was added in the first quarter of 2004 to handle incremental volumes. The property was last drilled in June 2004 and all productive wells have been completed and tied-in, however it is being reviewed for additional drilling with 5 to 6 new wells possible in late 2005 or into 2006. The Sproule Report assigns 17.1 bcf of proven natural gas reserves and 28 Mbbls of proven NGL reserves to this property. In addition, 6.9 bcf of probable natural gas reserves and 11 Mbbls of probable NGL reserves have been assigned to this property. CHIP LAKE, ALBERTA The Chip Lake property is located 125 km west of Edmonton. It produces light oil (37oAPI) from the Jurassic aged Rock Creek Formation, with some associated natural gas. This property was acquired in December 2004 with the Defiant Acquisition. Currently the property produces 250 bbls/d and 300 mcf/d. One well drilled in the 4th quarter of 2004 has been completed and is being equipped for production. Additional drilling will occur after regulatory approval of the facility and waterflood has been received. Defiant had essentially built the oil facility and water handling facilities but had not received approval to commence operations. We are currently working through the process with the EUB and expect to have the property fully operational in the second half of 2005. Production is however occurring by the use of single well batteries. In addition to the existing pool, we also acquired some additional undeveloped land with the Defiant Acquisition and has seismically identified stepout opportunities. The Sproule Report assigns 1.5 bcf of proven natural gas reserves and 2,300 Mbbls of proven crude oil and NGL reserves to this property. In addition, 1.7 bcf of probable natural gas reserves and 2,441 Mbbls of risked probable crude oil and NGL reserves have been assigned to this property. SUNSET-VALLEYVIEW AREA, ALBERTA This area is located approximately 100 km east of the city of Grande Prairie, just north of the town of Valleyview. It consists of a group of three main producing properties: Sunset A, Sunset B, and Valleyview. All three properties produce from the Triassic Montney Formation, with some production from younger Cretaceous reservoirs such as the Gething. These properties came with the Defiant Acquisition in December 2004. 19 SUNSET A- Montney production in these reservoirs is both oil and gas and occurs from progressively younger stratigraphic traps beneath the Jurassic unconformity. The youngest sand is preserved the furthest downdip at the Sunset A pool and production is predominantly oil at 32oAPI. This pool is unitized and we have a 70% interest in the unit and operate. Development plans include the drilling of three wells spaced across the unit which will evaluate the viability of moving the full pool onto a downspaced basis. In addition, a pipeline and accompanying compression is planned to gather solution gas and transport it to the Sunset B facility to the north. Gas is currently being flared. Current net production from the Sunset A unit is 158 bbls/d and 160 mcf/d. The Sunset A pool was discovered in 1960 and has a long history of stable low decline production. It is one of our longest life reservoirs. SUNSET B - Production from this Montney reservoir is predominantly gas although there is a thin oil column. Oil gravity is light at 33oAPI. Defiant began operations at Sunset B in mid 2000 and commissioned a sour gas processing plant and gathering system late that year. The plant and gathering system were expanded in December 2003, increasing total throughput capacity to 12 MMcf/d. There is potential to add further compression and upgrades in modular increments to increase throughput capacity to approximately 20 MMcf/d. Current production from Sunset B is 3,000 Mcf/d and 100 bbls/d. A small amount of gas is produced as well from the Cretaceous and Bluesky reservoirs. Sunset B has a long production history and long reserve life. The original discovery well, Defiant Sunset 2-14-70-20 W5M, has been on production for 28 years, and has recovered 350 Mboe to date and still produces 12 bbls/d and 85 mcf/d. VALLEYVIEW - The Sunset B and Valleyview properties are in close proximity to each other, with the Valleyview property connected to the Sunset B gas processing plant by a twelve kilometre pipeline where natural gas, NGL and light oil from both properties are processed. Production at Valleyview is from three separate sands all older than those at Sunset A or B. Additional drilling locations exist and seismic re-interpretation is underway to confirm these. Production at Valleyview is essentially all natural gas with current rates of 5.1 MMcf/d. All wells require fracture stimulation to bring them on production and cost about $750,000 drilled, completed and tied-in. For the three properties, Sunset A, Sunset B and Valleyview, the Sproule Report assigns 25.2 bcf of proven natural gas reserves and 1,537 Mbbls of proven crude oil and NGL reserves to this property. In addition, 9.8 bcf of probable natural gas reserves and 1,034 Mbbls of probable crude oil and NGL reserves have been assigned to this property. SHOULDICE, ALBERTA The Shouldice area of southern Alberta is located approximately 45 km southeast of the city of Calgary. We have an average working interest of more than 85% in 34 sections of land and operate in excess of 90% of our production. Much of this acreage is downspaced to accommodate additional drilling. In January 2005, natural gas production of 5,521 MMcf/d was produced on a co-mingled basis from the Medicine Hat sand with various Belly River Formation sands. In addition to natural gas, we also produce 42 bbls/d of medium gravity (33(degree) API) crude oil from the deeper, Mannville Group, Basal Quartz Formation. During 2003, 20 net wells were added to the existing 70 producers. Both natural gas and crude oil are produced and gathered through AOG owned facilities of varying working interests. An additional 4 MMcf/d of new compression capacity was added in 2004 to handle additional production. Four additional sections of land have been assembled and the project is under review for additional drilling later in 2005. The Sproule Report assigns 12.2 bcf of proven natural gas reserves and 79 Mbbls of proven crude oil and NGLs to this property. In addition, 2.7 bcf of probable natural gas reserves and 19 Mbbls of probable crude oil and NGL reserves have been assigned to this property. 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, is low cost and requires minimal capital expenditures. We own an interest in 30 producing wells (22 net) in the area. We operate approximately 80% of the natural gas production and have a 40% working interest in the oil production. The area includes 12,000 gross (9,176 20 net) acres of undeveloped land. Current production from this area is 5 MMcf/d of natural gas and 140 bbls/d of light oil and NGLs. Sproule evaluated our proved reserves in the area and assigned 11.1 bcf of natural gas and 466 Mbbls of crude oil and NGLs. In addition, 4.1 bcf of probable natural gas reserves and 227 Mbbls of probable crude oil and NGLs reserves have been assigned to this property. WAINWRIGHT, ALBERTA This property, which has varying working interests averaging more than 80% in approximately 175 sections of land, is located in east central Alberta, approximately 40 kilometers northwest of Wainwright, Alberta. Current net production from the property is 5,000 Mcf/d natural gas, 30 bbl/d NGLs and crude oil. In 2002, we swapped out virtually all of our heavy oil assets in this area for producing natural gas assets in our adjacent area of Vermilion. Natural gas production occurs from the Manville Group and Viking Formations at shallow depths of between 450 and 700 meters. We operate 95% of our production in this area as well as own and operate a majority interest in an extensive gas gathering system tied into three Advantage-operated gas compression facilities. In 2003, 23.3 net wells were drilled for a combination of Viking and Upper Mannville zones. Sproule evaluated our proved reserves in the Wainwright area and assigned 9.3 bcf of natural gas. Probable reserves in this area were evaluated by Sproule at 5.6 bcf of natural gas. BRAZEAU RIVER, ALBERTA The Brazeau River property is located approximately 50 km west of the town of Drayton Valley, Alberta. The property produces sour light oil and natural gas primarily from Devonian aged Nisku pinnacle reefs. The majority of the production is from a non-operated 50% working interest in the Nisku C, D and E pools and a 17% working interest in the Nisku A unit. The property was acquired in the package of assets purchased from Anadarko in 2004. Sweet natural gas is also produced from eight natural gas wells out of reservoirs in either of the Cretaceous aged Cardium, Viking or Lower Mannville Formations. Major facility interests include a 25.7% working interest in the West Pembina Sour Gas Plant and a 31.6% working interest in the Brazeau River Gas Plant. Current net production from the property is 4,000 Mcf/d natural gas and 310 bbl/d NGLs and crude oil. Sproule evaluated our proved reserves in the Brazeau River area and assigned 3.8 bcf of natural gas and 323 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 2.3 bcf of natural gas and 288 Mbbls of crude oil and NGLs. OPEN LAKE, ALBERTA The Open Lake property is located approximately 35 km north of the town of Rocky Mountain House, Alberta. The property was acquired in the package of assets purchased from Anadarko in 2004. We operate and have a 100% working interest in the Open Lake property. Oil and natural gas production from this property is multi-zoned from various Cretaceous and Jurassic reservoirs including the Rock Creek, Ellerslie, Ostracod, Viking, Second White Specks and Belly River Formations. We have recently re-entered an existing wellbore and completed a Glauconite zone which has production tested gas rates in excess of 1 MMcf/d. The well is expected to be tied-in by the end of the 1st quarter 2005. Additional re-completion opportunities exist in several offsetting wells and we are actively engaged in re-completing and evaluating these. Net current production from the property is 2,648 Mcf/d natural gas and 283 bbl/d NGLs and crude oil. Sproule evaluated our proved reserves in the Open Lake area and assigned 3.4 bcf of natural gas and 341 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 2.3 bcf of natural gas and 247 Mbbls of crude oil and NGLs. 21 OIL AND GAS WELLS The following table sets forth the number and status of wells as at December 31, 2004 in which we have a working interest.
Oil Wells Natural Gas Wells ------------------------------------------ ---------------------------------------- Producing Non-Producing Producing Non-Producing --------- ------------- --------- ------------- Gross Net Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- ----- --- Alberta 564 355.9 391 222.4 1,090 934.7 211 120.5 British Columbia 1 0.4 5 2.3 64 37.3 15 6.2 Saskatchewan 187 140.5 86 62.8 - - - - Manitoba 85 5.1 - - - - - - --- ----- --- ----- ----- ----- --- ----- Total 837 501.9 482 287.5 1,154 972.0 226 126.7 === ===== === ===== ===== ===== === =====
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 our developed and undeveloped land holdings as at December 31, 2004.
Developed Acres Undeveloped Acres Total Acres ------------------------ ------------------------ ------------------------ Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Alberta 680,245 334,110 469,438 253,338 1,149,683 587,448 British Columbia 96,934 18,821 24,344 7,335 121,278 26,156 Saskatchewan 30,077 21,466 142,374 124,070 172,451 145,536 ------- ------- ------- ------- --------- ------- Total 807,256 374,397 636,156 384,743 1,443,412 759,140 ======= ======= ======= ======= ========= =======
We expect that rights to explore, develop and exploit 117,205 net acres of our undeveloped land holdings will expire by December 31, 2005. The land expirations do not consider our 2005 exploitation and development program that may result in extending or eliminating such potential expirations. We closely monitor land expirations as compared to our development program with the strategy of minimizing undeveloped land expirations relating to significant identified opportunities. 22 FORWARD CONTRACTS We currently have the following hedge contracts in place:
DESCRIPTION OF HEDGE AND TERM VOLUME AVERAGE PRICE ----------------------------- ------ ------------- NATURAL GAS - AECO Fixed Price January to March 2005 10,450 mcf/d $6.30 Cdn/mcf Fixed Price April to October 2005 34,123 mcf/d $7.45 Cdn/mcf Collar April to October 2005 11,374 mcf/d Floor $6.86 Cdn/mcf Ceiling $8.18 Cdn/mcf Collar April to October 2005 11,374 mcf/d Floor $7.02 Cdn/mcf Ceiling $8.02 Cdn/mcf CRUDE OIL - WTI Fixed Price April to September 2005 1,750 bbls/d $52.11 US/bbl Collar April to October 2005 1,750 bbls/d Floor $47.00 US/bbl Ceiling $56.75 US/bbl
ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS We estimate the costs to abandon and reclaim all our shut-in and producing wells, facilities, gas plants, pipelines, batteries and satellites. No estimate of salvage value is netted against the estimated cost. Our 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 we hold. 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. We estimate that we will incur reclamation and abandonment costs on 1,888.1 net producing and non-producing wells. Costs to abandon and reclaim the producing wells totals $43.5 million ($10.7 million discounted at 10%) and are included in the estimate of future net revenue. The additional liability associated with non-producing wells, pipelines and facilities reclamation costs was estimated to be $14 million ($2.8 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 our 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 2005, $1.2 million in 2006 and $1.3 million in 2007. TAX HORIZON In 2004, we did not pay any income related taxes. However, we did pay capital taxes that are determined based on the debt and equity levels of the Trust at the end of a given year. As a result of new legislation in 2003, capital taxes are to be gradually eliminated over the next four years. In the Fund's structure, the operating company utilizes available tax pools to significantly reduce taxable income and makes other required payments to the Trust transferring both income and associated tax liability to the Unitholders. Therefore, it is expected, based on current legislation that no cash income taxes are to be paid by the operating company in the future and it is our intent to continue with the current arrangement. For the 2004 distributions, 38.33% were taxable to the Unitholders and 61.67% were deemed a return of capital. 23 CAPITAL EXPENDITURES The following tables summarize capital expenditures (including capitalized general and administrative expenses) related to our activities for the year ended December 31, 2004:
CAPITAL EXPENDITURES ($ THOUSANDS) 2004 ----------------------------------------------------------------------------- ---------------------- Land and seismic $ 3,034 Drilling, completions and workovers 68,327 Well equipping and facilities 35,655 Other 877 ----------------------------------------------------------------------------- ---------------------- $107,893 Acquisition of Anadarko Properties 179,115 Acquisition of Defiant Energy Corporation(1) 200,291 Property acquisitions 1,530 Property dispositions (6,539) ----------------------------------------------------------------------------- ---------------------- TOTAL CAPITAL EXPENDITURES $482,290 ----------------------------------------------------------------------------- ----------------------
Note: (1) Represents consideration of $144.1 million plus net debt assumed of $56.2 million. EXPLORATION AND DEVELOPMENT ACTIVITIES The following table sets forth the gross and net wells in which we participated during the year ended December 31, 2004:
Exploratory Development Total ------------------- ------------------- ------------------ Gross Net Gross Net Gross Net Oil wells 10 7.0 30 14.3 40 21.3 Gas wells 5 2.8 147 126.8 152 129.6 Dry holes 4 4.0 15 10.8 19 14.8 Total 19 13.8 192 151.9 211 165.7
In 2005, we plan to drill, complete and tie-in 70 net wells including 32 net wells in Nevis, 5 net wells in Chain, with the remaining activity occurring throughout the various areas. 24 PRODUCTION ESTIMATES The following table sets out the volume of our production estimated for the year ended December 31, 2005 reflected in the estimate of future net revenue disclosed in the tables contained under "Disclosure of Reserves Data".
Light and Natural Gas Medium Oil Heavy Oil Natural Gas Liquids BOE (bbls/d) (bbls/d) (Mcf/d) (bbls/d) (boe/d) -------- -------- ------- -------- ------- Proved Developed Producing 4,839 699 81,419 1,279 20,387 Developed Non-Producing 328 - 2,219 46 745 Undeveloped 799 - 4,028 66 1,535 Total Proved 5,966 699 87,666 1,391 22,667 Probable 720 27 5,463 106 1,763 Total Proved Plus Probable 6,686 726 93,129 1,497 24,430
PRODUCTION HISTORY The following tables summarize certain information in respect of production, prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:
Quarter Ended -------------------------------------------------------------------- 2004 -------------------------------------------------------------------- Dec. 31 Sept. 30 Jun. 30 Mar. 31 ------- -------- ------- ------- Average Daily Production(1) Crude oil and NGLs (bbls/d) 6,815 3,550 3,106 2,841 Natural gas (Mcf/d) 84,336 75,425 73,283 75,649 Combined (boe/d) 20,871 16,121 15,320 15,449 Average Net Prices Received(2) Crude oil and NGLs ($/bbl) 47.05 51.20 45.36 40.93 Natural gas ($/Mcf) 6.09 5.76 6.20 6.28 Royalties(3)(5) Crude oil and NGLs ($/bbl) 8.28 8.15 7.22 6.10 Natural gas ($/Mcf) 1.34 1.22 1.28 1.30 Combined ($/boe) 8.12 7.49 7.59 7.51 Operating Expenses(4)(5) Crude oil and NGLs ($/bbl) 8.87 8.33 6.59 7.57 Natural gas ($/Mcf) 0.97 0.93 0.95 0.92 Combined ($/boe) 6.81 6.19 5.90 5.92 Netback Received(6) Crude oil and NGLs ($/bbl) 29.90 34.72 31.55 27.26 Natural gas ($/Mcf) 3.78 3.61 3.97 4.06 Combined ($/boe) 25.03 24.56 25.38 24.86
Notes: (1) Before deduction of royalties. (2) Production prices are net of costs to transport the product to market and net of realized hedging gains and losses. (3) Royalties are net of ARC. (4) This figure includes all field operating expenses. 25 (5) We do 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 and natural gas 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 our approximate exit daily production from our important fields at December 31, 2004: Natural Gas Crude Oil & NGLs Total Properties (Mcf/d) (bbls/d) (boe/d) ------------------------------------------------------------------------------ Medicine Hat 22,296 - 3,716 Sunset 8,196 400 1,766 Bantry 9,540 50 1,640 Nevis 3,540 960 1,550 Shouldice 5,790 60 1,025 Brazeau River 4,218 320 1,023 ------------------------------------------------------------------------------ Major Properties 53,580 1,790 10,720 Other 39,420 5,710 12,280 ------------------------------------------------------------------------------ TOTAL 93,000 7,500 23,000 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 Sproule Report are based on 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. "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: 26 (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 our interest in production and reserves, our "Trust gross reserves", which are our 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 we have an interest; and (c) in relation to properties, the total area of properties in which we have an interest. "NET" means: (a) in relation to our interest in production and reserves, our interest (operating and non-operating) share after deduction of royalties obligations, plus our royalty interest in production or reserves; (b) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and (c) in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest owned by us. 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 on: 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. (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. 27 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. MARKETING Our crude oil and natural gas production is primarily sold through marketing companies at current market prices. These contracts are generally for less than a year and are cancellable on 30 days notice. Approximately 23% of our natural gas production is sold to aggregators who accumulate production from various producers and market the gas on behalf of the group. Such contracts are reserve specific and continue for the life of production from the specified reserves. CYCLICAL AND SEASONAL IMPACT OF INDUSTRY Our operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse effect on our financial condition. We mitigate such price risk through closely monitoring the various commodity markets and establishing hedging programs, as deemed necessary, to provide stability to Unitholders' cash distributions and lock-in high netbacks on production volumes. See "Other Oil and Gas Information - Forward Contracts" for our current hedging program. 28 RENEGOTIATION OR TERMINATION OF CONTRACTS As at the date hereof, we do not anticipate that any aspect of our business will be materially affected in the remainder of 2005 by the renegotiation or termination of contracts or subcontracts. ENVIRONMENTAL CONSIDERATIONS We are pro-active in our approach to environment concerns. Procedures are in place to ensure that the utmost care is taken in the day-to-day management of our oil and gas properties. All government regulations and procedures are followed in strict adherence to the law. We believe in well abandonment and site restoration in a timely manner to ensure minimal damage to the environment and lower overall costs to us. COMPETITIVE CONDITIONS We are a member of the petroleum industry, which is highly competitive at all levels. We compete with other companies for all of our business inputs, including exploitation and development prospects, access to commodity markets, acquisition opportunities, available capital and staffing. We strive to be competitive by maintaining a strong financial condition and by utilizing current technologies to enhance exploitation, development and operational activities. HUMAN RESOURCES As at December 31, 2004, we employ 77 full-time employees, all of which are located in the head office and 15 consultants. 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 December 31, 2004, 49,674,783 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 two classes, as follows: (i) 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) "special voting units", which shall be issued to a trustee and which are entitled to such number of votes at meetings of 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 AOG's board of directors. As at the date hereof there is one special voting unit outstanding. The special voting unit gives 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 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 on liquidation, is fully paid and non assessable and entitles the holder thereof to one vote at all meetings of Unitholders for each Trust Unit held. The Trust Units do not represent a traditional investment and should not be viewed by investors as "shares" in either AOG or the Trust. Corporate law does not govern the Trust and the rights of Unitholders. As holders of Trust Units in the Trust, the 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 rights of Unitholders are specifically set forth in the Trust Indenture. In addition, trusts are not defined as recognized entities within the definitions of legislation such as the Bankruptcy and Insolvency Act (Canada) and the Companies' Creditors Arrangement Act (Canada). As a result, in the event of an insolvency or restructuring, a Unitholder's position as such may be quite different than that of a shareholder of a corporation. 29 The price per Trust Unit is a function of anticipated distributable income from AOG and the combined ability of AOG's board of directors and the Manager 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, commodity prices and our ability to acquire additional assets. Changes in market conditions may adversely affect the trading price of the Trust Units. A return on an investment in the Trust is not comparable to the return on an investment in a fixed-income security. The recovery of an initial investment in the Trust is at risk, and the anticipated return on such investment is based on many performance assumptions. Although the Trust intends to make distributions of its available cash to holders of Trust Units, these cash distributions may be reduced or suspended. The actual amount distributed will depend on numerous factors including: the financial performance of AOG, debt obligations, working capital requirements and future capital requirements. In addition, the market value of the Trust Units may decline if the Trust's cash distributions decline in the future, and that market value decline may be material. It is important for an investor to consider the particular risk factors that may affect the industry in which it is investing, and therefore the stability of the distributions that it receives. See "Risk Factors". The after-tax return from an investment in Trust Units to Unitholders subject to Canadian income tax can be made up of both a return on capital and a return of capital. That composition may change over time, thus affecting an investor's after-tax return. Returns on capital are generally taxed as ordinary income in the hands of a Unitholder. Returns of capital are generally tax-deferred (and reduce the Unitholder's cost base in the Trust Unit for tax purposes). EXCHANGEABLE SHARES As at December 31, 2004, AOG had 1,450,030 Exchangeable Shares outstanding. The Exchangeable Shares were issued in connection with our acquisition of Defiant. Each Exchangeable Share is exchangeable for Trust Units at any time (subject to the provisions of the Voting and Exchange Trust Agreement), on the basis of the applicable exchange ratio in effect at that time, in accordance with the share provisions applicable to such shares and the terms and provisions of the Voting and Exchange Trust Agreement. The exchange ratio was initially equal to one upon issuance of the Exchangeable Shares and will increase on each date that a distribution is paid by us on the Trust Units. The exchange ratio will decrease on each record date for the payment of dividends on the Exchangeable Shares. The holders of Exchangeable Shares are not entitled to any vote at meetings of shareholders of AOG but are, through the Special Voting Unit of Advantage held by the Trustee as trustee under the Voting and Exchange Trust Agreement, entitled to vote (on the basis of the number of votes equal to the number of Trust Units into which the Exchangeable Shares are then exchangeable) with the holders of Trust Units as a class. In addition, holders are provided with all information sent by us to Unitholders. Holders of Exchangeable Shares will be entitled to receive, as and when declared by the board of directors of AOG in its sole discretion from time to time, such cash dividends as may be declared thereon by the board of directors. It is not anticipated that dividends will be declared or paid on the Exchangeable Shares. The Exchangeable Shares will be redeemable by AOG, in certain circumstances, and will be retractable by holders of Exchangeable Shares, in certain circumstances. Exchangeable Shares not previously redeemed or retracted will be redeemed by AOG or purchased by us on January 15, 2008. 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 our 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 our assets. Pursuant to the Trust Indenture, we 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 us must contain a provision to the effect that such obligation will not be binding upon our Unitholders personally. Notwithstanding the terms of the Trust Indenture, Unitholders may not be protected from our liabilities 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 30 possibly certain other statutory liabilities. The possibility of any personal liability to Unitholders of this nature arising is considered unlikely in view of the fact that our sole business activity 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. Our business and that of our 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 our Unitholders for claims against us, including obtaining appropriate insurance, where available, for the operations of AOG and having written agreements, signed by or on our behalf, include a provision that such obligations are not binding upon our 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 of AOG determines. The Trust Indenture also provides that immediately after any PRO RATA distribution of Trust Units to all 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. 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 Notes, royalty income from the Royalty, dividends on or in respect of shares of AOG received by us and income from the Permitted Investments; less: (i) our administrative expenses and other obligations; and (ii) amounts which may be paid by us 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 us 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 we do 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. We derive interest income from our holdings of the Notes. It is expected that our 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 of AOG intends for the Trust to make monthly cash distributions. Cash distributions will be made monthly to the 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 us of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requesting redemption. Upon our receipt of the redemption request, 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. 31 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. The aggregate Redemption Price payable by us 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 Unitholders to receive cash upon the redemption of their Trust Units is subject to the limitations that: (i) the total amount payable by us 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 Long Term 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 Long Term Notes will be distributed and where the number of Long Term Notes to be received by a Trust Unitholder includes a fraction, such number shall be rounded to the next lowest whole number. We shall be entitled to all interest paid, or accrued and unpaid, on the Long Term Notes on or before the date of the distribution IN SPECIE. If we do not hold Long Term Notes having a sufficient principal amount outstanding to effect such payment, we will be entitled to create and, subject to any applicable regulatory approvals, issue in satisfaction of the Redemption Price our own debt securities (the "REDEMPTION NOTES") having terms and conditions substantially the same as the Long Term Notes, and with recourse of the holder limited to our assets. Holders of such Long Term 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". Long Term 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. Long Term Notes or Redemption Notes which may be distributed IN SPECIE to Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such Long Term Notes or Redemption Notes. MEETINGS OF UNITHOLDERS The Trust Indenture provides that meetings of Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of our auditors, 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 our assets in their entirety or substantially in their entirety (other than as part of an internal 32 reorganization), the termination of the Trust and the direction of the Trustee as to the selection of the directors of AOG. Meetings of Unitholders will be called and held annually for, among other things, the election of the Trustee, the appointment of our auditors, and the direction of the Trustee as to the selection of the directors of AOG. A resolution appointing or removing a Trustee, our auditors, 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 Unitholders. The balance of the foregoing matters must be passed by at least 66?% of the votes cast at a meeting of Unitholders called for such purpose. A meeting of 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. Unitholders may attend and vote at all meetings of 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 Unitholders. The next annual and special meeting of Unitholders is scheduled for April 27, 2005. INFORMATION AND REPORTS We will furnish to 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 Unitholders' tax returns under the Tax Act and equivalent provincial legislation. Prior to each meeting of Unitholders, the Trustee will provide the 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 of AOG will ensure that AOG provides us with proper disclosure as to its business and financial operations and sufficient information and materials on a timely basis to allow us to meet our public reporting requirements. With respect to material changes, the board of directors of AOG will ensure that AOG provides timely disclosure to us 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 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 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 Unitholders. The Trustee is reappointed or changed every year as may be determined by a majority of the votes cast at a meeting of our Unitholders. The Trustee may resign upon 60 days' notice to us. The Trustee may also be removed by special resolution of our Unitholders. Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee. 33 DELEGATION OF AUTHORITY, ADMINISTRATION AND TRUST GOVERNANCE The board of directors of AOG has generally been delegated our significant management decisions 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 of AOG responsibility for any and all matters relating to, among other things: (a) any offering of our securities, 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) our acquisition of Permitted Investments and Subsequent Investments and the negotiation of agreements respecting Subsequent Investments; (g) maintaining our books and records and providing timely reports to Unitholders; (h) our financial statements and the financial statements of AOG; (i) the continued listing of our Trust Units on any exchange and to maintain our 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. Unitholders are entitled to elect a majority of the board of directors of AOG pursuant to the terms of the Shareholder Agreement. Subject to the ultimate authority of the board of directors of AOG, AOG and the Trust will be managed by the Manager. For more information as to the board of directors of AOG, see "Additional Information Respecting Advantage Oil & Gas Ltd. - Management of AOG". DECISION-MAKING Although the Manager will provide certain advisory and management services to us pursuant to the Management Agreement, the board of directors of AOG will supervise the management of our business and affairs, including our business and affairs 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 of AOG. In addition, the Trustee has delegated certain matters to the board of directors of AOG, 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 we are a party will require the approval of the board of directors of AOG on our behalf. The board of directors of AOG 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 34 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 our Unitholders called for such purpose. The Trustee may, without the approval of the 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 we 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 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 Unitholders; 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. 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 our assets in their entirety or substantially in their entirety, except as part of an internal reorganization of the our assets as approved by the board of directors of AOG, requires approval by at least 66?% of the votes cast at a meeting of the 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 us which represents more than 51% of the Trust Fund, except as part of a reorganization of AOG and any one or more of our directly or indirectly owned subsidiaries without the approval of at least 66?% of the votes cast at a meeting of the Unitholders called for such purpose. ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD. MANAGEMENT OF AOG Pursuant to the Shareholder Agreement, the board of directors of AOG ("BOARD OF DIRECTORS") is comprised of not more than nine nor less than five members. 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. 35 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.
Number of Trust Units Beneficially Position Held and Owned or Name and Period Served as Controlled as at Municipality of Residence a Director(4)(5) Principal Occupations During Past Five Years February 15, 2005 ------------------------- ---------------- ---------------------------------------------------------- ----------------- Gary F. Bourgeois Vice President, Vice President, Corporate Development of AOG since 373,774 (0.66%) Toronto, Ontario Corporate May 24, 2001. Vice President of the Manager since March Development and 2001. Prior thereto, Managing Director of the EnerPlus Director since Group of Companies, which companies specialize in May 24, 2001 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 President, Chief President and Chief Executive Officer of AOG since 582,375 (1.02%) Calgary, Alberta Executive Officer May 24, 2001. President of the Manager since March and Director 2001. Prior thereto, Senior Vice President (1997-2001) since May 24, 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(2)(3) Director since Chairman of Navigo Energy Inc. since December 2003. As 38,811 (0.07%) Calgary, Alberta September 25, of December 29, 2003, Navigo Energy Inc. became a 1998(6) 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 Since May 24, 2001, a self-employed businessman. Prior 316,101 (0.56%) Victoria, British Columbia December 31, thereto, Vice President, Business Development of Search 1996(6) Energy Corp. Carol Pennycook(2) Director since Partner at the Toronto office of Davies Ward Phillips & 3,000 (0.01%) Toronto, Ontario May 26, 2004 Vineberg, LLP, a national law firm.
36
Number of Trust Units Beneficially Position Held and Owned or Name and Period Served as Controlled as at Municipality of Residence a Director(4)(5) Principal Occupations During Past Five Years February 15, 2005 ------------------------- ---------------- ---------------------------------------------------------- ----------------- Steven Sharpe(1)(2) Director since Managing Partner of Blair Franklin Capital Partners Inc., 8,225 (0.01%) Toronto, Ontario May 24, 2001 and an investment banking firm since May, 2003. Prior Non-Executive thereto, Mr. Sharpe was the Managing Director of The EBS Chairman since Corporation, a management and strategic consulting firm, May 26, 2004 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)(7) Director since President of Tourigny Management Ltd., a private oil and Nil Calgary, Alberta December 31, gas consulting company. 1996(6) Lamont Tolley(1)(3) Director since President and Chief Executive Officer of Rally Energy Nil Calgary, Alberta May 24, 2001 Corp. since July 27, 2004. Prior thereto, independent businessman who has been active in the oil and gas industry for 20 years. He is also 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 Senior Vice President of AOG since June 2001. Vice 373,085 (0.66%) Calgary, Alberta President President 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 Chief Financial Officer of AOG since January 2003. Prior 69,495 (0.12%) Calgary, Alberta Officer and thereto, Controller of AOG since December 1999. Prior Controller thereto, Manager of Financial Reporting with Numac Energy Inc. Richard Mazurkewich Vice President, Vice President, Operations of AOG since August 2001. 182,814 (0.32%) Calgary, Alberta Operations Prior thereto, Manager, Production and Facilities of AOG since March 1998. Prior thereto, Production Engineer with Canadian Natural Resources Limited. Weldon Kary Vice President, Vice President, Exploitation since February 14, 2005. 78,514 (0.14%) Calgary, Alberta Exploitation Prior thereto, with AOG since May 23, 2001, most recently as Manager, Geology and Geophysics. Prior thereto, Exploration Manager at Palliser Energy Corp. when Palliser was purchased by Search Energy Corp, the predecessor entity of AOG.
37
Number of Trust Units Beneficially Position Held and Owned or Name and Period Served as Controlled as at Municipality of Residence a Director(4)(5) Principal Occupations During Past Five Years February 15, 2005 ------------------------- ---------------- ---------------------------------------------------------- ----------------- Anthony Coombs Controller Controller since September 1, 2004. Prior thereto with 7,258 (0.01%) Calgary, Alberta AOG since May 23, 2001, most recently as Chief Accountant. Prior thereto, Chief Accountant for Search Energy Corp., the predecessor entity of Advantage. Jay P. Reid Corporate Partner, Burnet, Duckworth & Palmer LLP, a Calgary-based 6,000 (0.01%) Calgary, Alberta Secretary law firm.
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) 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. (6) 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 these directors were appointed directors of post-Reorganization Search on May 24, 2001. (7) 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. As at February 15, 2005, the directors and executive officers of AOG, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 2,039,452 Trust Units, or approximately 3.6% of the issued and outstanding Trust Units. CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS Except as disclosed above, no director or officer of Advantage, or a shareholder holding a sufficient number of securities of Advantage to affect materially the control of Advantage is, or within the last ten years has been, a director or officer of any reporting issuer that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied us access to any statutory exemption for a period of more than 30 consecutive days or, within a year of such person ceasing to act in that capacity or within the 10 years prior to the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that person. No director or officer of Advantage, or a shareholder holding a sufficient number of securities of Advantage to affect materially the control of Advantage, has been subject to any penalties or sanctions under securities legislation or by a 38 securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision. DISTRIBUTION POLICY It is anticipated that income we receive 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 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, Preferred Shares and Exchangeable Shares. We are the sole holder of the issued and outstanding Common Shares. There are no Non-Voting Shares or Preferred Shares issued and outstanding. We are 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, Exchangeable 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. 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. EXCHANGEABLE SHARES As at December 31, 2004, AOG had 1,450,030 Exchangeable Shares outstanding. The Exchangeable Shares were issued in connection with our acquisition of Defiant. Each Exchangeable Share is exchangeable for Trust Units at any time (subject to the provisions of the Voting and Exchange Trust Agreement), on the basis of the applicable exchange ratio in effect at that time, in accordance with the share provisions applicable to such shares and the terms and provisions of the Voting and Exchange Trust Agreement. The exchange ratio was initially equal to one upon issuance of the Exchangeable 39 Shares and will increase on each date that a distribution is paid by us on the Trust Units. The exchange ratio will decrease on each record date for the payment of dividends on the Exchangeable Shares. The holders of Exchangeable Shares are not entitled to any vote at meetings of shareholders of AOG but are, through the Special Voting Unit of Advantage held by the Trustee as trustee under the Voting and Exchange Trust Agreement, entitled to vote (on the basis of the number of votes equal to the number of Trust Units into which the Exchangeable Shares are then exchangeable) with the holders of Trust Units as a class. In addition, holders are provided with all information sent by us to Unitholders. Holders of Exchangeable Shares will be entitled to receive, as and when declared by the board of directors of AOG in its sole discretion from time to time, such cash dividends as may be declared thereon by the board of directors. It is not anticipated that dividends will be declared or paid on the Exchangeable Shares. The Exchangeable Shares will be redeemable by AOG, in certain circumstances, and will be retractable by holders of Exchangeable Shares, in certain circumstances. Exchangeable Shares not previously redeemed or retracted will be redeemed by AOG or purchased by us on January 15, 2008. NOTES The following is a summary of the material attributes and characteristics of the Notes. This summary does not purport to be complete and is qualified in its entirety by reference to the provisions of the Note Indentures, pursuant to which the Notes are issued. PAYMENT UPON MATURITY On maturity and subject to any applicable subordination restrictions, AOG will repay the indebtedness represented by the Notes by paying to the Note Trustee, in lawful money of Canada, an amount equal to the principal amount of the outstanding Notes, together with accrued and unpaid interest thereon. 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 Notes will be subordinated in right of payment, as set forth in the Note Indentures, 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 Note Indentures; 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 Note Indentures; 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 Notes. The Note Indentures provide 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 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. In the event of any creditor proceedings, the indebtedness represented by the 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 Notes in respect of any restructuring or arrangement proposal regarding AOG. DEFAULT The Note Indentures provides that any of the following shall constitute an "Event of Default": (i) default in payment of the principal of the Notes when the same becomes due; (ii) the failure to pay the interest obligations of the Notes for a period of 12 months; (iii) default on any indebtedness exceeding $10,000,000; (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 40 condition of the 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 the Note Indentures, 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 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 Notes (or other securities of AOG) agrees to be bound by the provisions of the subordination agreements. LONG TERM NOTES The aggregate principal amount of Long Term Notes as at December 31, 2004 was $475,312,732. The Long Term Notes mature on December 31, 2031. The Long Term Notes consist of a series of notes, which as at the date hereof, includes Long Term Notes bearing interest at a rate of 14% and 12.5% 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 Long Term Notes are payable in lawful money of Canada. The Long Term Notes are issuable only as fully-registered notes in minimum denominations of $100.00 and integral multiples of $1.00. REDEMPTION OF LONG TERM NOTES The Long Term 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 Long Term Note Indenture, where the Board of Directors believe the indebtedness represented by the Long Term 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. MEDIUM TERM NOTES The original aggregate principal amount of Medium Term Notes was $259,200,000 ("ORIGINAL PRINCIPAL AMOUNT") and the aggregate principal amount of the Medium Term Notes as at December 31, 2004 was $207,624,757. The Medium Term Notes consist of a series of notes, which as of December 31, 2004, includes Medium Term Notes bearing interest at rates between 7.75% and 10.375% per annum, payable twice annually, and maturing between December 31, 2012 and December 21, 2015. The principal and interest on the Medium Term Notes are payable in lawful money of Canada. The Medium Term Notes are issuable only as fully-registered notes in minimum denominations of $100.00 and integral multiples of $1.00. PRINCIPAL REPAYMENTS AND REDEMPTION OF MEDIUM TERM NOTES From time to time and in any event not less frequently than each anniversary of December 31, 2004, AOG shall make principal repayments on the Notes in an aggregate amount equal to not less than 5% of the Original Principal Amount (and, if applicable, the aggregate principal amount of any additional Notes issued under the Medium Term Note Indenture in excess of the Original Principal Amount (the "SUPPLEMENTAL PRINCIPAL AMOUNT")), provided, however that during the period commencing on September 30, 2004 and ending on December 31 of the year ended five years before the Maturity Date, AOG shall make, in aggregate, principal payments on the Notes in an amount equal to not less than 50% of the Original Principal Amount. In the event that, at any time during the term of this Indenture, a Supplemental Principal Amount is outstanding, during the period commencing with the issue date of the Notes relating to the Supplemental Principal Amount and ending five years from such issue date, AOG shall make principal payments on the Notes relating to the Supplemental Principal Amount in an aggregate amount equal to not less than 50% of the Supplemental Principal Amount. In the event that AOG makes principal repayments on the Notes pursuant to this section of the Medium Note Indenture and there is more than one holder thereof, such principal prepayments shall be made as near as may be pro rata as between the holders and without discrimination or preference, based upon the aggregate principal amount of Notes held by them (rounded, if necessary, to the nearest One Dollar ($1.00)). 41 THE ROYALTY AGREEMENT Pursuant to the Royalty Agreement, AOG has granted to us 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 we are not entitled to take our share of production in kind or to separately sell or market our 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 us and our 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 $2 million, AOG's board of directors is required to approve such disposition. SHAREHOLDER AGREEMENT Pursuant to the Shareholder Agreement, prior to us voting our shares in AOG, each Unitholder shall be entitled to vote in respect of the matter on the basis of one vote per Trust Unit held and we shall be required to vote our shares in AOG in accordance with the result of the vote of 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 our auditors. In addition, Unitholders will be entitled to direct us as to how to vote our 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. We will not be entitled, without the direction of Unitholders, to exercise our 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 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 our manager and as manager of AOG. The board of directors of AOG 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 us and of AOG and to assist in making executive decisions which conform to the general policies and general principles previously established by the board of directors of AOG. The Manager will provide executive officers to AOG, subject to the approval of the board of directors of AOG. 42 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 the Toronto, Ontario 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 since Calgary, Alberta and Secretary 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.
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 us and AOG, 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; (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; 43 (f) at least annually, and at other times as requested by the board of directors of AOG, 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 of AOG; (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 us: (a) ensure we comply with our legal obligations, including our continuous disclosure obligations under all applicable securities legislation; (b) provide investor relations services; (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; 44 (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 of AOG will supervise the management of the business and affairs of AOG, including our business and affairs delegated to AOG, and, in particular: 1. significant operational decisions in respect of AOG as identified by the Manager, acting reasonably; and 2. 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 our 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 our behalf, 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 of AOG. 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 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 45 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 AOG 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 us and AOG, 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 45th 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. 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 of AOG) 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. Effective October 4, 2004, such fees are allocated by the Manager, subject to the discretion of the Manager, on the following basis: Manager Operating Fee 66 2/3% Termination Fee 66 2/3% Performance Fee 60% Employees of AOG Operating Fee 33 1/3% Termination Fee 33 1/3% Performance Fee 40% 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 of AOG. The initial term of the Management Agreement was for 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 of AOG 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 ("TERMINATION FEES") equal to the Management Fees paid for the immediately-prior 2 1/2 years shall be payable. 46 In addition, the Manager is entitled to reimbursement, by us 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 AOG 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 us 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 us and AOG 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 they will not do any of the following activities except with prior disclosure to the board of directors of AOG 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 of AOG is first obtained: 1. they will not manage another oil and gas income fund or royalty trust; 2. they will not, without prior approval of us and AOG, acting reasonably, as determined by the board of directors of AOG, 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 us and AOG, acting reasonably, as determined by the board of directors of AOG, 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 us or AOG. 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. CASH DISTRIBUTIONS The following is a summary of the distributions made by us from our inception in May of 2001 to December 31, 2004. 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 47 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 For the 2004 Period Ended Distributions per Unit Payment Date ------------------------- ---------------------- ------------------ January 31 $0.23 February 17, 2004 February 29 0.23 March 15, 2004 March 31 0.23 April 15, 2004 April 30 0.23 May 17, 2004 May 31 0.23 June 15, 2004 June 30 0.23 July 15, 2004 July 31 0.23 August 16, 2004 August 31 0.23 September 15, 2004 September 30 0.23 October 15, 2004 October 31 0.25 November 15, 2004 November 30 0.25 December 15, 2004 December 31 0.25 January 17, 2005 ---- TOTAL $2.82 Note: (1) We announced on January 12, 2005 that a distribution of $0.28 per Trust Unit will be paid on February 15, 2005 to Unitholders of record on the close of business on January 31, 2005. 48 MARKET FOR SECURITIES Our 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. Period High Low Volume ------------------- ------ ----- --------- 2003 ---- First Quarter 15.59 11.80 7,622,480 Second Quarter 16.95 14.15 7,995,072 Third Quarter 17.15 14.92 8,001,055 Fourth Quarter 17.95 15.65 9,684,205 2004 ---- January 18.42 16.80 2,919,734 February 17.90 16.01 3,020,709 March 19.00 17.69 1,726,037 April 19.84 18.80 4,120,250 May 20.08 19.05 3,367,746 June 19.37 17.80 3,169,079 July 19.65 18.63 2,095,637 August 19.70 18.51 3,648,664 September 21.50 19.47 4,872,670 October 22.35 20.46 5,644,564 November 22.05 20.36 7,372,495 December 22.54 20.61 4,164,232 Our 10% Convertible Debentures are listed for trading on the TSX under the symbol "AVN.DB". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 10% Convertible Debentures as reported by the TSX for the periods indicated. Period High Low Volume ------------------- ------ ----- --------- 2003 ---- First Quarter 116.00 102.30 142,516 Second Quarter 126.25 108.00 109,300 Third Quarter 128.22 115.50 44,200 Fourth Quarter 133.01 112.00 35,110 2004 ---- January 136.75 129.50 13,210 February 136.00 121.14 3,380 March 141.00 133.65 1,960 April 147.52 141.53 4,220 May 148.89 141.76 3,100 June 145.00 135.13 3,080 July 147.00 143.54 4,545 August 145.59 139.30 1,971 September 160.00 145.00 6,756 October 166.09 155.02 6,950 November 164.74 156.91 3,565 December 162.39 155.55 290 49 Our 9% Convertible Debentures are listed for trading on the TSX under the symbol "AVN.DB.A". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 9% Convertible Debentures as reported by the TSX for the periods indicated. Period High Low Volume ------------------- ------ ----- --------- 2003 ---- Third Quarter 107.00 102.25 95,305 Fourth Quarter 108.00 101.00 13,160 2004 ---- January 111.00 108.00 9,510 February 110.00 108.50 2,430 March 111.50 109.00 9,720 April 115.50 111.00 56,010 May 118.00 112.07 20,590 June 113.00 101.00 5,870 July 115.00 110.24 5,655 August 114.75 109.00 7,350 September 126.16 115.00 24,200 October 130.35 121.89 8,540 November 128.25 120.00 5,750 December 132.00 113.03 3,870 Our 8.25% Convertible Debentures are listed for trading on the TSX under the symbol "AVN.DB.B". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 8.25% Convertible Debentures as reported by the TSX for the periods indicated. Period High Low Volume ------------------- ------ ----- --------- 2003 ---- Fourth Quarter 108.50 101.50 219,180 2004 ---- January 111.01 107.01 59,740 February 109.25 106.00 21,030 March 112.09 108.25 16,180 April 120.00 113.00 124,940 May 121.25 115.11 53,510 June 117.00 110.12 7,850 July 118.00 114.51 39,390 August 118.70 111.50 28,280 September 130.00 118.35 60,930 October 134.61 125.00 22,680 November 133.00 126.10 34,040 December 135.20 127.00 20,240 50 Our 7.5% Convertible Debentures are listed for trading on the TSX under the symbol "AVN.DB.C". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 7.5% Convertible Debentures as reported by the TSX for the periods indicated. Period High Low Volume ------------------- ------ ----- --------- 2004 ---- September 105.50 101.75 151,840 October 110.00 102.85 64,720 November 109.00 103.55 33,070 December 111.00 105.50 35,990 Our 7.75% Convertible Debentures are listed for trading on the TSX under the symbol "AVN.DB.D". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 7.75% Convertible Debentures as reported by the TSX for the periods indicated. Period High Low Volume ------------------- ------ ----- --------- 2004 ---- September 105.00 101.05 172,990 October 107.00 103.00 35,970 November 107.99 104.25 23,670 December 109.50 104.60 15,550 ESCROWED SECURITIES As at the date hereof, none of our securities are subject to escrow. PAST PROMOTER Advantage Investment Management Ltd. could be considered the promoter of the Trust for the years 2001 and 2002. The Manager holds Nil Trust Units or Nil% of the issued and outstanding Trust Units as at February 15, 2005. 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 our current asset value to which we are a party or in respect of which any of our 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 2004 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 2004, and (ii) as disclosed herein. MATERIAL CONTRACTS Except for contracts entered into by us in the ordinary course of business or otherwise disclosed herein, the only material contracts we entered into 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 51 Indenture and Management Agreement, in addition to Documents Affecting the Rights of Securityholders, are available on our SEDAR profile at WWW.SEDAR.COM. INTEREST OF EXPERTS There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by us during, or related to, our most recently completed financial year other than Sproule Associates Limited, our independent engineering evaluator and KPMG LLP, our auditors. As at the date hereof, none of the principals of Sproule Associates Limited had any registered or beneficial interests, direct or indirect, in any securities or other property of the Corporation or of our associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them. As at March 15, 2005 KPMG LLP and its partners did not hold any registered or beneficial ownership interest, directly or indirectly, in the securities of the Corporation or its associates or 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 associate or affiliate of the Trust except for Mr. Jay Reid, the Corporate Secretary of AOG, who is a partner of Burnet, Duckworth & Palmer LLP, which law firm provides the Trust, AOG and the Manager with legal services. AUDITORS, TRANSFER AGENT AND REGISTRAR Our auditors 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 and Debentures. AUDIT COMMITTEE INFORMATION COMPOSITION OF THE AUDIT COMMITTEE The audit committee of the Company (the "AUDIT COMMITTEE") is comprised of Messrs. Steven Sharpe, Rodger A. Tourigny and Lamont Tolley. The following chart sets out the assessment of each Audit Committee member's independence, financial literacy and relevant educational background and experience supporting such financial literacy. 52
NAME AND MUNICIPALITY OF FINANCIALLY RESIDENT INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE ----------------------------- ----------- ----------- --------------------------------------------------------- Steven Sharpe Yes Yes Mr. Sharpe has an LLB and is currently Managing Partner Toronto, Ontario of Blair Franklin Capital Partners, an investment bank, with Limited Market Dealer and Portfolio Manager registrations. Mr. Sharpe has served as Chairman of the Audit Committee of Altamira Investment Services Ltd. and as a member of the Audit Committee of Foamex International Ltd. and of a number of private not-for-profit companies. Mr. Sharpe practiced law in the area of work-outs and financial restructurings, and advised lenders, bondholders and boards of directors on financial matters. Rodger A. Tourigny Yes Yes Mr. Tourigny has a Bachelor of Commerce and is a Calgary, Alberta Chartered Accountant. He is a director and President of Tourigny Management Ltd., a private company through which he provides consulting services. Mr. Tourigny is also a Corporate Director and Chairman of the Audit Committee of NAV Energy Trust and is a director and member of the Audit Committee of Burmis Energy Inc. and of Caribou Energy Inc., a private oil and gas company. Lamont Tolley Yes Yes Mr. Tolley holds an MBA and is currently President and Calgary, Alberta CEO of Rally Energy Corp. and is serving as a director and member of the Audit Committee of Delphi Energy Corp. He served as an equity analyst and equity portfolio manager for the Sun Life Investment Group, managed two energy royalty trusts, Starcor Energy Royalty Fund and Orion Energy Trust, and has served as an Audit Committee member of several public issuers and private companies.
PRE-APPROVAL OF POLICIES AND PROCEDURES We have adopted polices and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by KPMG LLP as set forth in item 15 of the Audit Committee charter, which is reproduced below under the heading "Audit Committee Charter". The Audit Committee has approved the provision of a specified list of audit and permitted non-audit services that the audit committee believes to be typical, reoccurring or otherwise likely to be provided by KPMG LLP during the current fiscal year. The list of services is sufficiently detailed as to the particular services to be provided to ensure that the audit committee knows precisely what services it is being asked to pre-approve and it is not necessary for any member of management to make a judgment as to whether a proposed service fits within pre-approved services. AUDIT COMMITTEE CHARTER The following is a summary of our Audit Committee charter which was originally approved by the board of directors of AOG on April 30, 2002 and amended in April 2003 and April 2004: 53 PURPOSE The primary function of the Audit Committee is to assist the Board of Directors (the "BOARD OF DIRECTORS" or "BOARD") of Advantage Oil & Gas Ltd. in fulfilling its responsibilities by reviewing: the financial reports and other financial information provided by Advantage Energy Income Fund to any governmental body or the public; the Trust's systems of internal controls regarding finance, accounting, legal compliance and ethics that management and the Board have established; and the Trust's auditing, accounting and financial reporting processes generally. Consistent with this function, the Audit Committee should endeavor to encourage continuous improvement of, and should endeavor to foster adherence to, the Trust's policies, procedures and practices at all levels. The Audit Committee's primary objectives are to: 1. To assist directors meet their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of the Trust and related matters; 2. To provide better communication between directors and external auditors; 3. To enhance the external auditor's independence; 4. To increase the credibility and objectivity of financial reports; and 5. To strengthen the role of the outside directors by facilitating discussions between directors on the Audit Committee, management and external auditors. COMPOSITION The Audit Committee shall be comprised of three or more directors as determined by the Board of Directors, none of whom are members of management of AOG, the Trust or Advantage Investment Management Ltd. and all of whom are "unrelated directors" (as such term is used in the Report of the Toronto Stock Exchange on Corporate Governance in Canada) and "independent" (as such term is used in Multilateral Instrument 52-110 -- Audit Committees ("MI 52-110"). All of the members of the Audit Committee shall be "financially literate". The Board of Directors has adopted the definition for "FINANCIAL LITERACY" used in MI 52-110 which means "the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the issuer's financial statements". Audit Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Trust or an outside consultant. The members of the Audit Committee shall be elected by the Board of Directors at the annual organizational meeting of the Board of Directors and remain as members of the Audit Committee until their successors shall be duly elected and qualified. Unless a Chair is elected by the full Board of Directors, the members of the Audit Committee may designate a Chair by majority vote of the full Audit Committee membership. MEETINGS The Audit Committee shall meet at least four times annually, or more frequently as circumstances dictate. As part of its job to foster open communication, the Audit Committee should meet at least annually with management and the independent auditors in separate executive sessions to discuss any matters that the Audit Committee or each of these groups believe should be discussed privately. In addition, the Audit Committee or at least its Chair should meet with the independent auditors and management quarterly to review the Trust's financials consistent with item 4 below. A quorum for meetings of the Audit Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Audit Committee shall be the same as those governing the Board. RESPONSIBILITIES AND DUTIES To fulfill its responsibilities and duties, the Audit Committee shall endeavor to: 54 DOCUMENTS/REPORTS REVIEW 1. Review and update this Charter periodically, at least annually, as conditions dictate. 2. Review the organization's annual and interim financial statements, MD&A, earnings press releases and any reports or other financial information submitted to any governmental body or the public, including any certification, report, opinion or review rendered by the independent auditors. 3. Review the reports to management prepared by the independent auditors and management's responses. 4. Review with financial management and the independent auditors the quarterly financial statements prior to their filing or prior to the release of earnings. The Chair of the Audit Committee may represent the entire Audit Committee for purposes of this review. 5. Review of significant findings during the year, including the status of previous significant audit recommendations. 6. Periodically assess the adequacy of procedures for the review of corporate disclosure that is derived or extracted from the financial statements. INDEPENDENT AUDITORS 7. Recommend to the Board the external auditors to be nominated for appointment by the unitholders. 8. Recommend to the Board the compensation of the external auditors 9. On an annual basis, the Audit Committee should review and discuss with the auditors all significant relationships the auditors have with the Trust to determine the auditors' independence. 10. Review any material disagreements between management and the independent auditors and review, consider and make a recommendation to the Board regarding any proposed discharge of the auditors when circumstances warrant. 11. When there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change 12. Periodically consult with the independent auditors, without the presence of management, about internal controls and the fullness and accuracy of the organization's financial statements. 13. Review the audit scope and plan of the independent auditor. 14. Oversee the work of the external auditors engaged for the purpose of preparing or issuing an auditor's report or performing other audit, review or attest services for the Trust. 15. Pre-approve the completion of any non-audit services by the external auditors and determine which non-audit services the external auditor is prohibited from providing. The Audit Committee may delegate to one or more members of the Audit Committee authority to pre-approve non-audit services in satisfaction of this requirement and if such delegation occurs, the pre-approval of non-audit services by the Audit Committee member to whom authority has been delegated must be presented to the Audit Committee at its first scheduled meeting following such pre-approval. The Audit Committee shall be entitled to adopt specific policies and procedures for the engagement of non-audit services if: (a) the pre-approval policies and procedures are detailed as to the particular service; (b) the Audit Committee is informed of each non-audit service; and 55 (c) the procedures do not include delegation of the Audit Committee's responsibilities to management. The Audit Committee will satisfy the pre-approval requirement set forth in this paragraph 15 if:: (a) the aggregate amount of all non-audit services that were not pre-approved is reasonably expected to constitute no more than 5% of the total amount of fees paid by the Trust and its subsidiary entities to the auditors during the fiscal year in which the services are provided; (b) the Trust or the subsidiary entity, as the case may be, did not recognize the services as non-audit services at the time of the engagement; and 16. the services are promptly brought to the attention of the Audit Committee and approved, prior to completion of the audit, by the Audit Committee or by one or more of its members to whom authority to grant such approvals has been delegated by the Audit Committee. FINANCIAL REPORTING PROCESSES 17. In consultation with the independent auditors, annually review the integrity of the organization's financial reporting processes, both internal and external. 18. In consultation with the independent auditors, consider annually the quality and appropriateness of the Corporation's accounting principles as applied in its financial reporting. 19. Consider and approve, if appropriate, major changes to the Trust's auditing and accounting principles and practices as suggested by the independent auditors or management. 20. Review risk management policies and procedures of the Trust and AOG (i.e., litigation and insurance). PROCESS IMPROVEMENT 21. Request reporting to the Audit Committee by each of management and the independent auditors of any significant judgments made in the management's preparation of the financial statements and the view of each group as to appropriateness of such judgments. 22. Following completion of the annual audit, review separately with each of management and the independent auditors any significant difficulties encountered during the course of the audit, including any restrictions on the scope of work or access to required information. 23. Review any significant disagreements among management and the independent auditors in connection with the preparation of the financial statements. 24. Review with the independent auditors and management the extent to which changes or improvements in financial or accounting practices, as approved by the Audit Committee, have been implemented. (This review should be conducted at an appropriate time subsequent to implementation of changes or improvements, as decided by the Audit Committee.) 25. Conduct and authorize investigations into any matters brought to the Audit Committee's attention and within the Audit Committee's scope of responsibilities. The Audit Committee shall be empowered to retain and to approve compensation for any independent counsel and other professionals to assist in the conduct of any investigation. 26. Review the systems that identify and manage principal business risks. 27. Establish a procedure for: o the receipt, retention and treatment of complaints received by the Trust and AOG regarding accounting, internal accounting controls or auditing matters; and 56 o the confidential, anonymous submission by employees of the Trust and AOG of concerns regarding questionable accounting or auditing matters. ETHICAL AND LEGAL COMPLIANCE 28. Establish, review and update periodically a Code of Ethical Conduct and ensure that management has established a system to enforce this code. 29. Review management's monitoring of the Trust's compliance with the organization's Ethical Code. 30. In consultation with the auditors, consider the review system established by management regarding the Corporation's financial statements, reports and other financial information disseminated to governmental organizations and the public in the context of the applicable legal requirements. 31. On at least an annual basis, review with the Trust's auditors or counsel, as appropriate, any legal matters that could have a significant impact on the organization's financial statements, the Trust's compliance with applicable laws and regulations and inquiries received from regulators or government agencies. 32. Review with the organization's counsel legal compliance matters including the trading policies of securities. 33. Perform any other activities consistent with this Charter, the Trust's and AOG's by-laws and governing law, as the Audit Committee or the Board of Directors deems necessary or appropriate. AUDIT SERVICE FEES AUDITOR SERVICES FEES The following table discloses fees billed to us by our auditors, KPMG LLP. TYPE OF SERVICE PROVIDED 2004 ------------------------------------------------------------------ --------- Audit Fees (these services included prospectus work and audit or review of financials forming part of $ 244,500 such prospectus) Audit-Related Fees (these services included French translation in connection with 2004 prospectus $ 51,000 offering) Tax Fees (these services included review/completion of tax returns and general tax consultations) $ 26,497 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 renewal annual information form. DEPENDENCE ON AOG We are an open-ended, limited purpose trust which will be entirely dependent upon the operations and assets of AOG through our ownership of the Common Shares, the Notes and the Royalty. Accordingly, the cash distributions to our 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 us may be adversely affected. 57 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 we have 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 us to improve our 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 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 our management are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin. In the future, we may acquire oil and gas properties outside this geographic area. In addition, the Trust Indenture does not limit our activities to oil and gas production and development, and we 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 our future operational and financial conditions being adversely affected. OIL AND NATURAL GAS PRICES The monthly cash distributions we pay 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 us 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. 58 Declines in oil or natural gas prices will have an adverse effect upon our operations, financial condition, reserves and ultimately on our ability to pay distributions to Unitholders. We may manage the risk associated with changes in commodity prices by entering into oil or natural gas price hedges. If we hedge our commodity price exposure, we will forego the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity hedging activities could expose us to losses. To the extent that we engage in risk management activities related to commodity prices, we will be subject to credit risks associated with counterparties with which we contract. Oil prices were relatively high throughout 2004 averaging US$41.43 WTI as compared to an average of US$31.06 WTI in 2003, an increase of 33%. Monthly AECO prices averaged $6.79/Mcf in 2004 as compared to $6.67/Mcf in 2003, an increase of 2%. The monthly AECO price in 2004 ranged from a high of $8.00/Mcf in November to a low of $5.69/Mcf in October. The price of oil and natural gas will fluctuate and price and demand are factors beyond our 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 we may acquire. As well, cash distributions from us will be highly sensitive to the prevailing price of crude oil and natural gas. MARKETING The marketability and price of oil and natural gas that may be acquired or discovered by us will be affected by numerous factors beyond our 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 us 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 of AOG 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 our 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 we use for our 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 us. Any such instance may offset the return on and value of the Trust Units. 59 CHANGES IN ACCOUNTING STANDARDS APPLICABLE TO CONVERTIBLE DEBENTURES On November 3, 2003 the Accounting Standards Board of the Canadian Institute of Chartered Accountants approved a change to the accounting standards applicable to convertible debentures such as those issued by us. The new standard requires 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 are effective for fiscal periods beginning on or after November 1, 2004. DEBT SERVICE AOG has credit facilities in the amount of $310,000,000. 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 us. 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 us or our 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. PRIOR RANKING INDEBTEDNESS; ABSENCE OF COVENANT PROTECTION The Debentures will be subordinate to all Senior Indebtedness and to any indebtedness of our creditors. The payment of principal and interest on the Debentures will be subordinated to the Senior Indebtedness of us and to indebtedness of our trade creditors. The Debentures will also be effectively subordinate to claims of creditors of our subsidiaries except to the extent we are a creditor of such subsidiaries ranking at least pari passu with such other creditors. The Indentures will not limit the ability of us 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 our level of indebtedness, provides operating investment guidelines, mandates the making of distributions and specify the nature of our 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. We are unable to assess the effect, if any, that any such claim would have on our 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 we 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 60 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 our 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 we 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, 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 $US/$Cdn exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar, which occurred in 2004, negatively impacted our net production revenue and may affect the future value of our reserves as determined by independent evaluations at this time. The impact is reduced to the extent that we have engaged in, or in the future will engage in risk management activities related to commodity prices and foreign exchange rates. We will be subject to unfavourable price changes and credit risks associated with the counterparties with which it contracts. We have not entered into any foreign exchange contracts at this time. Variations in interest rates could result in a significant increase in the amount we pay 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 our management team could have a detrimental effect upon us. 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 our properties. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for our properties will vary from estimates and those variations could be material. The reserve and cash flow information contained in this renewal annual information form represent estimates only. Reserves and estimated future net cash flow from our 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: 61 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 our 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. DEPLETION OF RESERVES We have 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 we will be successful in developing or acquiring additional reserves on terms that meet our 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. We currently operate properties that represent approximately 85% of our total daily production. To the extent the operator fails to perform these functions properly or becomes insolvent, revenue may be reduced. ENFORCEMENT OF OPERATING AGREEMENTS Operations of the wells on properties not operated by us 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 us or our Unitholders. As an owner of working interests in 62 properties we do not operate, we 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 the terms of the operating agreements; thus, Unitholders will be dependent upon us, 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 Unitholders. If we cease 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 us and our Unitholders. Tax authorities having jurisdiction over the Trust or the Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practises to the detriment of us or the detriment of our Unitholders. We expect that it will continue to qualify as a mutual fund trust for purposes of the Tax Act. We 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 us and our Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows: o We would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties held by us. 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 We 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 our registration revoked by the Canada Customs and Revenue Agency. In addition, we may take certain measures in the future to the extent it believes necessary to ensure that we maintain our status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units. INVESTMENT ELIGIBILITY We 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. 63 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. Our 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 our value. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and our ability 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 our 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 our assets 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 our assets. ADDITIONAL FINANCING In the normal course of making capital investments to maintain and expand our oil and gas reserves, 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 we issue 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, our ability and AOG's ability to make the necessary capital investments to maintain or expand our 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 64 return on investment through interest payments. Distributions represent a blend of a return of Unitholders' initial investment and a return on Unitholders' initial investment. Unitholders have a limited right to require us 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 Unitholders to liquidate their investments. Long Term Notes or Redemption Notes which may be distributed IN SPECIE to Unitholders in connection with a redemption will not be listed on any stock exchange and no established market is expected to develop for such Long Term Notes or Redemption Notes. Cash redemptions are subject to limitations. See "Additional Information Respecting Advantage Energy Income Fund - Redemption Right". UNITHOLDER LIMITED LIABILITY The Trust Indenture provides that no Trust Unitholder will be subject to any liability in connection with us or our affairs or obligations and, in the event that a court determines that 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 our assets. The Trust Indenture provides that all written instruments signed by or on behalf of us 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 us 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. FUTURE DILUTION One of our objectives is to continually add to our reserves through acquisitions and through development, and because we does not reinvest our cash flow, our success is in part dependent upon our 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 Our 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 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 our information circular for the most recent annual meeting of shareholders that involved the election of directors. Additional financial information is 65 provided in our financial statements and management's discussion and analysis for the year ended December 31, 2004. Documents affecting the rights of securityholders, along with additional information relating to Advantage, may be found on SEDAR at www.sedar.com. SCHEDULE "A" 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, 2004 using forecast prices and costs; and (ii) the related estimated future net revenue; and (iii) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 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 Vice President, Finance and Chief Financial Officer (signed) "RONALD A. MCINTOSH" (signed) "RODGER A. TOURIGNY" Ronald A. McIntosh Rodger A. Tourigny Director Director March 21, 2005 SCHEDULE "B" 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, 2004. The reserves data consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and (ii) the related estimated future net revenue; and (b) (i) proved oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and (ii) the related estimated future net revenue. 2. The reserves data are the responsibility of the 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 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, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Trust's board of directors:
Location of Net Present Value of Future Net Revenue Independent Qualified Reserves (County (before income taxes, 10% discount rate (000's)) Reserves Evaluator or Description and Preparation or Foreign ------------------------------------------------- Auditor Date of Evaluation Report Geographic Area) Audited Evaluated Reviewed Total ------------------------ ---------------------------- ---------------- ------- --------- -------- ----- Sproule Associates Limited Evaluation of the P&NG Canada 75,820 809,274 0 885,094 Reserves of Advantage Energy Income Fund as of December 31, 2004 prepared November 2004 to February 2005
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. 6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after its preparation date. 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 February 17, 2005