EX-99 8 ex99-1form_40f.txt EXHIBIT 99.1 EXHIBIT 99.1 ------------ -------------------------------------------------------------------------------- A D V A N T A G E E N E R G Y I N C O M E F U N D -------------------------------------------------------------------------------- ANNUAL INFORMATION FORM YEAR ENDED DECEMBER 31, 2006 March 21, 2007 ================================================================================ TABLE OF CONTENTS PAGE ---- GLOSSARY OF TERMS...........................................................1 ABBREVIATIONS...............................................................4 CONVERSION..................................................................4 ADVANTAGE ENERGY INCOME FUND................................................6 GENERAL DEVELOPMENT OF THE BUSINESS.........................................7 DESCRIPTION OF OUR BUSINESS AND OPERATIONS..................................9 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION...............11 ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND.............34 ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD..................41 MARKET FOR SECURITIES......................................................48 ESCROWED SECURITIES........................................................52 LEGAL PROCEEDINGS..........................................................52 INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS.................52 MATERIAL CONTRACTS.........................................................52 INTEREST OF EXPERTS........................................................52 AUDITORS, TRANSFER AGENT AND REGISTRAR.....................................53 AUDIT COMMITTEE INFORMATION................................................53 AUDIT COMMITTEE CHARTER....................................................54 AUDIT SERVICE FEES.........................................................59 INDUSTRY CONDITIONS........................................................59 RISK FACTORS...............................................................65 DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE................................................75 ADDITIONAL INFORMATION.....................................................76 SCHEDULES "A" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION "B" - REPORT ON RESERVES DATA GLOSSARY OF TERMS "6.50% DEBENTURES" means 6.50% convertible unsecured subordinated debentures of the Trust due June 30, 2010; "7.50% DEBENTURES" means 7.50% convertible unsecured subordinated debentures of the Trust due October 1, 2009; "7.75% DEBENTURES" means 7.75% convertible unsecured subordinated debentures of the Trust due December 1, 2011; "8.25% DEBENTURES" means 8.25% convertible unsecured subordinated debentures of the Trust due February 1, 2009; "9.00% DEBENTURES" means 9.00% convertible unsecured subordinated debentures of the Trust due August 1, 2008; "10.00% DEBENTURES" means 10.00% convertible unsecured subordinated debentures of the Trust due November 1, 2007; "ADMINISTRATION AGREEMENT" means the agreement entered into between the Trustee and AOG dated as of June 23, 2006 and providing for the administration of the Trust; "ADMINISTRATOR" means AOG; "ADVANTAGE" or "THE TRUST" means Advantage Energy Income Fund, an unincorporated trust formed under the laws of the Province of Alberta pursuant to the Trust Indenture. All references to "ADVANTAGE" or "THE TRUST", unless the context otherwise requires, are references to Advantage and its predecessors and subsidiaries; "ADVANTAGE RU PLAN" means the Advantage restricted unit incentive plan which was implemented in connection with the Arrangement; "AIM" means Advantage Investment Management Ltd., a corporation incorporated under the ABCA and which amalgamated with AOG effective June 23, 2006; "AOG" or the "CORPORATION" means Advantage Oil & Gas Ltd., a corporation incorporated under the ABCA and a wholly-owned subsidiary of the Trust. All references to "AOG", unless the context otherwise requires, are references to Advantage Oil & Gas Ltd. and its predecessors; "AOG BOARD OF DIRECTORS" or "BOARD OF DIRECTORS" means the board of directors of Advantage Oil & Gas Ltd.; "ARRANGEMENT" means the plan of arrangement involving Advantage, AOG, Ketch, Ketch Resources Ltd., Advantage ExchangeCo II Ltd., Advantage Investment Management Ltd., 1231801 Alberta Ltd., Advantage Unitholders and unitholders of Ketch completed on June 23, 2006 whereby each trust unit of Ketch was exchanged for 0.565 of a Trust Unit on a tax-deferred basis in Canada; "DEBENTURES" means, collectively, the 6.50% Debentures, 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; "ESCROW AGREEMENT" means the agreement entered into among Computershare Trust Company of Canada, the Trust and various securityholders dated as of April 24, 2006; "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; "KETCH" means Ketch Resources Trust; 2 "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; "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; "NOON BUYING RATE" means the noon buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York; "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; "NYSE" means the New York Stock Exchange; "OCTOBER 31, 2006 PROPOSALS" means the draft legislation released by the Federal Minister of Finance on December 21, 2006 to implement proposals originally announced on October 31, 2006 to amend the Tax Act to apply a distribution tax on distributions from publicly-traded income trusts, which proposals are described in more detail under the "RISK FACTORS - THE OCTOBER 31, 2006 PROPOSALS"; "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; "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 AOG Board of Directors from time to time): (i) obligations issued or guaranteed by the government of Canada or any province of Canada or any agency or instrumentality thereof; (ii) term deposits, guaranteed investment certificates, certificates of deposit or bankers' acceptances of or guaranteed by any Canadian chartered bank or other financial institutions (including the Trustee and any affiliate of the Trustee) the short-term debt or deposits of which have been rated at least A or the equivalent by Standard & Poor's Corporation, Moody's Investors Service, Inc. or Dominion Bond Rating Service Limited; (iii) commercial paper rated at least A or the equivalent by Dominion Bond Rating Service Limited, in each case maturing within 180 days after the date of acquisition; and (iv) trust units and limited partnership units in trusts and limited partnerships which invest in energy related assets including all types of petroleum and natural gas and energy related assets, and including, without limitation, facilities of any kind, oil sands interests, coal, electricity or power generating assets, and pipeline, gathering, processing and transportation assets; 3 "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; "ROYALTY" means the 99% 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 royalty agreement entered into between AOG and us dated as of June 24, 2006 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; "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; "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; "TRUSTEE" means Computershare Trust Company of Canada or its successor or successors as trustee under the Trust Indenture; "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, May 26, 2004, April 27, 2005, December 13, 2005 and June 23, 2006, pursuant to which Advantage was formed, as the same may be further amended, restated or replaced from time to time; "TRUST UNIT" or "UNIT" means a unit of the Trust, each unit representing an equal undivided beneficial interest therein; "TSX" means the Toronto Stock Exchange; "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; and "U.S." means the United States of America. Words importing the singular number only include the plural, and VICE VERSA, and words importing any gender include all genders. All dollar amounts set forth in this annual information form are in Canadian dollars, except where otherwise indicated. 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 annual information form, and in certain documents incorporated by reference into this 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 annual information form should not be unduly relied upon. These statements speak only as of the date of this annual information form or as of the date specified in the documents incorporated by reference into this annual information form, as the case may be. In particular, this annual information form, and the documents incorporated by reference, contain forward-looking statements pertaining to the following: o 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 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 annual information form and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Except as required by law, 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 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 our wholly-owned oil and natural gas exploitation and development company. 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 company wholly-owned by us. Search and AcquisitionCo amalgamated and continued as "Search Energy Corp.". On July 26, 2001, Search acquired all of the issued and outstanding shares of Due West Resources Inc. ("DUE WEST"). Effective August 1, 2001, Search and Due West 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"), after which Best Pacific assigned all of its assets to AOG and dissolved. On December 2, 2003, AOG acquired all of the issued and outstanding shares of MarkWest Resources Canada Corp. ("MARKWEST"). MarkWest 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 a plan of arrangement involving a combination of cash consideration, Trust Units and Exchangeable Shares of AOG. Effective January 1, 2005, Defiant amalgamated with AOG. Effective February 1, 2006, Advantage ExchangeCo Ltd. amalgamated with AOG. Effective June 23, 2006, Advantage and Ketch completed the Arrangement with the combined entity continuing under the name Advantage Energy Income Fund. See "GENERAL DEVELOPMENT OF THE BUSINESS". Prior to completion of the Arrangement, Advantage Investment Management Ltd. ("AIM") acted as manager of the Trust and of AOG. As part of the Arrangement, Advantage internalized its external management structure and eliminated all related fees by acquiring all of the outstanding shares of AIM for total consideration of $44 million, paid through the issuance of 1,933,208 Trust Units which have been placed in escrow and are releaseable as to one-third on each of the first three anniversaries of the Arrangement. Our head office, the head office of AOG and the registered office of AOG is located at Suite 3100, 150 - 6th Avenue S.W., Calgary, Alberta, T2P 3Y7. 7 OUR ORGANIZATIONAL STRUCTURE The following diagram sets forth our organizational structure as at the date hereof. [ORGANIZATION CHART OMITTED] Notes: (1) The Unitholders own 100% of the Trust. (2) All our operations and management are conducted through AOG. (3) Advantage receives regular monthly payments in accordance with the Royalty Agreement as well as distributions and interest payments from the Advantage Notes. In accordance with the terms of the Trust Indenture, 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. GENERAL DEVELOPMENT OF THE BUSINESS 2004 On September 15, 2004, we completed an issue, by way of short form prospectus, of 3,500,000 Trust Units and $75,000,000 aggregate principal amount of 7.50% convertible unsecured subordinated debentures (the "7.50% DEBENTURES") and $50,000,000 aggregate principal amount of 7.75% convertible unsecured subordinated debentures (the "7.75% DEBENTURES") to partially finance the $186,000,000 (before closing adjustments) acquisition of certain petroleum and natural gas properties and related assets (the "ACQUIRED ASSETS") from Anadarko (the "ASSET ACQUISITION"). The 7.50% Debentures 8 mature on October 1, 2009 and are convertible into Trust Units at a price of $20.25 per Trust Unit. The 7.75% Debentures mature on December 1, 2011 and are convertible into Trust Units at a price of $21.00 per Trust Unit. The Asset Acquisition had an effective date of July 1, 2004. On December 21, 2004, we announced the closing of our acquisition of Defiant (the "DEFIANT ACQUISITION") by way of plan of arrangement under section 193 of the ABCA. Pursuant to the plan of 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. As a result of this transaction, we paid total cash consideration of $34,000,000, issued 3,666,286 Trust Units and issued 1,450,030 AOG exchangeable shares. 2005 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. The net proceeds of the offering were used to pay down debt incurred in the Defiant Acquisition, for our 2005 capital expenditure program and for general corporate purposes. On December 9, 2005, the Trust Units were listed and posted for trading on the New York Stock Exchange (the "NYSE") under the trading symbol "AAV". We believe the listing on the NYSE will result in improved liquidity for all Unitholders, greater access to the U.S. capital markets, and improved cost of capital for future acquisitions. 2006 On March 8, 2006, AOG elected to exercise its redemption right to redeem all of its outstanding exchangeable shares. The redemption price per exchangeable share was satisfied by delivering that number of Trust Units equal to the exchange ratio of 1.22138 in effect on May 9, 2006. During 2006, we issued 127,014 Trust Units for the remaining AOG exchangeable shares. On June 23, 2006 we completed the merger of Advantage and Ketch under the terms of the Arrangement. The merger was accomplished through the exchange of each trust unit of Ketch for 0.565 of a Trust Unit of Advantage and upon completion, Advantage Unitholders owned approximately 65% of the combined trust and Ketch unitholders owed approximately 35%. We negotiated an increase to our credit facilities in June of 2006 and currently have a $600 million credit facility agreement consisting of a $580 million extendible revolving loan facility and a $20 million operating loan facility. The credit facilities are secured by a $1 billion floating charge demand debenture, a general security agreement and a subordination agreement covering all assets and cash flows. On July 24, 2006 we announced that we adopted a Premium Distribution(TM), Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "PLAN"). The Plan commenced with the monthly cash distribution payable on August 15, 2006 to Unitholders who elected to participate and have their monthly distribution obligation settled through the issuance of additional Trust Units at 95% of the average market price (as defined in the Plan). On August 1, 2006 we issued 7,500,000 Trust Units under a short-form prospectus offering at $17.30 per Trust Unit. An additional 1,125,000 Trust Units were issued on August 4, 2006 at $17.30 per Trust Unit upon full exercise of the over-allotment option provided to the underwriters. The net proceeds of the offering of approximately $141.4 million were used to pay down bank indebtedness and to subsequently fund capital and general corporate expenditures. On December 21, 2006 the Federal Minister of Finance released draft legislation to implement the October 31, 2006 Proposals pursuant to which, commencing January 1, 2011 (provided we only experience "normal growth" and no "undue expansion" before then) certain distributions which would have otherwise been taxed as ordinary income generally will be characterized as dividends in addition to being subject to tax at corporate rates at the Trust level. See "RISK FACTORS - CHANGES IN LEGISLATION - THE OCTOBER 31, 2006 PROPOSALS". 9 RECENT DEVELOPMENTS On January 19, 2007, we announced that the cash distribution to be paid on February 15, 2007 to Unitholders of record on January 31, 2007 would be adjusted to $0.15 per Trust Unit from the then current distribution rate of $0.18 per Trust Unit and that the reduction in the monthly distribution rate arose as a result of recent weakness in crude oil and natural gas prices which have been driven by an abnormally mild winter heating season. We have recently completed additional hedging to help protect the Trust's cash flows in 2007. Overall, approximately 46% of our gas is now hedged for the 2007 calendar year at a floor of $7.51/mcf. For the first quarter of 2007, we have secured approximately 58% of our net gas production at an $8.42/mcf floor. For the months of April to October 2007, approximately 54% of our net gas production is hedged at a floor of $7.08/mcf. We have also hedged approximately 14% of our 2007 net crude oil production at an average floor price of US$65.00/bbl. On January 19, 2007, we also announced that the Board of Directors of AOG approved our 2007 capital expenditure budget at between $120 and $145 million. On February 14, 2007 we issued 7,800,000 Trust Units under a short-form prospectus offering at $12.80 per Trust Unit. An additional 800,000 Trust Units were issued on March 7, 2007 at $12.80 per Trust Unit upon exercise of the over-allotment option provided to the underwriters. The net proceeds of the offering of approximately $105 million were used to pay down bank indebtedness and to fund capital and general corporate expenditures. 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 2007 financial year. 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 or AOG 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; 10 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 and Medium Terms Notes and principal repayments, royalty income earned on the Royalty, dividends (if any) received on, and amounts, if any, received on redemption of, Common Shares and Preferred Shares, and income and distributions received from any Permitted Investments after expenses and capital expenditures, any cash redemptions of Trust Units, and other expenditures. See "ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND - CASH DISTRIBUTIONS". ADVANTAGE OIL & GAS LTD. AOG is actively engaged in the business of oil and gas exploration, development, acquisition and production in the provinces of Alberta, British Columbia and Saskatchewan. We employ a strategy to maintain production from AOG's existing production base while focusing capital expenditures on low-risk development opportunities. As a practice, AOG may manage the risk associated with changes in commodity prices by entering into oil or natural gas hedges related only to specific acquisition or project economics. 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. 11 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 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, 2006. The effective date of the Statement is December 31, 2006 and the preparation date of the Statement is March 9, 2007. 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, 2006 contained in a report of Sproule dated March 9, 2007 (the "SPROULE REPORT"). The Reserves Data summarizes our oil, natural gas 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. We 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. IN CERTAIN OF THE TABLES SET FORTH BELOW, THE COLUMNS MAY NOT ADD DUE TO ROUNDING.
RESERVES DATA (CONSTANT PRICES AND COSTS) SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE as of December 31, 2006 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 16,225 14,393 1,912 1,712 251,561 205,905 6,242 4,588 Developed Non-Producing 477 397 0 0 11,479 9,485 241 179 Undeveloped 3,527 2,919 0 0 27,861 22,361 881 653 -------- -------- -------- -------- -------- -------- -------- -------- Total Proved 20,229 17,710 1,912 1,712 290,901 237,751 7,364 5,420 Probable 13,789 11,804 697 605 145,498 116,708 3,830 2,789 -------- -------- -------- -------- -------- -------- -------- -------- Total Proved Plus Probable 34,018 29,514 2,609 2,317 436,399 354,459 11,194 8,210 ======== ======== ======== ======== ======== ======== ======== ========
12
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 1,707,666 1,241,355 1,000,555 850,715 746,990 1,707,666 1,241,355 1,000,555 850,715 746,990 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Producing Developed 55,498 44,779 37,293 31,804 27,622 55,498 44,779 37,293 31,804 27,622 Non-Producing Undeveloped 171,290 125,900 91,452 66,341 47,768 171,290 125,900 91,452 66,341 47,768 Total Proved 1,934,455 1,412,034 1,129,300 948,860 822,380 1,934,455 1,412,034 1,129,300 948,860 822,380 Probable 1,079,108 612,513 409,724 298,503 228,844 1,079,108 612,513 409,724 298,503 228,844 Total Proved Plus Probable 3,013,563 2,024,547 1,539,024 1,247,364 1,051,223 3,013,563 2,024,547 1,539,024 1,247,364 1,051,223 ========= ========= ========= ========= ========= ========= ========= ========= ========= ========= TOTAL FUTURE NET REVENUE (UNDISCOUNTED) as of December 31, 2006 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 3,550,949 555,622 894,772 120,786 39,438 5,878 1,934,453 0 1,934,453 Proved Plus Probable 5,545,136 903,002 1,359,142 216,628 43,331 9,472 3,013,563 0 3,013,563 FUTURE NET REVENUE BY PRODUCTION GROUP as of December 31, 2006 CONSTANT PRICES AND COSTS Future Net Revenue Before Income Taxes (Discounted At 10%/Year) Reserves Category Production Group ($000's) ------------------------------------------------------------------------------------------------------------------------------ Proved Light and Medium Crude Oil (including solution gas and other by-products) 476,825 Heavy Oil (including solution gas and other by-products) 26,750 Natural Gas (including by-products but excluding solution gas from oil wells) 606,603 Proved Plus Probable Light and Medium Crude Oil (including solution gas and other by-products) 691,258 Heavy Oil (including solution gas and other by-products) 35,245 Natural Gas (including by-products but excluding solution gas from oil wells) 792,053
13
RESERVES DATA (FORECAST PRICES AND COSTS) SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE as of December 31, 2006 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 15,949 14,136 1,908 1,709 253,286 207,212 6,252 4,599 Developed Non-Producing 474 394 0 0 11,523 9,526 241 179 Undeveloped 3,513 2,907 0 0 27,970 22,464 881 654 Total Proved 19,935 17,437 1,908 1,709 292,779 239,200 7,375 5,433 Probable 13,586 11,615 688 596 146,566 117,581 3,833 2,795 Total Proved Plus Probable 33,521 29,053 2,596 2,305 439,345 356,781 11,208 8,227 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 2,110,371 1,495,671 1,200,133 1,022,394 901,119 2,110,371 1,495,671 1,200,133 1,022,394 901,119 Producing Developed Non- 70,588 57,401 48,211 41,470 36,325 70,588 57,401 48,211 41,470 36,325 Producing Undeveloped 184,665 146,958 111,997 85,222 65,030 184,665 146,958 111,997 85,222 65,030 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Total Proved 2,365,623 1,700,030 1,360,341 1,149,085 1,002,475 2,365,623 1,700,030 1,360,341 1,149,085 1,002,475 Probable 1,395,502 745,205 489,733 356,741 275,470 1,395,502 745,205 489,733 356,741 275,470 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Total Proved Plus Probable 3,761,127 2,445,236 1,850,073 1,505,824 1,277,946 3,761,127 2,445,236 1,850,073 1,505,824 1,277,946 ========= ========= ========= ========= ========= ========= ========= ========= ========= ========= TOTAL FUTURE NET REVENUE (UNDISCOUNTED) as of December 31, 2006 FORECAST 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 4,426,050 720,559 1,152,517 123,464 58,212 5,675 2,365,623 0 2,365,623 Proved Plus 7,108,931 1,195,238 1,848,496 223,800 70,818 9,453 3,761,127 0 3,761,127 Probable
14
FUTURE NET REVENUE BY PRODUCTION GROUP as of December 31, 2006 FORECAST PRICES AND COSTS Future Net Revenue Before Income Taxes (Discounted At 10%/Year) Reserves Category Production Group ($000's) ------------------------------------------------------------------------------------------------------------------------------ Proved Light and Medium Crude Oil (including solution gas and other by-products) 482,772 Heavy Oil (including solution gas and other by-products) 27,612 Natural Gas (including by-products but excluding solution gas from oil wells) 830,835 Proved Plus Probable Light and Medium Crude Oil (including solution gas and other by-products) 695,661 Heavy Oil (including solution gas and other by-products) 36,151 Natural Gas (including by-products but excluding solution gas from oil wells) 1,097,794
PRICING ASSUMPTIONS The following tables set forth the benchmark reference prices, as at December 31, 2006, reflected in the Reserves Data. These price assumptions were provided to us by Sproule and were Sproule's then current forecasts at the date of the Sproule Report.
SUMMARY OF PRICING ASSUMPTIONS(1) as of December 31, 2006 CONSTANT PRICES AND COSTS Oil ------------------------------------------------ Edmonton Hardisty Natural Gas WTI Par Price Heavy Cromer Medium AECO Gas Pentanes Propanes Cushing 40(degree) 12(degree) 29.3(degree) Price Plus Fob Butanes Fob Fob Field Exchange Oklahoma API API API ($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/$Cdn) ------------- --------- ---------- ---------- ---------- ----------- ---------- ---------- ---------- ---------- Historical (3) 2006 61.05 67.59 40.06 62.45 6.13 71.51 54.00 42.06 0.858
Notes: (1) This summary table identifies benchmark reference pricing schedules that might apply to a REPORTING ISSUER. (2) The exchange rate used to generate the benchmark reference prices in this table. (3) As at December 31. 15
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS(1) as of December 31, 2006 FORECAST PRICES AND COSTS Oil ------------------------------------------------ Natural Pentanes Butantes Propoane Edmonton Hardisty Cromer Gas(1) Plus Fob Fob Fob WTI Par Price Heavy Medium AECO Gas Field Field Field Cushing 40(degree) 12(degree) 29.3(degree) Price Gate Gate Gate Inflation Exchange Oklahoma API API API ($Cdn/ ($Cdn/ ($Cdn/ ($Cdn/ Rates(2) Rate(3) Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) MMbtu) bbl) bbl) bbl) %/Year ($US/$Cdn) --------- --------- ---------- ---------- ---------- -------- -------- -------- -------- --------- ---------- Forecast 2007 65.73 74.10 42.98 63.72 7.72 75.88 55.23 43.94 5.0 0.87 2008 68.82 77.62 45.02 66.75 8.59 79.49 57.85 46.03 4.0 0.87 2009 62.42 70.25 40.74 60.41 7.74 71.94 52.36 41.66 3.0 0.87 2010 58.37 65.56 38.03 56.38 7.55 67.14 48.87 38.88 2.0 0.87 2011 55.20 61.90 35.90 53.24 7.72 63.40 46.14 36.71 2.0 0.87 2012 56.31 63.15 36.63 54.31 7.85 64.67 47.07 37.45 2.0 0.87 2013 57.43 64.42 37.36 55.40 7.99 65.98 48.02 38.21 2.0 0.87 2014 58.58 65.72 38.12 56.52 8.12 67.30 48.98 38.97 2.0 0.87 2015 59.75 67.04 38.88 57.65 8.26 68.66 49.97 39.76 2.0 0.87 Thereafter +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr 0.87
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, including hedging, realized by us for the year ended December 31, 2006, were $6.86/Mcf for natural gas, $64.34/bbl for crude oil, $55.81/bbl for natural gas liquids. 16 RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE RECONCILIATION OF NET RESERVES BY PRINCIPAL PRODUCT TYPE CONSTANT 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 Proved Probable Probable Proved Probable Probable FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) ---------------------- ------ -------- -------- ------ -------- -------- ------ -------- --------- December 31, 2005 13,693 10,124 23,817 1,539 835 2,374 2,772 1,573 4,345 ------ ------ ------ ------ ------ ------ ------ ------ ------ Extensions 33 65 98 0 0 0 127 61 188 Improved Recovery 1,931 1,629 3,560 144 58 202 201 167 368 Technical Revisions 1,758 -313 1,445 304 -272 32 158 -37 121 Discoveries 44 34 78 0 0 0 0 0 0 Acquisitions 2,044 366 2,410 0 0 0 2,711 1,066 3,777 Dispositions 0 0 0 0 0 0 0. 0 0 Economic Factors -137 -101 -238 -31 -16 -47 -69 -40 -109 Production -1,656 0 -1,656 -244 0 -244 -480 0 -480 ------ ------ ------ ------ ------ ------ ------ ------ ------ December 31, 2006 17,710 11,804 29,514 1,712 605 2,317 5,420 2,790 8,210 ====== ====== ====== ====== ====== ====== ====== ====== ====== Natural Gas Oil Equivalent ---------------------------------- ---------------------------------- Net Net Proved Proved Net Net Plus Net Net Plus Proved Probable Probable Proved Probable Probable FACTORS (mmcf) (mmcf) (mmcf) (Mboe) (Mboe) (Mboe) ---------------------- -------- -------- -------- -------- -------- -------- December 31, 2005 165,911 72,030 237,941 45,656 24,537 70,193 Extensions 5,126 3,465 8,591 1,014 704 1,718 Improved Recovery 3,629 2,806 6,435 2,881 2,321 5,202 Technical Revisions 2,620 -1,270 1,349 2,657 -834 1,823 Discoveries 4 7 11 45 35 80 Acquisitions 93,124 41,608 134,732 20,276 8,366 28,642 Dispositions -359 -137 -496 -60 -23 -83 Economic Factors -4,148 -1,800 -5,948 -928 -457 -1,385 Production -28,156 0 -28,156 -7,073 0 -7,073 -------- -------- -------- -------- -------- -------- December 31, 2006 237,751 116,708 354,459 64,468 34,649 99,117 ======= ======= ======= ====== ====== ======
17 RECONCILIATION OF WORKING INTEREST RESERVES BY PRINCIPAL PRODUCT TYPE FORECAST PRICES AND COSTS
Light And Medium Oil Heavy Oil Natural Gas Liquids ----------------------------- ------------------------------- -------------------------------- WI WI WI Proved Proved Proved WI WI Plus WI WI Plus WI WI Plus Proved Probable Probable Proved Probable Probable Proved Probable Probable FACTORS (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) ---------------------- ------ -------- -------- ------ -------- -------- ------ -------- --------- December 31, 2005 15,558 11,913 27,471 1,720 957 2,677 3,747 2,206 5,953 Extensions 40 78 118 0 0 0 174 84 258 Improved Recovery 2,327 1,962 4,289 167 73 240 275 229 504 Technical Revisions 1,747 -626 1,121 342 -326 16 156 -102 54 Discoveries 53 41 94 0 0 0 0 0 0 Acquisitions 2,455 410 2,865 0 0 0 3,741 1,451 5,192 Dispositions 0 0 0 0 0 0 0 0 0 Economic Factors -249 -191 -440 -27 -16 -43 -60 -35 -95 Production -1,996 0 -1,996 -294 0 -294 -658 0 -658 ------- ------- -------- ------ ------- ------- ------ ------ ------ December 31, 2006 19,935 13,586 33,521 1,908 688 2,596 7,375 3,833 11,208 ======= ======= ======== ====== ======= ======= ====== ====== ====== Natural Gas Oil Equivalent ---------------------------------- ---------------------------------- WI WI Proved Proved WI WI Plus WI WI Plus Proved Probable Probable Proved Probable Probable FACTORS (mmcf) (mmcf) (mmcf) (mmcf) (mmcf) (mmcf) ---------------------- -------- -------- -------- -------- -------- -------- December 31, 2005 195,534 88,013 283,547 53,613 29,745 83,358 Extensions 6,420 4,340 10,760 1,284 885 2,169 Improved Recovery 4,536 3,508 8,044 3,525 2,849 6,374 Technical Revisions 4,930 -1,991 2,939 3,068 -1,388 1,680 Discoveries 5 9 14 54 42 96 Acquisitions 119,212 54,244 173,456 26,065 10,901 36,966 Dispositions -392 -149 -541 -65 -25 -90 Economic Factors -3,129 -1,408 -4,537 -858 -476 -1,334 Production -34,337 0 -34,337 -8,670 0 -8,670 -------- ------- ------- ------- -------- -------- December 31, 2006 292,779 146,566 439,345 78,016 42,533 120,549 ======== ======= ======= ======= ======== ========
18 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 2006 ------------------------------------------------------------------------------------------- -------------- Estimated Future Net Revenue at Beginning of Year 1,216,240 Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties -255,063 Net Change in Prices, Production Costs and Royalties Related to Future Production -385,426 Actual Development Costs Incurred During the Period 50,135 Changes in Estimated Future Development Costs -81,336 Extensions and Improved Recovery 76,549 Discoveries 2,148 Acquisitions of Reserves 374,141 Dispositions of Reserves -1,874 Net Change Resulting from Revisions in Quantity Estimates 12,162 Accretion of Discount 121,624 Net Change in Income Taxes 0 - Estimated Future Net Revenue at End of Year 1,129,300 =========
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. The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each by product type, first attributed to us in each of the following financial years.
PROVED UNDEVELOPED RESERVES Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids Year (Mbbl) (Mbbl) (MMcf) (Mbbl) Mboe ---- -------------------- --------- ----------- ------------------- --------- 2004 1,053 0 1,733 181 1,523 2005 319 0 2,529 30 771 2006 1,047 0 10,547 576 3,381 PROBABLE UNDEVELOPED RESERVES Light and Medium Oil Heavy Oil Natural Gas Natural Gas Liquids Year (Mbbl) (Mbbl) (MMcf) (Mbbl) Mboe ---- -------------------- --------- ----------- ------------------- --------- 2004 265 0 1,945 126 715 2005 764 0 11,109 320 2,936 2006 748 0 18,049 572 4,328
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. 19 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.
Constant Prices and Costs Forecast Prices and Costs ($000's) ($000's) ----------------------------------------------------------- ------------------------------ Proved Reserves Proved Plus Probable Reserves Proved Reserves ----------------------- ---------------------------- ------------------------------ Year 0% 10% 0% 10% 0% 10% ------------------- ------- ------- ------- ------- ------- ------- 2007 80,717 77,216 118,930 114,145 80,518 77,013 2008 33,247 28,720 73,086 63,438 31,663 27,370 2009 8,265 6,433 13,905 10,996 7,568 5,892 2010 337 247 9,803 7,201 300 219 Additional years 898 477 8,076 4,850 737 405 Total 123,464 113,093 223,800 200,630 120,786 110,899 ======= ======= ======= ======= ======= =======
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 issuance of 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 Our properties are spread geographically throughout the Western Canadian Sedimentary Basin. This sedimentary basin covers a large portion of the four western Canadian provinces, with the majority of our properties concentrated in Alberta and northeastern British Columbia and in southeast Saskatchewan. These properties produce from a variety of various aged geological formations and reservoirs. We operate over 85% of our properties. This allows us to control the nature and timing of the capital investments necessary to maximize the potential in developing these assets. Our properties can be divided on the broad basis of commodity and of production type. Light or medium gravity oil accounts for 27% of our production and 39% of our reserves. A further 73% of production and 61% of reserves are natural gas. Rates referenced in the following property descriptions are as of December 31, 2006 unless otherwise noted and reserves quoted are as reported in the Sproule Report to December 31, 2006. MARTIN CREEK, BRITISH COLUMBIA The Martin Creek property is located approximately 100 kilometers northwest of Fort St. John, British Columbia and has been producing since 1978. The property is operated with an average 76% overall working interest. This property is in the winter drilling area which requires all drilling, completion and tie in activities to occur essentially between January 1st and the end of March each season. In the last winter program, January 2006, 16 wells averaging 80% working interest were drilled across the property. These wells targeted multiple zones within the Cretaceous including the Bluesky and Gething Formations as well as Triassic reservoirs in the Halfway, Charlie Lake and Baldonnel Formations. Ten of the 16 wells were placed on production and these averaged 6.5 MMcf/d in 2006. Much of the success of the 2006 program was focused in the northern part or the Black - Conroy area of the property. Following up on the 2006 success, 17 wells were drilled in the 2007 program exclusively within Black - Conroy, targeting the Baldonnel and Bluesky Formations which occur at moderate depths between 800 to 1,300 meters. Fifteen of the 17 wells were cased and completed. Eleven have been tied in for production. These wells are stimulated with propped sand fracs in the case of the Bluesky sandstones or with acid squeezes and/or fracs in the case of the Baldonnel carbonates. Tested initial capability from the 2007 winter program is exceeding 12 MMcf/d. Three MMcf/d of new compression was installed during March 2007. With this addition, about half of the new volumes will be able to produce immediately with the remainder coming on stream as pipeline and facility space 20 becomes free with natural production decline. As a result it is expected that we should be able to keep production flat until well into 2008. Total production from the greater Martin Creek, including the Black - Conroy areas is 14.1 MMcf/d. Additional facilities, pipeline and compression options will be scoped for next year to handle subsequent anticipated volumes from current and future drilling programs. The successful 2007 program has set up a great number of locations available for a 2008 drilling program which should be similar in size and expectations to the one just executed. In addition we own a 100% working interest ownership in key facilities, including five compressor stations, one 30 mmcf/d plant and over 254 kilometers of pipelines, which gives us a dominant infrastructure position in this portion of British Columbia. Sproule evaluated our proved reserves in the area and assigned 32.6 bcf of natural gas and 656 Mbbls of crude oil and NGLs. In addition, 22.9 bcf of probable natural gas reserves and 478 Mbbls of probable crude oil and NGLs reserves have been assigned to this property. STODDART/NORTH PINE, BRITISH COLUMBIA The Stoddart/North Pine area lies just 8 kilometers west of the Town of Fort St. John in northeast British Columbia. This area is within the agricultural area and is accessible year round. The area contains multiple producing horizons, predominantly natural gas from the Permian Belloy Formation and oil from the Triassic, Charlie Lake Formation. Historically, 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 North Pine Charlie Lake oil pool. The area includes 12,000 gross (9,176 net) acres of undeveloped land. Current production from this area is 3.0 MMcf/d of natural gas and 174 Bbls/d of light oil and NGLs. Sproule evaluated our proved reserves in the area and assigned 12.5 bcf of natural gas and 900 Mbbls of crude oil and NGLs. In addition, 2.9 bcf of probable natural gas reserves and 175 Mbbls of probable crude oil and NGL reserves have been assigned to this property. FONTAS, ALBERTA The Fontas property is situated in the northwestern corner of Alberta, along the BC border just south of the Rainbow-Zama oilfields. Fontas is a natural gas property which produces principally from Mississippian aged reservoirs in the Debolt, Shunda and Elkton Formations. Gas is trapped as these reservoirs are truncated and preserved beneath Cretaceous silts and shales. In addition Cretaceous Detrital Formation sand channels which were cut into the older Mississippian rock have formed natural gas reservoirs. We operate this winter only access property and have an average 60% working interest. We operate six strategically located gas processing facilities and over 200 kilometers of gas gathering pipelines. Current production from this area is 7.5 Mmcf/d. In the January 2006 winter season, 13 wells were drilled and cased. Nine of these are on production. A winter drilling program was not implemented in 2007, however, drilling plans are being evaluated for a 2008 winter program Sproule evaluated our proved reserves in the area and assigned 14.7 bcf of natural gas. In addition, 6.8 bcf of probable natural gas reserves have been assigned to this property. PEACE RIVER ARCH AREA, ALBERTA WORSLEY/CECIL - These properties are located 150 kilometers north of the City of Grande Prairie, Alberta. The Worsley property is complex geologically with numerous structural and stratigraphic reservoirs ranging from 600 meters to 2,200 meters. The principle reservoirs are the Devonian, Wabamun Formation, Mississippian Kiskatinaw and Debolt Formations and Cretaceous Bluesky and Gething Formations. Often these pools are stacked over deep seated structural features which provide multiple trapping opportunities up the stratigraphic column. These structures must be controlled seismically before drilling. We hold varying interests in approximately 35 sections of land in this area, generally in excess of 50%. Nine wells were drilled on this property in 2006. Seven are on production, one was abandoned and one is suspended. The Cecil area consists of varying interests in 16 sections of land adjacent to Worsley, again with multi-zone, shallow and medium drill depth targets. The principal producing pool is the Charlie Lake JJ Doig Formation pool. We have a 40% working interest in 2 producing wells making collectively making 750 boe/d of primarily 36o API gravity crude oil. We 21 hold a 100% working interest in the seven MMcf/d capacity gas processing facility in Worsley and 10% working interest in a 50 MMcf/d gas processing facility at Cecil. Sproule evaluated our proved reserves in the Cecil/Worsley area and assigned 4 bcf of natural gas and 335 Mbbls of crude oil and NGLs. In addition, 5.2 bcf of probable natural gas reserves and 392 Mbbls of probable crude oil and NGLs reserves have been assigned to this property. BOUNDARY LAKE - This property lies immediately west of the Worsley property just east of the BC/Alberta border. The property consists of 14 sections of land (variable but generally greater than 40% working interest.) In February 2006 one well was successfully drilled and completed into the Triassic, Halfway Formation. This well has been flow lined in but is awaiting EUB approval for startup of facilities to commence producing. Current production from the Boundary Lake property is 0.4 MMcf/d, with an anticipated 2.5 MMcf/d gross (facilities restricted) waiting to come on stream from the new wells. Sproule evaluated our proved reserves in the area and assigned 2.2 bcf of natural gas and 88 Mbbls of crude oil and NGLs. In addition, 1.1 bcf of probable natural gas reserves and 27 Mbbls of probable crude oil and NGL reserves have been assigned to this property. SUNSET/VALLEYVIEW, 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 Triassic "A" Unit, Sunset B, and Valleyview-Stump. All three properties produce from the Triassic Montney Formation. SUNSET A - We have a 70% working interest and operates the Sunset Triassic "A" Unit. Production from the unit is predominantly (32oAPI) oil and has a forty year production history with a very stable performance and very low decline, indicating that there is a lot more oil to be recovered. In 2005, two wells were drilled which evaluated the viability of additional infill drilling in the pool. These wells came onstream at an average rate of 75 bbls/d per well, similar to that in the original wells. An additional 14 oil wells and an injector were added in 2006, with similar results. Current net production from the Sunset A unit is 640 bbls/d of crude oil and 750 Mcf/d of natural gas. An additional 14 locations have been identified with 4 budgeted for drilling in 2007. SUNSET B - Production from this Montney reservoir is predominantly natural gas although there is a thin oil (32oAPI) column. We have a 100% interest in this pool. We own 100% of a sour gas processing plant and gathering system with throughput capacity of 12 MMcf/d. Associated gas from Sunset A and from Valleyview is gathered and streams through this facility. Current production from the Sunset B pool is 1.6 MMcf/d and 98 Bbls/d. No wells were drilled in 2006. VALLEYVIEW - This Montney gas pool is connected to the Sunset B gas processing plant by a twelve kilometer pipeline. We have a 93% average working interest in the pool. One new well was drilled in 2006 and is currently on production. Production from this property is 1.9 MMcf/d. For the three properties, Sunset A, Sunset B and Valleyview, the Sproule Report assigns 14.2 bcf of proven natural gas reserves and 2,287 Mbbls of proven crude oil and NGL reserves to this property. In addition, 16.9 bcf of probable natural gas reserves and 2,525 Mbbls of probable crude oil and NGL reserves have been assigned to this property. NEVIS, ALBERTA The Nevis property is situated 60 km east of Red Deer. Nevis is an operated property consisting of approximately 50 sections of land with an average working interest over 90%. This property produces natural gas from numerous shallow depth horizons (400 to 800 m) including the Horseshoe Canyon, Edmonton, Belly River and Viking formations. Oil and natural gas is produced from the slightly deeper reservoirs (1,200 m) of the Glauconite, Ostacode and Ellerslie formations within the Mannville Group. The main zone of interest however, is an oil and gas reservoir which occurs at 1,600 meters in Devonian aged carbonates of the Big Valley Member of the Wabamun Formation. Development of the sweet oil from this high porosity/low permeability reservoir is being accomplished by horizontal drilling. Crude oil quality ranges between 35o and 42o API. In 2006, through two separate land deals, we added approximately 15 sections of land with Wabamun rights 22 into the property. Drilling in 2007 will focus on areas on these new lands on the west side of the Red Deer River valley. Additional facilities and compression is planned to accommodate expected volumes from drilling on the west side. Oil on the east side is collected at central facilities and trucked to market. The gas is gathered through company owned pipelines and delivered to third party midstream for final processing and sale. Currently, the property is being reviewed to scope the potential for either waterflood or C02 secondary recovery. In 2006, 13 horizontal wells were drilled into the Wabamun formation and are all currently producing. The average first month initial production from these wells is 180 Boe/d. An additional 6 shallow vertical wells were drilled which for Horseshoe Canyon coals and Edmonton and Belly River sands. (The CBM on this property is discussed further under the coal bed Methane section later in this discussion.) Current production from all zones on this property is 2,445 Boe/d. The Sproule Report assigns 20.2 bcf of proven natural gas reserves and 4,256 Mbbls of proven crude oil and NGL reserves to this property. In addition, 7.9 bcf of probable natural gas reserves and 1,573 Mbbls of probable crude oil and NGL reserves have been assigned to this property. GOLDEN SPIKE, ALBERTA The Golden Spike property is located 10 kilometers southwest of Edmonton, Alberta. This area has been a historical oil producing area since the discovery of oil in the Devonian Leduc reefs in the 1940's. Advantage is the operator and holds a 100% Working Interest in all zones above the Leduc Formation. Several wellbores which were originally used for deeper Leduc production, are now used for the uphole productive zones in the Devonian Nisku and Wabamun carbonates and Cretaceous Ellerslie, Glauconite, Viking and Belly River sandstones which are draped over the deeper Leduc structure. The production is primarily gas prone with some light oil opportunities. The area has well established sweet and sour gas processing capacity at competitive midstream operated facilities. Current net production from this property is 418 Boe/d from six wells. The Sproule Report assigns 4.4 bcf of proven natural gas reserves and 304 Mbbls of proven crude oil and NGL reserves to this property. In addition, 1.0 bcf of probable natural gas reserves and 67 Mbbls of probable crude oil and NGL reserves have been assigned to this property. WAINWRIGHT, ALBERTA The Wainwright property is located approximately 175 kilometers southeast of the City of Edmonton. We have varying working interests in this property averaging 85% in approximately 175 sections of land. Current net production from the property is 3.4 Mmcf/d natural gas. 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. No drilling has occurred on this property since 2003. The Sproule Report assigns 7.4 bcf of proven natural gas reserves and 4.4 Mbbls of proven crude oil and NGL reserves to this property. In addition, 1.8 bcf of probable natural gas reserves and 0.2 Mbbls of probable crude oil and NGL reserves have been assigned to this property. SKARO, ALBERTA The Skaro property is located 50 kilometers northeast of Edmonton, Alberta. We operate 11 sections of land with 100% working interest. Production in this area is 25o API gravity oil at depths less than 900 meters. The Skaro property is positioned in a productive Cretaceous Ellerslie channel trend offset by numerous commercial, multi-well oil pools. The Skaro property has the potential for horizontal delineation development drilling through and utilization of existing 3-D seismic data for continued new pool exploration. Current net production from this property is 162 Boe/d. The Sproule Report assigns 273 Mmcf of proven natural gas reserves and 33 Mbbls of proven crude oil and NGL reserves to this property. In addition, 225 Mmcf of probable natural gas reserves and 32 Mbbls of probable crude oil and NGL reserves have been assigned to this property. 23 COAL BED METHANE (CBM) PROJECTS We hold high working interest in several properties along the main coal bed methane fairway of the Horseshoe Canyon Formation which extends in a wide geographical belt straddling the Queen Elizabeth 2 Highway between Calgary and Edmonton. The Horseshoe Canyon Formation bears between 10 and 20 individual coal seams which are fracture stimulated with nitrogen and produce "dry" (no associated water) natural gas. Primary spacing allows for four wells per section in this area. NORTH CHIGWELL CBM We entered into a 50% joint venture with a major CBM company and during 2006, 28 wells were drilled, completed and tied into a dedicated low pressure gathering system. Central compression and a major sales line was constructed which are owned 50%. Current production is 1.7 MMcf/d net to Advantage or about 120 Mcf/d gross per well. After suitable evaluation of this production, this property has the potential by way of EUB application to be downspaced to eight wells per section and double the current well count. CHIGWELL CBM Immediately south of the current North Chigwell CBM joint venture, we hold an approximate 50% working interest and operate in a similar sized lock of land. The synergies provided with the existing facilities and sales line provides a great opportunity to exploit this resource for significant cost reductions from the initial program. Production at North Chigwell will be monitored and along with a favorable gas price window, this property will be considered for development. No budget dollars have been allocated to this property in 2007. NEVIS CBM We hold rights to the Horseshoe Canyon in seven sections (average 47% working interest) of operated lands as well as three non-operated (40%) lands. We have drilled and completed one CBM well on each of six sections of land and has recently installed wellhead compression to allow the wells to produce into our existing higher pressure conventional gathering system. Although not enough time has passed to suitably observe the specific individual well performance it is expected that, based on a statistical average of 200 adjacent third party CBM wells, rates will be significantly higher than at Chigwell. Initial rates of between 200 and 250 Mcf/d are expected. Production from the wells will be observed in 2007 and given favorable production rates and gas prices, a 2008 drilling program could proceed. (Reserves assigned are included in the overall Nevis summary discussed earlier in this section.) CAMROSE CBM The Camrose property is located 25 kilometers southeast of Edmonton, Alberta. We hold a 100% working interest in 22 sections of land. This property is at the north end of the Horseshoe Canyon fairway. As such per well rates are expected only to be in the 75 Mcf/d range. The lands have been farmed-out to a third party that will allow us to participate on a well by well basis based on drilling results. CBM RESERVES: The Sproule Report assigns 5.8 bcf of proven natural gas reserves and 4.9 bcf of probable natural gas reserves to the CBM properties (including those assigned separately at Nevis). WESTEROSE, ALBERTA The Westerose property is approximately 60 kilometers southwest of Edmonton, Alberta. Westerose is and oil and gas property with production from various Cretaceous reservoirs but produces principally from several pools associated with the erosional subcrop edge of the Mississippian Banff Formation. The primary pool is the Banff "C" Oil Unit. We also operate five compressor stations and 80 kilometers of pipeline gathering facilities that are connected to the Keyspan Rimbey gas plant. 24 WESTEROSE SOUTH BANFF "C" OIL UNIT. - We hold a 52% Working Interest in Banff "C" Unit, which has an estimated 28.7 MMbbls of original oil in place. Cumulative production for the unit was 3.7 MMbbls (13% recovery of original oil in place) at December 31, 2006. Sproule has assigned a proved plus probable recovery factor of 35%. The reservoir in the Banff "C" Unit is a dolomitized carbonate that is conducive to secondary recovery through waterflooding based on analogous pools and engineering studies completed on the unit. Waterflood operations commenced in the Banff "C" Oil Unit during 2003 and continued through 2006. Benefits of the waterflood are expected to be realized as we continue to inject water and slowly build up reservoir pressure. Our current voidage replacement ration is 1.3. In the fourth quarter of 2006 we drilled three wells into the Banff "C" unit. The initial production rate from the three new wells is 350 Boe/d. We have plans to drill an additional two wells plus an additional water injector in 2007. The Sproule Report assigns 11.2 bcf of proven natural gas reserves and 3,061 Mbbls of proven crude oil and NGL reserves to the greater Westerose area. In addition, 3.7 bcf of probable natural gas reserves and 1,619 Mbbls of probable crude oil and NGL reserves have been assigned to this property. CHIP LAKE, ALBERTA The Chip Lake property is located 125 kilometers west of the City of Edmonton. The property produces light crude oil (37 degrees API) with associated gas. Production at the end of 2006 is approximately 330 Boe/d. This property was acquired in December 2004 and prior to the acquisition, the previous owner had constructed a central sour oil and water handling facility without appropriate Energy Utilities Board ("EUB") approval. We have been involved in extensive discussion with the EUB and public stakeholders throughout the last two years to rectify and resolve this issue which is expected in 2007. The property will continue to produce from single well batteries under maximum rate limitation allowables until the issues are resolved. Sproule evaluated our proved reserves in the Chip Lake area and assigned 1.6 bcf of natural gas and 1,766 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 1.7 bcf of natural gas and 2,580 Mbbls of crude oil and NGLs. OPEN LAKE (WILLESDEN GREEN) The Willesden Green property is located approximately 35 km north of the Town of Rocky Mountain House. We operate and have in excess of 90% working interest. Oil and natural gas production is multi-zoned from various Cretaceous and Jurassic reservoirs including the Rock Creek, Ellerslie, Ostacode, Viking, Second White Specks and Belly River Formations. We drilled one well targeting the Glauconite and Rock Creek in 2006. This well was placed onstream in the fourth quarter of 2006 and a follow up well has been drilled and is being completed in the first quarter of 2007. In addition three wells were drilled at no cost to Advantage down to the Jurassic Rock Creek Formation on expiring lands. These wells have tested 14 Mmcf/d at very low draw downs. Tie in of these wells is underway and production is expected to commence shortly. We will receive an overriding royalty of 15% on natural gas reserves and we have exposed no capital on the project. Our net production from all zones in this property is 3.7 Mmcf/d natural gas and 475 bbls/d NGLs and crude oil. Sproule evaluated our proved reserves in the Willesden Green area and assigned 6.0 bcf of natural gas and 786 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 2.3 bcf of natural gas and 343 Mbbls of crude oil and NGLs. FERRIER/ O'CHIESE, ALBERTA The Ferrier and O'Chiese areas lie between 75 and 100 kilometers southwest of Edmonton, Alberta. The 20 sections of land in these properties are non-operated with an average working interest of around 40%. This area has high yield natural gas liquids from gas production which occurs at drill depths of 2,000 meters to 3,000 meters within the porous carbonates of the Mississippian aged Elkton and Shunda formations, but principally from the Jurassic Rock Creek and Cretaceous Ellerslie Formations. Some additional production occurs in shallower Cretaceous aged clastic reservoirs as well. In 2006 Advantage participated in the drilling of 5 wells in these areas. Our net production from these properties is 2.4 Mmcf/d of natural gas and 76 Bbls/d of NGLs and crude oil. 25 Sproule evaluated our proved reserves in the Ferrier/O'Chiese area and assigned 2.5 bcf of natural gas and 72 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 0.8 bcf of natural gas and 30 Mbbls of crude oil and NGLs. BRAZEAU RIVER, ALBERTA The Brazeau River property is located approximately 50 km west of the town of Drayton Valley. 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. 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 3.7 MMcf/d natural gas and 305 bbls/d NGLs and crude oil. Sproule evaluated our proved reserves in the Brazeau River area and assigned 2.6 bcf of natural gas and 348 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 2.6 bcf of natural gas and 264 Mbbls of crude oil and NGLs. LOOKOUT BUTTE, ALBERTA The Lookout Butte property is located approximately 90 kilometers southwest of Lethbridge, Alberta. Production occurs primarily from the Mississippian Rundle Formation where natural gas has been trapped in a foothills overthrust structure in front of Waterton Park. We have a 100% working interest in the Rundle gas production. Production began in 1963 and production decline is very shallow at approximately 12% per year. A recently drilled well (2004) in the southern portion of the pool indicates the potential for significant undrained reserves and additional prospective locations targeting the Rundle carbonates. The property includes a 100% operated working interest plant and associated gas gathering system which dehydrates the gas before final processing at Shell's Waterton gas plant. In 2006 a former deep producer was re-completed uphole at 3,250 meters in Cretaceous Mannville Formation sandstones and commenced production in May 2006 and has averaged145 boe/d since. We have a 50% working interest in the Mannville. In some of the older wells, the Cretaceous Cardium sands tested gas rates as high as 1MMcf/d from the shallowest of up to six overthrust repeats of the Cardium zone per well. A new well drilled for the Cardium in Q1 2007 is awaiting completion. We have a 50% working interest in the Cardium intervals. Working interest production from this property from all zones is 5.8 MMcf/d of natural gas and 180 bbls/d of NGLs. Sproule evaluated our proved reserves at Lookout Butte and assigned 31.5 bcf of natural gas and 1,665 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 12 bcf of natural gas and 632 Mbbls of crude oil and NGLs. SOUTHEAST SASKATCHEWAN This area consists of a host of individual properties within the Williston Sedimentary Basin in the southeast corner of Saskatchewan. We operate the majority of this production at 100%. Production at the major properties comes principally from the Ordovician Red River Formation at Midale, Hardy and Froude, Devonian Winnipegosis Formation at Steelman and from Mississippian Midale/Frobisher Formations at Steelman, Weyburn and Workman. In 2006, we drilled two vertical wells at Pinto which have resulted in Midale and Frobisher oil wells. Also one vertical Winnipegosis oil well was added to the Steelman property. One well at each of Hardy, Midale and Froude was re-entered to add an additional horizontal leg or sidetrack. The Workman property is in the process of being unitized and ultimately waterflood. Production from Saskatchewan, all light crude oil, was 1,522 Bbls/d. Sproule evaluated our proved reserves in Southeast Saskatchewan and assigned 314 Mmcf of natural gas and 4,261 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 160 Mmcf of natural gas and 2,607 Mbbls of crude oil and NGLs. 26 SHALLOW GAS PROPERTIES: A significant portion of our production comes from shallow gas properties at Medicine Hat, Bantry, and Shouldice. These projects are all located in southern Alberta and occur between 500 and 1,200 meters of depth. Typical of shallow gas, these properties are resource plays which require a large number of wells to extract the very large in place reserves at relatively low per well production rates. As a result, they have a long production life (long reserve life index or RLI). These reservoirs consist of low permeability strata, requiring fracture stimulation to enhance and induce productivity. The wells are gathered by an extensive network of low pressure pipelines which feed into large central gas compression facilities. All of these properties have been downspaced to allow for multiple gas wells per section. MEDICINE HAT, ALBERTA The Medicine Hat 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 where 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 approximately 5.2 MMcf/d of natural gas. From January 2002 to December 2005, 320 new wells were added. Only 16 wells were drilled in 2006. Year end 2006 production from this property is 13.1 MMcf/d. Sproule evaluated our reserves in the area and assigned 50.9 bcf of proved natural gas reserves and 12.6 bcf of probable reserves. As such, this property is our largest property on an assigned reserves basis. 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. 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. One well was drilled at this property in 2006. Natural gas is gathered into our operated compression and dehydration facilities. Year end net production from this area is 4.5 MMcf/d of natural gas and 25 bbls/d of crude oil and NGLs. The Sproule Report assigns 11 bcf of proven natural gas reserves and 20 Mbbls of proven NGL reserves to this property. In addition, 4.3 bcf of probable natural gas reserves and 7 Mbbls of probable NGL reserves have been assigned to this property. SHOULDICE, ALBERTA The Shouldice area of southern Alberta is located approximately 50 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 in the area. Much of this acreage is downspaced to accommodate additional drilling. Current natural gas production of 3.0 MMcf/d is produced on a co-mingled basis from the Medicine Hat Formation sands with various Belly River Formation sands from approximately 90 wells. No new wells were added in 2006. Both natural gas and crude oil are produced and gathered through our facilities of varying working interests. The Sproule Report assigns 9.2 bcf of proven natural gas reserves and 73 Mbbls of proven crude oil and NGLs to this property. In addition, 2.6 bcf of probable natural gas reserves and 40 Mbbls of probable crude oil and NGL reserves have been assigned to this property. 27 OIL AND GAS WELLS The following table sets forth the number and status of wells as at December 31, 2006 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 794.0 445.2 441.0 237.5 1,468.0 1,143.8 359.0 194.0 British Columbia 5.0 3.4 3.0 0.3 117.0 77.3 45.0 30.5 Saskatchewan 207.0 153.5 86.0 62.7 -- -- -- -- Manitoba 85.0 5.1 -- -- -- -- -- -- ------- ------- ------- ------- ------- ------- ------- ------- Total 1,091.0 607.2 530.0 300.5 1,585.0 1,221.1 404.0 224.5 ======= ======= ======= ======= ======= ======= ======= =======
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, 2006.
Developed Acres Undeveloped Acres Total Acres -------------------------- --------------------------- ------------------------ Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Alberta 907,997 438,611 541,547 260,910 1,449,544 699,521 British Columbia 169,584 72,330 122,835 68,854 292,419 141,184 Saskatchewan 32,978 23,969 94,194 78,413 127,172 102,382 --------- --------- --------- --------- --------- --------- Total 1,110,559 534,910 758,576 408,177 1,869,135 943,087 ========= ========= ========= ========= ========= =========
We expect that rights to explore, develop and exploit 91,109 net acres of our undeveloped land holdings will expire by December 31, 2007. The land expirations do not consider our 2007 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. FORWARD CONTRACTS 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 in recent years. Such prices are primarily determined by economic, and in the case of oil prices, political factors. Supply and demand factors, as well as weather, general economic conditions, and conditions in other oil and natural gas regions of the world also impact prices. Any upward or downward movement in oil and natural gas prices could have an effect on our financial condition, thus impacting the cash distributions made to Unitholders. We have implemented a hedging policy to use costless collars and fixed price swaps to hedge up to 50% of our gross production for a maximum period of 1 1/2 years. These hedging activities could expose us to losses or gains. However, such oil or natural gas price hedges will only be entered into on specific acquisitions and projects. To the extent that we engage in risk management activities related to commodity prices, we will be subject to credit risk associated with the parties with which we contract. This credit risk will be mitigated by entering into contracts with only stable and creditworthy parties and through the frequent review of our exposure to these entities. Overall, approximately 48% of our gas is now hedged for the 2007 calendar year at a floor of $7.55/mcf. For the first quarter of 2007, we have secured approximately 58% of our net gas production at an $8.42/mcf floor. For the months of April to 28 October 2007, approximately 54% of our net gas production is hedged at a floor of $7.08mcf. We have also hedged approximately 14% of our 2007 net crude production at an average floor price of US$65.00/bbl.
------------------------------------------------------------------------------------------------------------------------------ Description of Hedge Term Volume Average Price ------------------------------------------------------------------------------------------------------------------------------ NATURAL GAS - AECO Fixed price November 2006 to March 2007 3,791 mcf/d Cdn$10.02/mcf Collar November 2006 to March 2007 9,478 mcf/d Floor Cdn$8.18/mcf Ceiling Cdn$11.24/mcf Collar November 2006 to March 2007 4,739 mcf/d Floor Cdn$8.44/mcf Ceiling Cdn$12.40/mcf Collar November 2006 to March 2007 4,739 mcf/d Floor Cdn$8.18/mcf Ceiling Cdn$11.66/mcf Collar November 2006 to March 2007 4,739 mcf/d Floor Cdn$8.44/mcf Ceiling Cdn$12.29/mcf Fixed price November 2006 to March 2007 5,687 mcf/d Cdn$8.70/mcf Collar November 2006 to March 2007 5,687 mcf/d Floor Cdn$7.91/mcf Ceiling Cdn$9.81/mcf Collar November 2006 to March 2007 9,478 mcf/d Floor Cdn$8.44/mcf Ceiling Cdn$13.82/mcf CRUDE OIL - WTI Collar October 2006 to March 2007 1,250 bbls/d Floor US$65.00/bbl Ceiling US$87.40/bbl Collar October 2006 to March 2007 1,000 bbls/d Floor US$65.00/bbl Ceiling US$90.00/bbl NATURAL GAS PHYSICAL CONTRACTS - AECO Collar November 2006 to March 2007 4,739 mcf/d Floor Cdn$8.07/mcf Ceiling Cdn$11.61/mcf Collar April 2007 to October 2007 4,739 mcf/d Floor Cdn$7.12/mcf Ceiling Cdn$8.67/mcf Collar April 2007 to October 2007 4,739 mcf/d Floor Cdn$6.86/mcf Ceiling Cdn$9.13/mcf Collar April 2007 to October 2007 9,478 mcf/d Floor Cdn$7.39/mcf Ceiling Cdn$9.63/mcf
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 2,859 (gross) producing and non-producing wells. Costs to abandon and reclaim the producing wells totals $90.7 million ($23.7 million discounted at 7%) 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 $66.5 million ($10.6 million discounted at 7%), and was not deducted in estimating 29 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 $0.6 million in 2007, $1.7 million in 2008 and $2.0 million in 2009. TAX HORIZON In 2006, we did not pay any income related taxes. Effective January 1, 2006 new government legislation eliminated Federal large corporations tax. In our structure, the operating company utilizes available tax pools to significantly reduce taxable income and makes other required payments to the Trust transferring both income and associated tax liability to the Unitholders. Therefore, it is expected, based on current legislation that no cash income taxes are to be paid by the operating company in the future and it is our intent to continue with the current arrangement. For the 2006 distributions, 50% were taxable to the Canadian Unitholders and 50% were deemed a return of capital. For U.S. Unitholders, 2006 distributions were 53% taxable and 47% were deemed a return of capital. CAPITAL EXPENDITURES The following tables summarize capital expenditures (including capitalized general and administrative expenses) related to our activities for the year ended December 31, 2006: CAPITAL EXPENDITURES ($ THOUSANDS) 2006 ------------------------------------------------------------------------------ Land and seismic 5,261 Drilling, completions and workovers 113,146 Well equipping and facilities 39,437 Other 1,643 ------------------------------------------------------------------------------ 159,487 ------------------------------------------------------------------------------ Property, acquisitions and purchase price adjustments 244 Property dispositions (8,727) ------------------------------------------------------------------------------ TOTAL CAPITAL EXPENDITURES 151,004 ------------------------------------------------------------------------------ EXPLORATION AND DEVELOPMENT ACTIVITIES The following table sets forth the gross and net wells in which we participated during the year ended December 31, 2006:
Exploratory Development Total ----------------------- ------------------------ ------------------------ Gross Net Gross Net Gross Net ------- ------- ------- ------- ------- ------- Oil wells 5 4.2 48 31.8 53 36.0 Gas wells 20 7.3 67 41.9 87 49.2 Dry holes 4 3.0 3 2.0 7 5.0 ------- ------- ------- ------- ------- ------- Total 29 14.5 118 75.7 147 90.2 ======= ======= ======= ======= ======= =======
Subject to, among other things, the availability of drilling rigs and weather that permits access to drill sites, in 2007, we plan to drill, complete and tie-in 64 net wells and recomplete an additional 5 net wells. 30 PRODUCTION ESTIMATES The following table sets out the volume of our production estimated for the year ended December 31, 2007 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 5,731 697 104,158 2,479 26,267 Developed Non-Producing 168 0 3,647 119 895 Undeveloped 584 0 4,074 90 1,353 ---------- --------- ----------- ------- ------- Total Proved 6,483 697 111,879 2,688 28,515 ---------- --------- ----------- ------- ------- Probable 599 59 10,181 279 2,634 ---------- --------- ----------- ------- ------- Total Proved Plus Probable 7,082 756 122,060 2,967 31,149 ---------- --------- ----------- ------- -------
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 ----------------------------------------------------------------------- 2006 ----------------------------------------------------------------------- Dec. 31 Sept. 30 Jun. 30 Mar. 31 --------- --------- --------- --------- Average Daily Production(1) Crude oil and NGLs (bbls/d) 9,570 9,330 6,593 6,760 Natural gas (Mcf/d) 117,134 122,227 70,293 65,768 Combined (boe/d) 29,092 29,701 18,309 17,721 Average Net Prices Received(2) Crude oil and NGLs ($/bbl) 54.58 57.77 68.69 58.26 Natural gas ($/Mcf) 6.90 5.89 6.18 8.69 Combined (boe/d) Royalties(3)(5) Crude oil and NGLs ($/bbl) 9.87 10.20 11.17 11.09 Natural gas ($/Mcf) 1.36 1.26 1.11 1.62 Combined ($/boe) 8.72 8.40 8.30 10.25 Operating Expenses(4)(5) Crude oil and NGLs ($/bbl) 11.92 11.04 11.86 10.86 Natural gas ($/Mcf) 1.61 1.32 1.34 1.43 Combined ($/boe) 10.39 8.92 9.41 9.45 Netback Received(6) Crude oil and NGLs ($/bbl) 57.67 58.41 51.28 57.31 Natural gas ($/Mcf) 2.38 2.41 3.21 3.48 Combined ($/boe) 28.54 28.25 30.77 34.79
Notes: (1) Before deduction of royalties. (2) Production prices are net of costs to transport the product to market and net of realized hedging gains and losses. (3) Royalties are net of ARC. (4) This figure includes all field operating expenses. 31 (5) We do not record royalties and operating expenses on a commodity basis. Information in respect of royalties and operating expenses for crude oil and NGLs ($/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, 2006:
Natural Gas Crude Oil & NGLs Total Properties (Mcf/d) (bbls/d) (boe/d) ------------------------------------------------------------------------------------------------- Willesden Green 11,010 1,460 3,295 Martin Creek 14,100 290 2,640 Nevis 7,000 1,280 2,447 Medicine Hat 13,150 -- 2,192 Peace River Arch 6,900 470 1,620 Fontas 7,540 -- 1,257 Brazeau 5,210 340 1,208 Lookout Butte 5,830 230 1,202 Sunset 2,380 740 1,137 ------------------------------------------------------------------------------------------------- Major Properties 73,120 4,810 16,997 Other 43,160 4,810 12,003 ------------------------------------------------------------------------------------------------- TOTAL 116,280 9,620 29,000
DEFINITIONS AND OTHER NOTES 1. Columns set forth above 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 32 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: (e) 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; (f) 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; (g) dry hole contributions and bottom hole contributions; (h) costs of drilling and equipping exploratory wells; and (i) costs of drilling exploratory type stratigraphic test wells. "GROSS" means: (j) 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; (k) in relation to wells, the total number of wells in which we have an interest; and (l) in relation to properties, the total area of properties in which we have an interest. "NET" means: (m) 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; (n) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and (o) 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. 33 (b) PROBABLE RESERVES are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook. Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories: (c) 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. (d) 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% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and (b) at least a 50% 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 13% 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 34 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. 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 2007 by the renegotiation or termination of contracts or subcontracts. ENVIRONMENTAL CONSIDERATIONS We are pro-active in our approach to environmental 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, 2006, we employ 111 full-time employees, 87 of which are located in the head office and 24 of which are located in the field. We also employ 9 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, 2006, 105,390,471 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 three classes, as follows: (i) "ordinary trust units", which are entitled to the rights, subject to limitations, restrictions and conditions set out in the Trust Indenture, as summarized herein; (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 the AOG Board of Directors; and (iii) "special trust units", which shall be entitled to the rights and subject to the limitations, restrictions and conditions set out in the Trust Indenture, as summarized herein. As at the date hereof there is one special voting unit and no special trust units 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 (including ordinary trust units and special 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. Each special trust unit entitles the holder or holders thereof to one-half of one vote at any meeting of the Unitholders and each ordinary trust unit entitles the holder or holders thereof to one vote at any meeting of the Unitholders. The Trust Units do not represent a traditional investment and should not be viewed by investors as "shares" in either AOG or the Trust. Corporate law does not govern the Trust and the rights of Unitholders. As holders of Trust Units in the Trust, the 35 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. The price per Trust Unit is a function of anticipated distributable income from AOG and the ability of the AOG Board of Directors 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). Legislation affecting the tax treatment of an investment in Trust Units can change at any time. See "RISK FACTORS". 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 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. 36 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 AOG Board of Directors 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 AOG Board of Directors 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. Pursuant to the provisions of the Trust Indenture all income earned by the Trust in a fiscal year, not previously distributed in that fiscal year, must be distributed to Unitholders of record on December 31. This excess income, if any, will be allocated to Unitholders of record at December 31 but the right to receive this income, if the amount is not determined and declared payable at December 31, will trade with the Trust Units until determined and declared payable in accordance with the rules of the Toronto Stock Exchange. To the extent that a Unitholder trades Trust Units in this period they will be allocated such income but will dispose of their right to receive such distribution. 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. 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 37 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 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 38 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 25, 2007. 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 AOG Board of Directors 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 AOG Board of Directors 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 was 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 providing 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. DELEGATION OF AUTHORITY, ADMINISTRATION AND TRUST GOVERNANCE AOG has generally been delegated our significant management decisions. In particular, pursuant to the Administration Agreement, the Trustee has delegated to AOG responsibility for the administration and management of all general and administrative affairs of Advantage, including, among other things: 39 (a) maintaining records and accounts; (b) preparing all tax returns, filings and documents and monitor the tax status of the Trust and of the Trust Units; (c) providing advice with respect to the Trust's obligations as a reporting issuer and ensure compliance under applicable securities legislation; (d) providing investor relations services to the Trust; (e) calling and holding all meetings of the Unitholders; (f) undertaking all matters relating to an offering including; (i) compliance with all applicable laws; (ii) all matters relating to the content of any offering documents, the accuracy of the disclosure and the certification thereof; and (iii) all matters concerning the entering into, terms of, and amendment from time to time of material contracts; (g) retaining professional services and advisors; (h) dealing with banks and other institutional lenders; (i) taking all actions reasonably necessary in relation to the redemption of Trust Units; (j) taking all actions reasonably necessary in relation to voting rights on any investments in the Trust Fund; (k) taking all action reasonably necessary relating to the specific powers and authorities as set forth in the Trust Indenture; (l) taking all actions reasonably necessary in relation to providing indemnities for the directors and officers of the Administrator and any affiliates of the Trust or the Administrator; (m) providing or causing to be provided to the Trustee any services reasonably necessary for the Trustee to be able to consider any future acquisitions or divestitures by the Trustee of any portion of the Trust Fund; (n) providing advice and, at the request and under the direction of the Trustee, direction to the transfer agent; (o) determining and arranging for distributions to Unitholders; (p) providing advice and assistance to the Trustee with respect to the performance of the obligations of the Trust and the enforcement of the rights of the Trust under all agreements entered into by the Trust; (q) withholding the withholding taxes required and promptly remit such taxes to the appropriate taxing authority; (r) providing such additional administrative and support services pertaining to the Trust, the Trust Fund and the Trust Units and matters incidental thereto as may be reasonably requested by the Trustee from time to time; (s) reporting to Unitholders; 40 (t) providing management services, for the economic and efficient exploration, exploitation and development of assets of the Trust; (u) recommending, carrying out and monitoring property acquisitions and dispositions and exploitation and development programs for the Trust; and (v) doing all such things regarding the use of commodity price swaps, hedges or other such instruments or agreements on behalf of the Trust in respect of commodity prices or rates of exchange of currencies or interest rates, the purpose of which is to mitigate or eliminate exposure to the fluctuations and prices of commodities or rates of exchange of one currency for another or interest rates. For more information as to the AOG Board of Directors, see "ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD. - MANAGEMENT OF AOG". LIABILITY OF THE TRUSTEE The Trustee, its directors, officers, employees, shareholders and agents shall not be liable to any 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 AOG or any other appropriately qualified person, any reliance upon any such evaluation, any action or failure to act of the 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 AOG to perform its duties under or delegated to it under the Trust Indenture or any material contract), unless such liabilities arise out of the gross negligence, wilful default or fraud of the Trustee or any of its directors, officers, employees, shareholders or agents. If the Trustee has retained an appropriate expert, adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture or any material contract, the Trustee may act or refuse to act based upon the advice of such expert, adviser or legal counsel, and the Trustee shall not be liable for and shall be fully protected from any loss or liability occasioned by any action or refusal to act based upon the advice of any such expert, adviser or legal counsel. In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the Trust and shall not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to the Trust or the Trust Fund. In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee. AMENDMENTS TO THE TRUST INDENTURE The Trust Indenture may be amended or altered, from time to time, by at least 66?% of the votes cast at a meeting of 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; 41 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 AOG Board of Directors, requires approval by at least 66 2/3% 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.
DIRECTORS AND OFFICERS OF AOG ------------------------------------------------------------------------------------------------------------------------------ Position Held and Name, Province and Country Period Served as of Residence a Director(4)(5) Principal Occupations During Past Five Years ------------------------------------------------------------------------------------------------------------------------------ Gary F. Bourgeois Vice President, Vice President, Corporate Development of AOG since May 24, 2001. Vice Ontario, Canada Corporate President of AIM from March 2001 to June 2006. Prior thereto, Managing Ontario, Canada Development and Director of the EnerPlus Group of Companies, which companies specialize Director since in management of oil and gas income funds and royalty trusts May 24, 2001 (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 Chief Executive Chief Executive Officer of AOG since May 24, 2001. President of AIM from Alberta, Canada Officer and March 2001 to June 2006. Prior thereto, Senior Vice President Director since (1997-2001) and Vice President, Finance and Chief Financial Officer May 24, 2001 (1990-1997) of EnerPlus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts.
42
DIRECTORS AND OFFICERS OF AOG ------------------------------------------------------------------------------------------------------------------------------ Position Held and Name, Province and Country Period Served as of Residence a Director(4)(5) Principal Occupations During Past Five Years ------------------------------------------------------------------------------------------------------------------------------ Grant B. Fagerheim(2)(4) Director since President and Chief Executive Officer of Kereco Energy Ltd. since Alberta, Canada June 23, 2006 January, 2005. President and Chief Executive Officer of Ketch Resources Ltd. from November 2002 to January 2005. President and Chief Executive Officer of Ketch Energy Ltd. from April 2000 to October 2002. John A. Howard (3)(8) Director since Independent Businessman. Director of Ketch Resources Ltd. from January Alberta, Canada June 23, 2006 2005 to June 23, 2006. Director of Bear Ridge Resources Ltd. since January 2005. President of Lunar Enterprises Corp. Director of Eastshore Energy Ltd. since July 2003. Director of Rockyview Energy Inc. since June 2005. Director of Bear Creek Energy Ltd. from June 2004 to January 2005. Director of APF Energy Trust from August 2004 to June 2005. Andy J. Mah President and President and Chief Operating Officer since June 23, 2006. Prior Alberta, Canada Chief Operating thereto, President of Ketch Resources Ltd. since October 2005. Chief Officer and a Operating Officer of Ketch Resources Ltd. from January 2005 to September Director since 2005. Prior thereto, Executive Officer and Vice President, Engineering June 23, 2006 and Operations of Northrock Resources Ltd. from August 1998 to January 2005. Ronald A. McIntosh(1)(3) Director since Chairman of North American Energy Partners Inc., a publicly traded Alberta, Canada September 25, corporation. 1998(6) Roderick M. Myers(1)(3)(9) Director since Since May 24, 2001, a self-employed businessman. Prior thereto, Vice British Columbia, Canada December 31, President, Business Development of Search Energy Corp. 1996(6) Carol Pennycook(1)(2) Director since Partner at the Toronto office of Davies Ward Phillips & Vineberg, LLP, a Ontario, Canada May 26, 2004 national law firm. Steven Sharpe(2) Director since Managing Partner of Blair Franklin Capital Partners Inc., an investment Ontario, Canada May 24, 2001 and banking firm since May, 2003. Prior thereto, Mr. Sharpe was the Managing Non-Executive Director of The EBS Corporation, a management and strategic consulting Chairman since firm, since June 2001. From July 1998 to June 2001, Executive Vice May 26, 2004 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)(2)(7) Director since President of Tourigny Management Ltd., a private oil and gas consulting Alberta, Canada December 31, company. 1996(6) Patrick J. Cairns Senior Vice Senior Vice President of AOG since June 2001. Vice President of the Alberta, Canada President 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.
43
DIRECTORS AND OFFICERS OF AOG ------------------------------------------------------------------------------------------------------------------------------ Position Held and Name, Province and Country Period Served as of Residence a Director(4)(5) Principal Occupations During Past Five Years ------------------------------------------------------------------------------------------------------------------------------ Peter Hanrahan Vice President Chief Financial Officer of AOG since January 2003. Prior thereto, Alberta, Canada Finance and Controller of AOG since December 1999. Prior thereto, Manager of Chief Financial Financial Reporting with Numac Energy Inc. Officer David Cronkhite Vice-President, Vice-President, Operations since July 18, 2006. Prior thereto, Alberta, Canada Operations Production Manager of AOG for five years. Prior thereto, Mr. Cronkhite held engineering positions with several oil and gas companies. Neil Bokenfohr Vice President, Vice-President, Exploitation since June 23, 2006. Prior thereto, Vice Alberta, Canada Exploitation President Exploitation and Operations of Ketch Resources Ltd. since January 2005; Vice President, Engineering of Bear Creek Energy Ltd. (and Crossfield Gas Corp. prior thereto) from March 2002 to January 2005. Prior thereto, Director of Exploitation for Calpine Canada Natural Gas Company from December 2000 to March 2002. Weldon M. Kary Vice President, Vice President, Exploitation since February 14, 2005. Prior thereto, with Alberta, Canada Geosciences and AOG since May 23, 2001, most recently as Manager, Geology and Geophysics. Land Prior thereto, Exploration Manager at Palliser Energy Corp. when Palliser was purchased by Search Energy Corp, the predecessor entity of AOG. Anthony Coombs Controller Controller since September 1, 2004. Prior thereto with AOG since May 23, Alberta, Canada 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 law firm. Alberta, Canada Secretary
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. (8) Mr. Howard was the President, Chief Executive Officer and Director of Sunoma Energy Corp. Immediately upon his resignation from the executive and board of directors, Sunoma Energy Corp. filed for Court protection. (9) Not standing for re-election at the upcoming meeting of Unitholders. 44 As at March 12, 2007, the directors and executive officers of AOG, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 3,731,958 Trust Units, or approximately 3.3% 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 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 received 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. AOG is the sole holder of the issued and outstanding common shares. There are no non-voting shares, preferred shares or exchangeable shares issued and outstanding. Advantage is also the sole holder of the outstanding Notes. The following is a description of the rights attaching to the common shares, non-voting shares, preferred shares and Notes. COMMON SHARES Each common share entitles its holder to receive notice of and to attend all meetings of the shareholders of AOG and to one vote at such meetings. The holders of common shares are, at the discretion of the AOG Board of Directors and subject to applicable legal restrictions, entitled to receive any dividends declared by the AOG 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 AOG 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 45 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. 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 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 46 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, 2006 was $662,269,576. 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 AOG 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, 2006 was $213,575,284. The Medium Term Notes consist of a series of notes, which as of December 31, 2006, 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, 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)). 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 99% of the production revenues from the Properties 47 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 99% 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 acquire or dispose of any properties that will cost or result in proceeds in excess of $5 million, approval of the AOG Board of Directors is required to approve such acquisition or disposition, respectively. CASH DISTRIBUTIONS The following is a summary of the distributions made by us for each of the three most recently completed financial years. Distributions For the 2006 Period Ended per Unit Payment Date ------------------------- ------------- ------------------ January 31 $0.25 February 15, 2006 February 28 0.25 March 15, 2006 March 31 0.25 April 17, 2006 April 30 0.25 May 15, 2006 May 31 0.25 June 15, 2006 June 30 0.25 July 17, 2006 July 31 0.20 August 15, 2006 August 31 0.20 September 15, 2006 September 30 0.20 October 16, 2006 October 31 0.20 November 15, 2006 November 30 0.18 December 15, 2006 December 31 0.18 January 15, 2007 -------- TOTAL: $2.66 48 Distributions For the 2005 Period Ended per Unit Payment Date ------------------------- ------------- ------------------ January 31 $0.28 February 15, 2005 February 29 0.28 March 15, 2005 March 31 0.28 April 15, 2005 April 30 0.28 May 16, 2005 May 31 0.25 June 15, 2005 June 30 0.25 July 15, 2005 July 31 0.25 August 15, 2005 August 31 0.25 September 15, 2005 September 30 0.25 October 17, 2005 October 31 0.25 November 15, 2005 November 30 0.25 December 15, 2005 December 31 0.25 January 16, 2006 ---- TOTAL $3.12 Distributions For the 2004 Period Ended 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) On February 15, 2007 a distribution of $0.15 per Trust Unit was paid to Unitholders of Record on the close of business on January 31, 2006. We announced on February 14, 2007 that a distribution of $0.15 per Trust Unit will be payable on March 15, 2007 to Unitholders of record on the close of business on February 28, 2007. MARKET FOR SECURITIES Our Trust Units are listed for trading on the TSX under the symbol "AVN.UN" and, since December 9, 2005, on the NYSE under the symbol "AAV". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the Trust Units as reported by the TSX for the periods indicated. 49 Period High Low Volume ------------------ --------- ----------- ------------ TSX TRADING ($) ($) 2006 January 23.95 21.02 9,642,249 February 24.35 19.87 10,809,845 March 23.00 20.81 6,193,383 April 23.26 21.30 3,993,614 May 22.10 20.01 4,514,672 June 21.18 18.55 7,236,955 July 19.45 17.25 14,968,997 August 18.83 17.65 8,135,213 September 17.83 13.17 8,434,297 October 16.42 12.05 15,632,835 November 14.95 11.74 13,668,239 December 14.49 12.20 5,573,202 2007 January 13.41 11.47 7,579,256 February 12.80 12.13 5,898,850 NYSE TRADING ($US) 2006 January 21.00 18.05 9,773,000 February 21.30 17.50 8,086,300 March 19.98 18.08 5,633,800 April 20.46 18.85 3,913,300 May 19.88 17.51 5,390,200 June 19.08 16.69 5,688,500 July 17.85 15.33 7,869,600 August 16.70 15.88 4,845,400 September 16.12 11.88 6,183,700 October 14.55 10.74 9,064,500 November 13.10 10.28 12,499,000 December 12.65 10.47 5,648,500 2007 January 11.40 9.76 5,406,700 February 10.90 10.46 3,333,500 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 ------------------ --------- ----------- ------------ 2006 ($) ($) January 177.24 160.79 1,150 February 178.21 164.48 940 March 170.00 169.03 550 April 170.00 168.00 300 May 163.75 150.92 1,450 June 155.50 150.65 2,670 July -- -- -- August 138.55 134.62 550 September 117.00 117.00 100 October -- -- -- November 100.00 100.00 100 December 110.00 101.01 300 50 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 ------------------ --------- ----------- ------------ 2006 ($) ($) January 140.00 129.25 2,385 February 140.50 126.07 7,130 March 131.89 125.00 1,630 April 135.00 127.91 990 May 127.00 117.50 2,020 June 124.00 110.00 3,690 July 111.71 108.75 800 August 113.00 107.12 360 September 103.80 100.26 450 October 103.00 103.00 270 November 109.00 103.00 450 December 103.01 103.01 240 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 ------------------ --------- ----------- ------------ 2006 ($) ($) January 144.40 129.15 5,280 February 146.27 126.78 32,670 March 138.03 130.00 5,520 April 139.09 131.56 950 May 132.50 120.65 2,980 June 122.83 116.08 820 July 112.50 106.00 890 August 110.07 106.68 670 September 106.60 103.75 1,630 October 106.00 104.05 1,210 November 106.00 102.50 850 December 105.00 105.00 140 51 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 ------------------ --------- ----------- ------------ January 118.00 107.59 17,920 February 120.00 105.01 30,350 March 113.25 106.70 26,660 April 114.50 108.01 7,310 May 110.20 104.65 19,110 June 108.01 103.75 23,400 July 105.00 102.00 37,650 August 104.34 102.25 4,130 September 103.50 100.00 344,210 October 102.95 100.25 6,740 November 102.27 100.01 9,110 December 101.99 100.50 2,240 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 ------------------ --------- ----------- ------------ 2006 ($) ($) January 113.90 104.59 46,730 February 115.72 104.01 45,770 March 111.00 106.50 25,310 April 111.00 108.00 19,580 May 108.99 104.75 27,750 June 107.99 104.10 20,410 July 105.01 101.25 19,622 August 104.00 102.20 6,020 September 103.41 101.00 32,350 October 102.75 99.22 11,340 November 102.50 100.00 15,270 December 101.35 100.60 5,930 Our 6.50% Convertible Debentures are listed for trading on the TSX under the symbol "AVN.DB.E". The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 6.50% Convertible Debentures as reported by the TSX for the periods indicated. Period High Low Volume ------------------ --------- ----------- ------------ 2006 ($) ($) June 101.99 99.50 1,290 July 102.00 99.00 11,560 August 102.00 99.00 13,810 September 100.00 97.01 36,430 October 99.50 96.00 21,950 November 98.01 94.50 22,560 December 98.00 95.77 30,840 52 ESCROWED SECURITIES As part of the Arrangement, shareholders of AIM received Trust Units in payment for the sale of their AIM shares to the Trust. All such shareholders were required to enter into an escrow agreement (the "ESCROW AGREEMENT") providing for the release of Trust Units as to one-third on each anniversary date of the Arrangement for three years. All distributions paid on the Trust Units held in escrow are made directly to the holders of the escrowed Trust Units, notwithstanding that their Trust Units are in escrow. All Trust Units will be released from escrow if a Change in Control (as defined in the Escrow Agreement) occurs. All Trust Units being held in escrow for a particular shareholder will be released upon that shareholder ceasing to be an employee for any reason other than termination for just cause or voluntary departure or resignation. The Board may consent to the transfer within escrow or the release from escrow of Trust Units in such circumstances and on such terms and conditions as it shall determine in its sole discretion. The Trust Units subject to escrow at December 31, 2006 are as follows: NUMBER OF TRUST UNITS HELD IN PERCENTAGE OF DESIGNATION OF CLASS IN ESCROW CLASS -------------------- -------------- ------------- Trust Units 1,822,099(1) 1.7% Notes: (1) All Trust Units are held by Computershare Trust Company of Canada as escrow agent. 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 MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS There were no material interests, direct or indirect, of directors and senior officers of AOG or 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 2006 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 2006; 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 Administrative Agreement described herein under the heading "ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND - DELEGATION OF AUTHORITY, ADMINISTRATION AND TRUST GOVERNANCE". Copies of the Trust Indenture and Administration 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 53 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. KPMG LLP has confirmed that it is independent in accordance with the relevant rules and related interpretation prescribed by the Institute of Chartered Accountants of Alberta. 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 and AOG 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 (the "AUDIT COMMITTEE") is comprised of Messrs. Roderick Meyers, Rodger Tourigny, Carol Pennycook and Ronald McIntosh. 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.
---------------------------------------------------------------------------------------------------------------------------- NAME, PROVINCE AND COUNTRY OF FINANCIALLY RESIDENCE INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE ---------------------------------------------------------------------------------------------------------------------------- Roderick M. Myers(1) Yes Yes Mr. Meyers has a Masters degree in Civil Engineering. British Columbia, Canada He is currently a self-employed businessman who has been working in Calgary's energy sector since 1981 and has focused on evaluating and investing in small-cap oil and natural gas ventures. Rodger A. Tourigny Yes Yes Mr. Tourigny has a Bachelor of Commerce and is a Alberta, Canada 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 Sound Energy Trust and is a director and member of the Audit Committee of Burmis Energy Inc. and of Ramparts Energy Ltd., a private oil and gas company. Ronald A. McIntosh Yes Yes Mr. McIntosh is the Chairman and member of audit Alberta, Canada committee of North American Energy Partners Inc., a publicly traded corporation. He is a director and member of the audit committee of C1 Energy Ltd. Mr. McIntosh is also the Chairman and member of the audit committee of Tasman Energy, a private oil and gas company.
54
---------------------------------------------------------------------------------------------------------------------------- NAME, PROVINCE AND COUNTRY OF FINANCIALLY RESIDENCE INDEPENDENT LITERATE RELEVANT EDUCATION AND EXPERIENCE ---------------------------------------------------------------------------------------------------------------------------- Carol D. Pennycook Yes Yes Ms. Pennycook is a partner at the Toronto offices of Ontario, Canada Davies Ward Phillips & Vineberg, LLP, a national law firm. Ms. Pennycook received her LLB in 1979 and has been a partner since 1986. A significant portion of Ms. Pennycook's practice involves financing transactions
Note: (1) Not standing for re-election at the upcoming meeting of Unitholders. 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 AOG Board of Directors on April 30, 2002 and amended in April 2003, April 2004, June 2005, August 2005, October 2005 and March 2006: 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. ("AOG") in fulfilling its responsibilities by reviewing: the financial reports and other financial information provided by Advantage Energy Income Fund (the "TRUST") 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 endeavour to encourage continuous improvement of, and should endeavour to foster adherence to, the Trust's policies, procedures and practices at all levels. In performing its duties, the external auditor is to report directly to the Audit Committee. The Audit Committee's primary objectives are: 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 assist the Board's oversight of the auditor's qualifications and independence; 4. To assist the Board's oversight of the credibility, integrity and objectivity of financial reports; 5. To strengthen the role of the outside directors by facilitating discussions between directors on the Audit Committee, management and external auditors; 6. To assist the Board's oversight of the performance of Corporation's internal audit function and independent auditors; and 7. To assist the Board's oversight of the Corporation's compliance with legal and regulatory requirements. 55 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 "independent" (as such term is defined in (a) Multilateral Instrument 52-110 -- Audit Committees ("MI 52-110") and (b) Section 303A.02 of the Corporate Governance Rules of the New York Stock Exchange). 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 definition is set forth in Schedule "A" attached hereto. Audit Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Trust or an outside consultant. In addition, at least one member of the Audit Committee must have accounting or related financial management expertise, as the Corporation's Board of Directors interprets such qualification in its business judgment. 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. In connection with the election of the members of the Audit Committee, the Board will determine whether any proposed nominee for the Audit Committee serves on the Audit Committees of more than three public companies. To the extent that any proposed nominee of the Corporation serves on the Audit Committees of more than three public companies, the Board will make a determination as to whether such simultaneous services would impair the ability of such member to effectively serve on the Corporation's Audit Committee and will disclose such determination in the Corporation's annual information circular and annual report on Form 40-F filed with the Securities and Exchange Commission. 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, internal auditors (if any) 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 Section IV.4 below. The Audit Committee should also meet with management and independent auditors on an annual basis to review and discuss annual financial statements and the management's discussion and analysis of financial conditions and results of operations. Attached as Schedule "B" is an example of an annual meeting schedule/agenda. 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 endeavour to: 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. 56 5. Review 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. 7. Periodically discuss guidelines and policies to govern the processes by which the Chief Executive Officer and senior management assess and manage the Corporation's exposure to risk. 8. Report regularly to the Board any issues that arise with respect to the quality or integrity of the Corporation's financial statements, compliance with legal or regulatory requirements, performance and independence of the Corporation's auditors, or performance of the internal audit function. 9. To prepare, if required, an Audit Committee report to be included in the Corporation's annual information circular and proxy statement. 10. Preparing an annual performance evaluation of the Audit Committee. 11. At least annually, obtaining and reviewing the report by the independent auditors describing the Trust's internal quality control procedures, any material issues raised by the most recent interim quality-control review, or peer review, of the Trust or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps to deal with any such issues. INDEPENDENT AUDITORS 12. Recommend to the Board the external auditors to be nominated for appointment by the unitholders. 13. Approve the compensation of the external auditors. 14. 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. In addition, the Audit Committee will ensure the rotation of the lead audit partner every five years and, in order to ensure continuing auditor independence, consider the rotation of the audit firm itself. 15. Review and, as appropriate, resolve 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. 16. 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. 17. 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. 18. Oversee the establishment of an internal audit function. 19. Periodically assess the Corporation's internal audit function, including Corporation's risk management processes and system of internal controls. 20. Review the audit scope and plan of the independent auditor. 21. 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. 57 22. 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 (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 22 if: (d) 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; (e) 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; (f) 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; and 23. Review, set and approve hiring policies relating to staff of current and former auditors. FINANCIAL REPORTING PROCESSES 24. In consultation with the independent auditors, annually review the integrity of the organization's financial reporting processes, both internal and external. 25. In consultation with the independent auditors, consider annually the quality and appropriateness of the Corporation's accounting principles as applied in its financial reporting. 26. 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. 27. Review risk management policies and procedures of the Trust and AOG (i.e., litigation and insurance). PROCESS IMPROVEMENT 28. 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. 29. 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. 30. Review any significant disagreements among management and the independent auditors in connection with the preparation of the financial statements. 58 31. 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.) 32. 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. 33. Review the systems that identify and manage principal business risks. 34. Establish a procedure for: (a) the receipt, retention and treatment of complaints received by the Trust and AOG regarding accounting, internal accounting controls or auditing matters; and (b) the confidential, anonymous submission by employees of the Trust and AOG of concerns regarding questionable accounting or auditing matters; which procedure shall be set forth in a "whistle blower program" to be adopted by the Audit Committee in connection with such matters. ETHICAL AND LEGAL COMPLIANCE 35. Establish, review and update periodically a Code of Ethical Conduct and ensure that management has established a system to enforce this code. 36. Review management's monitoring of the Trust's compliance with the organization's Ethical Code. 37. 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. 38. 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. 39. Review with the organization's counsel legal compliance matters including the trading policies of securities. OTHER 40. 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. 41. In connection with the performance of its responsibilities as set forth above, the Audit Committee shall have the authority to engage outside advisors and to pay outside auditors and advisors. 59 AUDIT SERVICE FEES AUDITOR SERVICES FEES The following table discloses fees billed to us by our auditors, KPMG LLP.
-------------------------------------------------------------------------------------------------------------------------- TYPE OF SERVICE PROVIDED 2006 2005 -------------------------------------------------------------------------------------------------------------------------- Audit Fees (these services included prospectus work and audit or review of financials $617,000 $269,000 forming part of such prospectus and U.S. GAAP reconciliation matters) Audit-Related Fees (these services included French translation in connection with $144,500 $ 30,000 prospectus offerings) Tax Fees (these services included review/completion of tax returns and general tax $ 36,040 $ 21,725 consultations)
INDUSTRY CONDITIONS The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia, and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas entities of similar size. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry. PRICING AND MARKETING - OIL AND NATURAL GAS The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council. The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires the approval of the Governor in Council. The governments of Alberta, British Columbia, and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations. 60 PIPELINE CAPACITY Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market natural gas production. In addition, the pro-rationing of capacity on the inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas. THE NORTH AMERICAN FREE TRADE AGREEMENT The North American Free Trade Agreement ("NAFTA") among the governments of Canada, United States of America, and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price subject to an exception with respect to certain voluntary measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings. NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector by 2010 and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports. PROVINCIAL ROYALTIES AND INCENTIVES GENERAL In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner's interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests. Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years has been for provincial governments to eliminate, amend or allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative. The Canadian federal corporate income tax rate levied on taxable income is 22.1% effective January 1, 2007 for active business income including resource income. With the elimination of the corporate surtax effective January 1, 2008 and other rate reductions introduced in the 2006 Federal Budget, the federal corporate income tax rate will decrease to 19% in three steps: 20.5% on January 1, 2008, 20% on January 1, 2009 and 19% on January 1, 2010. 61 ALBERTA In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents. Currently, the amount of royalties that are payable is influenced by the oil production, density of the oil, and the vintage of the oil. Originally, the vintage classified oil in "new oil" and "old oil" depending on when the oil pools were discovered. If discovered prior to March 31, 1974 it is considered "old oil", if discovered after March 31, 1974 and before September 1, 1992, it is considered "new oil". The Alberta government introduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 1, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%. The royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 metres is also subject to a royalty exemption, the amount of which depends on the depth of the well. Oil sands projects are subject to a specific regulation made effective July 1, 1997, and expiring June 30, 2007, which, among other things, determines the Crown's share of crude and processed oil sands products. Regulations made pursuant to the MINES AND MINERALS ACT (Alberta) provided various incentives for exploring and developing oil reserves in Alberta. However, the Alberta Government announced in August of 2006 that four royalty programs were to be amended, a new program was to be introduced and the Alberta Royalty Tax Credit Program ("ARTC") was to be eliminated, effective January 1, 2007. The ARTC was eliminated on January 1, 2007 as announced. The programs being amended are: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction. The program being introduced is the Innovative Energy Technologies Program (the "IETP") which is intended to promote the producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. The IETP provides royalty reductions which are presumed to reduce financial risk. Alberta Energy will be the one to decide which projects qualify and the level of support that will be provided. The deadline for the IETP's third round of applications is May 31, 2007. On February 16, 2007, the Alberta Government announced that a review of the province's royalty and tax regime (including income tax and freehold mineral rights tax) pertaining to oil, gas and oil sands will be conducted by a panel of experts, with the assistance of individual Albertans and key stakeholders. The purpose of this process is to ensure that Albertans are receiving a fair share from energy development through royalties, taxes and fees. The issues to be reviewed during this examination process are: (i) undertaking a comparison of Alberta's royalty system to other oil and gas producing jurisdictions, taking into account investment economics and industry returns and risks in Alberta; (ii) whether Alberta's royalty system is sufficiently sensitive to market conditions; (iii) whether the current revenue minus cost system for oil sands royalties is optimal; (iv) which programs built into the existing royalty system should be retained or strengthened, and which should be adapted or eliminated; (v) how the tax treatment of the oil and gas sector compares to other sectors and jurisdictions; (vi) the economic and fiscal impacts of any possible changes to the royalty and corporate tax structures; and (vii) how existing resource development should be treated if changes are to be made to the fiscal regime. The review panel is to produce a final report that will be presented to the Minister of Finance by August, 31, 2007. BRITISH COLUMBIA Producers of oil and natural gas in the Province of British Columbia are required to pay annual rental payments with respect to the Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands. The amount payable as a royalty in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month, and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (old oil), between October 31, 1975, and June 1, 1998 (new oil), or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable (exempt wells). Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450m(3) produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of 62 exploration and extraction that the producers would incur. The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price. However, when the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty then the royalty payable on non-conservation gas. On May 30, 2003, the Ministry of Energy and Mines for the Province of British Columbia announced an Oil and Gas Development Strategy for the Heartlands ("STRATEGY"). The Strategy is a comprehensive program to address road infrastructure, targeted royalties and regulatory reduction, and British Columbia service sector opportunities. In addition, the Strategy will result in economic and employment opportunities for communities in British Columbia's heartlands. Some of the financial incentives in the Strategy include: o Royalty credits of up to $30 million annually towards the construction, upgrading, and maintenance of road infrastructure in support of resource exploration and development. Funding will be contingent upon an equal contribution from industry. o Changes to provincial royalties: new royalty rates for low productivity natural gas to enhance marginally economic resources plays, royalty credits for deep gas exploration to locate new sources of natural gas, and royalty credits for summer drilling to expand the drilling season. On February 27, 2007 the Government of British Columbia unveiled the Energy Plan outlining the Province's strategy towards the environment and which includes targeting for zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world's leader in sustainable environmental management. With regards to the oil and gas industry the objective is to achieve clean energy through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract investment for the development of the oil and gas sector. Among the changes to be implemented are: (i) a new of Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishing of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) the new Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves from existing reserves and promotes responsible development of new oil and gas reserves. SASKATCHEWAN In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month, and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered "heavy oil", "southwest designated oil", or "non-heavy oil other than southwest designated oil". The conventional royalty and production tax classifications ("fourth tier oil" introduced October 1, 2002, "third tier oil", "new oil", or "old oil") of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all "fourth tier oil" to 20% for "old oil". Marginal royalty rates are 30% for all "fourth tier oil" to 45% for "old oil". The amount payable as a royalty in respect of natural gas is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas, and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The royalty and production tax classifications of gas production are "fourth tier gas" introduced October 1, 2002, "third tier gas", "new gas", and "old gas". The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for "fourth tier gas" and 20% for "old gas". The marginal royalty rates are between 30% for "fourth tier gas" and 45% for "old gas". On October 1, 2002, the following changes were made to the royalty and tax regime in Saskatchewan: 63 o A new Crown royalty and freehold production tax regime applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale. The royalty/tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65 thousand cubic metres in a month. o A modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from oil wells and gas wells with a finished drilling date on or after October 1, 2002, was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of zero per cent. o The elimination of the re entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002, will receive the "fourth tier" royalty/ tax rates and new incentive volumes. In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the federal government disallowing crown royalties and similar taxes as a deductible business expense for income tax purposes. As of January 1, 2007, the remaining balance of any unused RTR limited in its carry forward to five years since the federal government had the initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income. LAND TENURE Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms from two years, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated. ENVIRONMENTAL REGULATION The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties. Environmental legislation in the Province of Alberta has been consolidated into the ENVIRONMENTAL PROTECTION AND ENHANCEMENT ACT (Alberta) (the "EPEA"), which came into force on September 1, 1993, and the OIL AND GAS CONSERVATION ACT (Alberta) (the "OGCA"). The EPEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations, and significantly increased penalties. In 2006, the Alberta Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide emissions from industrial operations including the oil and gas industry. No additional expenses are foreseen that are associated with complying with the new regulations. We are committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment, and will be taking such steps as required to ensure compliance with the EPEA and similar legislation in other jurisdictions in which it operates. We believe that we are in material compliance with applicable environmental laws and regulations. We also believe that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue. British Columbia's ENVIRONMENTAL ASSESSMENT ACT became effective June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental review process. 64 In December, 2002, the Government of Canada ratified the Kyoto Protocol ("PROTOCOL"). The Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 "business-as-usual" levels between 2008 and 2012. Given revised estimates of Canada's normal emissions levels, this target translates into an approximately 40% gross reduction in Canada's current emissions. It remains uncertain whether the Kyoto target of 6% below 1990 emission levels will be enforced in Canada. The Federal Government has introduced legislation aimed at reducing greenhouse gas emissions using a "intensity based" approach, the specifics of which have yet to be determined. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007. As details of the implementation of this legislation have not yet been announced, the effect of our operations cannot be determined at this time. TRENDS There are a number of trends that have been developing in the oil and gas industry during the past several years that appear to be shaping the near future of the business. The first trend is the volatility of commodity prices. Natural gas is a commodity influenced by factors within North America. A tight supply-demand balance for natural gas causes significant elasticity in pricing, whereas higher than average storage levels tend to depress natural gas pricing. Drilling activity, weather, fuel switching and demand for electrical generation are all factors that affect the supply-demand balance. Changes to any of these or other factors create price volatility. Crude oil is influenced by the world economy, Organization of the Petroleum Exporting Countries' ability to adjust supply to world demand and weather. Crude oil prices have been kept high by political events causing disruptions in the supply of oil and concern over potential supply disruptions triggered by unrest in the Middle East and more recently have been impacted by weather and increased storage levels. Political events trigger large fluctuations in price levels. The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. Purchasing land and properties similarly increase in price during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline. A second trend within the Canadian oil and gas industry is the fairly consistent "renewal" of private and small junior oil and gas companies starting up business. These companies often have experienced management teams from previous industry organizations that have disappeared as a part of the ongoing industry consolidation. Many are able to raise capital and recruit well qualified personnel. We will have to compete with these companies and others to attract qualified personnel. A third trend currently affecting the oil and gas industry is the impact on capital markets caused by investor uncertainty in the North American economy. The capital market volatility in Canada has also been affected by uncertainties surrounding the economic impact that the Protocol, and other environmental initiatives, will have on the sector and, in more recent times, by the October 31, 2006 Proposals of the Federal government of Canada relating to income trusts and other "specified investment flow-through" entities ("SIFTS"). Pursuant to the existing provisions of the INCOME TAX ACT (Canada), to the extent that a SIFT has any income for a taxation year after certain inclusions and deductions, the SIFT will be permitted to deduct all amounts of income which are paid or become payable by it to unitholders in the year. Under the October 31, 2006 Proposals, SIFTs will be liable for tax at a rate consistent with the taxes currently imposed on corporations commencing in January 2011, provided that the SIFT experiences only "normal growth" and no "undue expansion" before then, in which case the tax could be imposed prior to the January 2011 deadline. See "RISK FACTORS - CHANGES IN LEGISLATION - THE OCTOBER 31, 2006 PROPOSALS". Generally during the past year, the economic recovery combined with increased commodity prices has caused an increase in new equity financings in the oil and gas industry, although the level of same was negatively impacted by the October 31, 2006 Proposals. We will compete with numerous new companies and their new management teams and development plans in its access to capital. The competitive nature of the oil and gas industry will cause opportunities for equity financings to be selective. We may have to rely on internally generated funds to conduct our exploration and developmental programs. 65 RISK FACTORS The following is a summary of certain risk factors relating to the business of AOG and the Trust. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this annual information form. DEPENDENCE ON AOG 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. OIL AND NATURAL GAS PRICES AOG's results of operations and financial condition and 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 global energy policy, including the ability of OPEC to set and maintain production levels and prices for oil; o political conditions throughout the world, including the risk of hostilities in the Middle East and global terrorism; o worldwide economic conditions; o weather conditions; o the supply and price of foreign oil and natural gas; o the level of consumer demand; o the price and availability of alternative fuels; o the proximity to, and capacity of, transportation facilities; o the effect of worldwide energy conservation measures; and o government regulations. Declines in oil or natural gas prices will have an adverse effect upon 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 2006 averaging US$66.35 WTI as compared to an average of US$56.61 WTI in 2005, an increase of 17%. AECO monthly index prices averaged $6.98/Mcf in 2006 as compared to $8.49/Mcf in 2005, a decrease of 18%. 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. 66 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. OPERATING COSTS AND PRODUCTION DECLINES Higher operating costs for the underlying properties of AOG will directly decrease the amount of cash flow received by us and, therefore, may reduce distributions to our Unitholders. Electricity, chemicals, supplies, reclamation and abandonment and labour costs are a few of AOG's operating costs that are susceptible to material fluctuation. The level of production from AOG's existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond AOG's control. A significant decline in production could result in materially lower revenues and cash flow and, therefore, could reduce the amount available for distributions to Unitholders. 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. 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 AOG Board of Directors has the discretion to determine the extent to which cash flow will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including under the credit facility. As a consequence, the amount of funds retained by AOG to pay debt services charges or reduce debt will reduce the amount of cash distributed to Unitholders during those periods in which funds are so retained. 67 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. DEBT SERVICE AOG has credit facilities in the amount of $600,000,000. 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. ENVIRONMENTAL CONCERNS All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. In 2002, the Government of Canada ratified the Kyoto Protocol (the "PROTOCOL"), which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases. Implementation of strategies for reducing greenhouse gases whether to meet the limits required by the Protocol or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including those of the Trust. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the Trust and its operations and financial 68 condition. 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 our actual future environmental and reclamation obligations. Although AOG maintains insurance coverage considered to be customary in the industry, it is not fully insured against certain environmental risks, either because such insurance is not available, or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (compared to sudden and catastrophic damages) is not available. Accordingly, AOG's properties may be subject to liability due to hazards which cannot be insured against, or have not been insured against due to prohibitive premium costs or for other reasons. In such an event, these environmental obligations will be funded out of AOG's cash flow and could therefore reduce distributable income payable to Unitholders. 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, accounting delays, 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 $Cdn/$US exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar, which occurred in 2006, negatively impacted our net production revenue and may affect the future value of our reserves as determined by independent evaluations at this time. The Canadian dollar strengthened in 2006 to an average $0.88 US/Cdn compared to $0.83 US/Cdn in 2005. 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 SENIOR EXECUTIVES OF AOG Unitholders will be dependent upon the management of 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 AOG should not invest in the Trust Units. 69 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 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: 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 70 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 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 - THE OCTOBER 31, 2006 PROPOSALS The October 31, 2006 Proposals propose to apply a tax at the trust level on distributions of certain income from publicly traded mutual fund trusts at rates of tax comparable to the combined federal and provincial corporate tax and to treat such distributions as dividends to the unitholders. Existing trusts will have a four-year transition period and, subject to the qualification below, will not be subject to the new rules until January 1, 2011. However, assuming the October 31, 2006 Proposals are ultimately enacted in their current form, the implementation of such legislation would be expected to result in adverse tax consequences to the Trust and certain Unitholders (including most particularly Unitholders that are tax deferred or non-residents of Canada) and may impact cash distributions from the Trust. In light of the foregoing, management of AOG believes that the October 31, 2006 Proposals may reduce the value of the Trust Units, which would be expected to increase the cost to the Trust of raising capital in the public capital markets. In addition management of AOG believes that the October 31, 2006 Proposals are expected to: (a) substantially eliminate the competitive advantage that the Trust and other Canadian energy trusts enjoy relative to their corporate peers in raising capital in a tax-efficient manner; and (b) place the Trust and other Canadian energy trusts at a competitive disadvantage relative to industry competitors, including U.S. master limited partnerships, which will continue to not be subject to entity level taxation. The October 31, 2006 Proposals are also expected to make the Trust Units less attractive as an acquisition currency. As a result, it may become more difficult for the Trust to compete effectively for acquisition opportunities. There can be no assurance that the Trust will be able to reorganize its legal and tax structure to substantially mitigate the expected impact of the October 31, 2006 Proposals. Further, the proposals provide that, while there is no intention to prevent "normal growth" during the transitional period, any "undue expansion" could result in the transition period being "revisited", presumably with the loss of the benefit to the Trust of that transitional period. As a result, the adverse tax consequences resulting from the proposals could be realized sooner than January 1, 2011. On December 15, 2006, the Department of Finance issued guidelines with respect to what is meant by "normal growth" in this context. Specifically, the Department of Finance stated that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to a SIFT's market capitalization as of the end of trading on October 31, 2006 (which would include only the market value of the SIFT's issued and outstanding publicly-traded trust units, and not any convertible debt, options or other interests convertible into or exchangeable for trust units). Those safe harbour limits are 40% for the period from November 1, 2006 to December 31, 2007, and 20% each for calendar 2008, 2009 and 2010. Moreover, these limits are cumulative, so that any unused limit for a period carries over into the subsequent period. Additional details of the Department of Finance's guidelines include the following: (a) new equity for these purposes includes units and debt that is convertible into units (and may include other substitutes for equity if attempts are made to develop those); (b) replacing debt that was outstanding as of October 31, 2006 with new equity, whether by a conversion into trust units of convertible debentures or otherwise, will not be considered growth for these purposes and will therefore not affect the safe harbour; and 71 (c) the exchange, for trust units, of exchangeable partnership units or exchangeable shares that were outstanding on October 31, 2006 will not be considered growth for those purposes and will therefore not affect the safe harbour where the issuance of the trust units is made in satisfaction of the exercise of the exchange right by a person other than the SIFT. The Trust's market capitalization as of the close of trading on October 31, 2006, having regard only to its issued and outstanding publicly-traded Trust Units, was approximately $1.6 billion, which means the Trust's "safe harbour" equity growth amount for the period ending December 31, 2007 is approximately $640 million, and for each of calendar 2008, 2009 and 2010 is an additional approximately $320 million (in any case, not including equity, including convertible debentures, issued to replace debt that was outstanding on October 31, 2006). While these guidelines are such that it is unlikely they would affect our ability to raise the capital required to maintain and grow our existing operations in the ordinary course during the transition period, they could adversely affect the cost of raising capital and our ability to undertake more significant acquisitions. It is not known at this time when the October 31, 2006 Proposals will be enacted by Parliament, if at all, or whether the October 31, 2006 Proposals will be enacted in the form currently proposed. CHANGES IN TAX AND OTHER LAWS MAY ADVERSELY AFFECT UNITHOLDERS. 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 allowance, may in the future be changed or interpreted in a manner that adversely affects us and our Unitholders. The Tax Act provides that a trust will permanently lose its "mutual fund trust" status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted to mean that the majority of unitholders must not be non-residents of Canada), unless at all times after February 21, 1990, "all or substantially all" of the trust's property consisted of property other than taxable Canadian property (the "TCP EXCEPTION"). Based on the most recent information obtained by us through our transfer agent and financial intermediaries, in February 2007 an estimated 70% of our issued and outstanding Trust Units were held by non-residents of Canada (as defined in the Tax Act) at that time. We are currently able to take advantage of the TCP Exception, and as a result, the Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by non-residents. There is no assurance that the TCP Exception will continue to be available to the Trust or that the Canadian federal government will not introduce new changes or proposals to tax regulations directed at non-resident ownership which, given our level of non-resident ownership, may result in us losing our mutual fund trust status or could otherwise detrimentally affect us and the market price of the Trust Units. We intend to continue to take the necessary measures in order to ensure that we continue to qualify as a mutual fund trust under the Tax Act. There would be material adverse consequences if we lost our status as a mutual fund trust under Canadian tax laws. See "CHANGES IN LEGISLATION - MATERIAL ADVERSE TAX CONSEQUENCES TO LOSS OF MUTUAL FUND TRUST STATUS". We may not be able to take steps necessary to ensure that we maintain our mutual fund trust status. Even if we are successful in taking such measures, these measures could be adverse to certain holders of Trust Units, particularly "non-residents" of Canada (as defined in the Tax Act). There can be no assurance that such circumstances would not detrimentally affect the market price of the Trust Units. Additionally, legislation may be implemented to limit the investment in income funds and royalty trusts by certain investors or to change the manner in which these entities are taxed. Tax authorities having jurisdiction over us or our Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practices to our detriment or the detriment of our Unitholders. 72 CHANGES IN LEGISLATION - MATERIAL ADVERSE TAX CONSEQUENCES TO LOSS OF MUTUAL FUND TRUST STATUS 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 we 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. 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 73 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 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 74 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 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. Notwithstanding the provisions of the Trust Indenture and the fact that Alberta (our governing jurisdiction) has adopted legislation purporting to limit trust unitholder liability, because of uncertainties in the law relating to investment trusts, there is a risk that a Unitholder could be held personally liable for obligations of the Trust in respect of contracts or undertakings which the Trust enters into and for certain liabilities arising otherwise than out of 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. 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. 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. 75 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. RISKS PARTICULAR TO UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS In addition to the risk factors set forth above, the following risk factors are particular to unitholders who are not residents of Canada. UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS MAY BE SUBJECT TO ADDITIONAL TAXATION. The Tax Act and the tax treaties between Canada and other countries may impose additional withholding or other taxes on the cash distributions or other property paid by us to Unitholders who are not residents of Canada, and these taxes may change from time to time. For instance, since January 1, 2005, a 15% withholding tax is applied to return of capital portion of distributions made to non-resident unitholders. Additionally, the reduced "Qualified Dividend" rate of 15% tax applied to our distributions under current U.S. tax laws is scheduled to expire at the end of 2010 and there is no assurance that this reduced tax rate will be renewed by the U.S. government at such time. Furthermore, it is unclear what impact the proposed changes relating to the October 31, 2006 Proposals will have on the taxation of cash distributions or other property paid by the Trust to unitholders who are not residents of Canada. NON-RESIDENT UNITHOLDERS ARE SUBJECT TO FOREIGN EXCHANGE RISK ON THE DISTRIBUTIONS THAT THEY MAY RECEIVE FROM THE TRUST. Distributions from the Trust are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, investors are subject to foreign exchange risk. To the extent that the Canadian dollar weakens with respect to the currency of a non-resident, the amount of the distribution will be reduced when converted to the home currency of a non-resident. THE ABILITY OF UNITED STATES AND OTHER NON-RESIDENT UNITHOLDERS INVESTORS TO ENFORCE CIVIL REMEDIES MAY BE LIMITED. We are a trust organized under the laws of Alberta, Canada, and our principal place of business is in Canada. All of the directors and officers of AOG are residents of Canada and most of the experts who provide services to us (such as its auditors and some of its independent reserve engineers) are residents of Canada, and all or a substantial portion of their assets and our assets are located within Canada. As a result, it may be difficult for investors in the United States or other non-Canadian jurisdictions (a "FOREIGN JURISDICTION") to effect service of process within such Foreign Jurisdiction upon such directors, officers and representatives of experts who are not residents of the Foreign Jurisdiction or to enforce against them judgments of courts of the applicable Foreign Jurisdiction based upon civil liability under the securities laws of such Foreign Jurisdiction, including United States federal securities laws or the securities laws of any state within the United States. In particular, there is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or the securities laws of any state within the United States. DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE As a Canadian issuer listed on the New York Stock Exchange (the "NYSE"), we are not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic requirements. As a foreign private issuer, we 76 are only required to comply with three of the NYSE Rules: 1) have an audit committee that satisfies the requirements of the United States Securities Exchange Act of 1934; 2) the Chief Executive Officer must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE Rules; and 3) provide a brief description of any significant differences between our corporate governance practices and those followed by U.S. companies listed under the NYSE. We have reviewed the NYSE listing standards and confirm that our corporate governance practices do not differ significantly from such standards. 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 provided in our financial statements and management's discussion and analysis for the year ended December 31, 2006. Documents affecting the rights of securityholders, along with additional information relating to Advantage, may be found on SEDAR at www.sedar.com. 77 SCHEDULE "A" REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION Management of the Trust 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, 2006 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, 2006 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. /s/ Kelly I. Drader /s/ Peter A. Hanrahan ------------------------------ -------------------------------- Kelly I. Drader Peter A. Hanrahan Chief Executive Officer Vice President, Finance and Chief Financial Officer /s/ Ronald A. Mcintosh /s/ John Howard ------------------------------ -------------------------------- Ronald A. McIntosh John Howard Director Director March 21, 2007 SCHEDULE "B" FORM 51-101F2 - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR 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, 2006. The reserves data consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 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, 2006 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 on our evaluation. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE HANDBOOK") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). 3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions 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, 2006, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Trust's management and 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 Reserves of Advantage Energy Income Fund as of December 31, 2006 prepared October 2006 to March 2007 TOTAL 170,226 1,679,848 Nil 1,850,074
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook. 6. We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date. 7. Because the reserves data are based upon judgments regarding future events, actual results will vary and the variations may be material. /s/ Sproule Associates Limited ---------------------------------- SPROULE ASSOCIATES LIMITED Calgary, Alberta March 9, 2007