EX-99 98 ex99-95form40_f.txt EXHBIT 99.95 EXHIBIT 99.95 ------------- NO SECURITIES REGULATORY AUTHORITY HAS EXPRESSED AN OPINION ABOUT THESE SECURITIES AND IT IS AN OFFENCE TO CLAIM OTHERWISE. THIS SHORT FORM PROSPECTUS CONSTITUTES A PUBLIC OFFERING OF THESE SECURITIES ONLY IN THOSE JURISDICTIONS WHERE THEY MAY BE LAWFULLY OFFERED FOR SALE AND THEREIN ONLY BY PERSONS PERMITTED TO SELL SUCH SECURITIES. THESE SECURITIES HAVE NOT BEEN AND WILL NOT BE REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED, OR ANY STATE SECURITIES LAWS. ACCORDINGLY, THESE SECURITIES MAY NOT BE OFFERED OR SOLD WITHIN THE UNITED STATES AND THIS SHORT FORM PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THESE SECURITIES WITHIN THE UNITED STATES. SEE "PLAN OF DISTRIBUTION". NEW ISSUE SEPTEMBER 3, 2004 SHORT FORM PROSPECTUS [GRAPHIC OMITTED] [LOGO - ADVANTAGE ENERGY INCOME FUND] $65,800,000 3,500,000 SUBSCRIPTION RECEIPTS, EACH REPRESENTING THE RIGHT TO RECEIVE ONE TRUST UNIT AND $75,000,000 7.50% EXTENDIBLE CONVERTIBLE UNSECURED SUBORDINATED DEBENTURES AND $50,000,000 7.75% EXTENDIBLE CONVERTIBLE UNSECURED SUBORDINATED DEBENTURES SUBSCRIPTION RECEIPTS Advantage Energy Income Fund (the "TRUST" or "ADVANTAGE") is hereby qualifying for distribution 3,500,000 subscription receipts ("SUBSCRIPTION RECEIPTS"), each of which will entitle the holder thereof to receive, without payment of additional consideration, one trust unit ("UNIT" or "TRUST UNIT") of the Trust upon closing of the acquisition (the "ACQUISITION") by Advantage Oil & Gas Ltd. ("AOG"), a wholly-owned subsidiary of the Trust, of certain petroleum and natural gas properties and related assets currently owned by Anadarko Canada Corporation ("ANADARKO") described in more detail under "Recent Developments - Acquisition". The proceeds from the sale of the Subscription Receipts (the "ESCROWED FUNDS") will be held by Computershare Trust Company of Canada, as escrow agent (the "ESCROW AGENT"), and invested in short-term obligations of, or guaranteed by, the Government of Canada (and other approved investments) pending completion of the Acquisition. Upon the Acquisition being completed on or before November 1, 2004, the Escrowed Funds and the interest thereon will be released to the Trust and the Units will be issued to the holders of Subscription Receipts. The Trust will utilize the Escrowed Funds and the proceeds from the sale of Debentures described below to pay a portion of the purchase price for the Acquisition. If the closing of the Acquisition does not take place by 5:00 p.m. (Calgary time) on November 1, 2004, or if the Acquisition Agreement or any amendment thereto is terminated at any earlier time or if the Trust has advised the Underwriters or announced to the public that it does not intend to proceed with the Acquisition (in any case, the "TERMINATION TIME"), holders of Subscription Receipts shall be entitled to receive an amount equal to the full subscription price therefor and their PRO RATA entitlements to interest on such amount. The Escrowed Funds and interest earned thereon will be applied towards payment of such amount. If the closing of the Acquisition takes place prior to the Termination Time and holders of Subscription Receipts become entitled to receive Units, such holders will be entitled to receive an amount per Subscription Receipt equal to the amount per Unit of any cash distributions for which record dates have occurred during the period from the date of closing of the offering to the date immediately preceding the date the Units are issued pursuant to the 2 Subscription Receipts. Accordingly, if the Acquisition closes on or before September 30, 2004 as currently contemplated, holders of Subscription Receipts will become holders of Units on or before September 30, 2004 and will be entitled, provided they are the holders of record of Units received pursuant to the Subscription Receipts on September 30, 2004, to receive the monthly distribution expected to be paid on October 15, 2004 to Unitholders of record on September 30, 2004. If the closing of the Acquisition occurs after September 30, 2004, but on or before November 1, 2004, holders of record of Subscription Receipts on the date they are exchanged for Units will be entitled to receive a payment equivalent to the distribution that will be paid by the Trust to Unitholders of record on September 30, 2004 or any subsequent Unit distribution record date (being on or about the last day of each month) prior to such closing. See "Details of the Offering". 7.50% DEBENTURES The Trust is also hereby qualifying for distribution 75,000 7.50% extendible convertible unsecured subordinated debentures (the "7.50% DEBENTURES") of the Trust at a price of $1,000 per Debenture. The 7.50% Debentures have an initial maturity date of November 1, 2004 (the "INITIAL MATURITY DATE"). If the closing of the Acquisition takes place by the Termination Time, the maturity date will be automatically extended from the Initial Maturity Date to October 1, 2009 (the "7.50% FINAL MATURITY DATE"). If closing of the Acquisition does not take place by the Termination Time, the 7.50% Debentures will mature on the Initial Maturity Date. See "Details of the Offerings". The 7.50% Debentures bear interest at an annual rate of 7.50% payable semi-annually on April 1 and October 1 in each year commencing April 1, 2005. The 7.50% Debentures are redeemable by the Trust at a price of $1,050 per 7.50% Debenture after October 1, 2007 and on or before October 1, 2008 and at a price of $1,025 per 7.50% Debenture after October 1, 2008 and before maturity on October 1, 2009, in each case, plus accrued and unpaid interest thereon, if any. See "Details of the Offerings". -------------------------------------------------------------------------------- 7.50% DEBENTURE CONVERSION PRIVILEGE Each 7.50% Debenture will be convertible into Units at the option of the holder at any time prior to the close of business on the earlier of maturity and the business day immediately preceding the date specified by the Trust for redemption of the 7.50% Debentures, at a conversion price of $20.25 per Unit, subject to adjustment in certain events. Holders converting their 7.50% Debentures will receive accrued and unpaid interest thereon. Notwithstanding the foregoing, no Debentures may be converted during the three business days preceding April 1 and October 1, in each year, commencing April 1, 2005, as the registers of the Debenture Trustee will be closed during such periods. -------------------------------------------------------------------------------- 7.75% DEBENTURES The Trust is also hereby qualifying for distribution 50,000 7.75% extendible convertible unsecured subordinated debentures (the "7.75% DEBENTURES") of the Trust at a price of $1,000 per Debenture. The 7.75% Debentures have an initial maturity date of November 1, 2004. If the closing of the Acquisition takes place by the Termination Time, the maturity date will be automatically extended from the Initial Maturity Date to December 1, 2011 (the "7.75% FINAL MATURITY DATE"). If closing of the Acquisition does not take place by the Termination Time, the 7.75% Debentures will mature on the Initial Maturity Date. See "Details of the Offerings". The 7.75% Debentures bear interest at an annual rate of 7.75% payable semi-annually on June 1 and December 1 in each year commencing June 1, 2005. The 7.75% Debentures are redeemable by the Trust at a price of $1,050 per 7.75% Debenture after December 1, 2007, and on or before December 1, 2008, at a price of $1,025 per 7.75% Debenture after December 1, 2008 and on or before December 1, 2009 and at a price of $1,000 per 7.75% Debenture after December 1, 2009 and before maturity on December 1, 2011, in each case, plus accrued and unpaid interest thereon, if any. See "Details of the Offerings". 3 -------------------------------------------------------------------------------- 7.75% DEBENTURE CONVERSION PRIVILEGE Each 7.75% Debenture will be convertible into Units at the option of the holder at any time prior to the close of business on the earlier of maturity and the business day immediately preceding the date specified by the Trust for redemption of the 7.75% Debentures, at a conversion price of $21.00 per Unit, subject to adjustment in certain events. Holders converting their 7.75% Debentures will receive accrued and unpaid interest thereon. Notwithstanding the foregoing, no 7.75% Debentures may be converted during the three business days preceding June 1 and December 1, in each year, commencing June 1, 2005, as the registers of the Debenture Trustee will be closed during such periods. -------------------------------------------------------------------------------- In the opinion of counsel, subject to the qualifications and assumptions discussed under the headings "Canadian Federal Income Tax Considerations" and "Eligibility for Investment", on the date of closing, the Subscription Receipts, the Debentures and the Units issuable pursuant to the Subscription Receipts and on conversion, redemption or maturity of the Debentures, will be qualified investments under the INCOME TAX ACT (Canada) and the regulations thereunder for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans (except, in the case of the Debentures, a deferred profit sharing plan to which the Trust has made a contribution) and registered education savings plans. The issued and outstanding Units are listed on the Toronto Stock Exchange (the "TSX") under the trading symbol AVN.UN. On August 23, 2004, the last trading day prior to the public announcement of the offering, and on September 2, 2004, the closing price of the Units on the TSX was $19.35 and $19.96, respectively. The TSX has conditionally approved the listing of the Subscription Receipts, the Debentures and the Units issuable pursuant to the Subscription Receipts and on the conversion, redemption and maturity of the Debentures. Listing is subject to the Trust fulfilling all of the listing requirements of the TSX on or before November 24, 2004. The offering price of the Subscription Receipts and Debentures was determined by negotiation between Advantage Investment Management Ltd. (the "MANAGER") and AOG on behalf of the Trust, and Scotia Capital Inc., on its own behalf and on behalf of BMO Nesbitt Burns Inc., National Bank Financial Inc., RBC Dominion Securities Inc., CIBC World Markets Inc., FirstEnergy Capital Corp. and Raymond James Ltd. (collectively, the "UNDERWRITERS").
NET PROCEEDS PRICE TO THE PUBLIC UNDERWRITERS' FEE(1) TO THE TRUST (2) ------------------- -------------------- ---------------- Per Subscription Receipt $ 18.80 $ 0.94 $ 17.86 Total $ 65,800,000 $ 3,290,000 $ 62,510,000 Per 7.50% Debenture $ 1,000 $ 40 $ 960 Total $ 75,000,000 $ 3,000,000 $ 72,000,000 Per 7.75% Debenture $ 1,000 $ 40 $ 960 Total $ 50,000,000 $ 2,000,000 $ 48,000,000 TOTAL $190,800,000 $ 8,290,000 $182,510,000
Notes: (1) The Underwriters' fee with respect to the Subscription Receipts is payable as to 50% upon the closing of the offering and 50% on the release of the Escrowed Funds to the Trust. If the Acquisition is not completed, the Underwriters' fee with respect to the Subscription Receipts will be reduced to the amount payable upon closing of the offering. (2) Excluding interest, if any, on the Escrowed Funds and before deducting expenses of the offering estimated to be $600,000, which will be paid from the general funds of the Trust. The Underwriters, as principals, conditionally offer the Subscription Receipts and the Debentures, subject to prior sale, if, as and when issued by the Trust and delivered and accepted by the Underwriters in accordance with the conditions contained in the Underwriting Agreement referred to under "Plan of Distribution" and subject to approval of certain legal matters relating to the offering on behalf of the Trust by Burnet, Duckworth & Palmer LLP and on behalf of the Underwriters by Macleod Dixon LLP. 4 SCOTIA CAPITAL INC., BMO NESBITT BURNS INC., NATIONAL BANK FINANCIAL INC. AND RBC DOMINION SECURITIES INC., FOUR OF THE UNDERWRITERS, ARE INDIRECT WHOLLY-OWNED SUBSIDIARIES OF CANADIAN CHARTERED BANKS WHICH ARE LENDERS TO THE TRUST. CONSEQUENTLY, THE TRUST MAY BE CONSIDERED TO BE A CONNECTED ISSUER OF THESE UNDERWRITERS FOR THE PURPOSES OF SECURITIES REGULATIONS IN CERTAIN PROVINCES. A PORTION OF THE NET PROCEEDS OF THIS OFFERING RECEIVED BY THE TRUST WILL BE USED TO REDUCE THE INDEBTEDNESS OF THE TRUST TO SUCH BANKS. SEE "RELATIONSHIP AMONG THE TRUST AND CERTAIN UNDERWRITERS" AND "USE OF PROCEEDS". THERE IS CURRENTLY NO MARKET THROUGH WHICH THE SUBSCRIPTION RECEIPTS OR DEBENTURES MAY BE SOLD AND PURCHASERS MAY NOT BE ABLE TO RESELL SUBSCRIPTION RECEIPTS OR DEBENTURES PURCHASED UNDER THIS SHORT FORM PROSPECTUS. Subscriptions for Subscription Receipts and Debentures will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without notice. It is expected that closing will occur on or about September 14, 2004 or such other date as the Trust and the Underwriters may agree. The Subscription Receipts will be represented by a global certificate issued in registered form to the Canadian Depository for Securities Limited ("CDS") or its nominee under the book-based system administered by CDS. Certificates for the aggregate principal amount of the 7.50% Debentures and 7.75% Debentures will be issued in registered form to CDS and will be deposited with CDS on the date of closing. No certificates evidencing the Subscription Receipts, 7.50% Debentures and 7.75% Debentures will be issued to subscribers except in certain limited circumstances, and registration will be made in the depositary service of CDS. Subscribers for Subscription Receipts and Debentures will receive only a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficial interest in the Subscription Receipts or Debentures is purchased. Subject to applicable laws, the Underwriters may, in connection with the offering, effect transactions which stabilize or maintain the market price of the Subscription Receipts, the Units or the Debentures at levels other than those that might otherwise prevail on the open market. See "Plan of Distribution". THE SUBSCRIPTION RECEIPTS, THE UNITS AND THE DEBENTURES 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, IT 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. 5 TABLE OF CONTENTS Page SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS.............................6 SELECTED ABBREVIATIONS........................................................7 DEFINITIONS...................................................................7 NON-GAAP MEASURES............................................................13 DOCUMENTS INCORPORATED BY REFERENCE..........................................14 ADVANTAGE ENERGY INCOME FUND.................................................15 DESCRIPTION OF BUSINESS......................................................15 RECENT DEVELOPMENTS..........................................................16 INFORMATION CONCERNING THE ASSETS............................................18 EFFECT OF THE ACQUISITION ON THE TRUST.......................................28 DESCRIPTION OF TRUST UNITS...................................................30 EARNINGS COVERAGE............................................................31 CONSOLIDATED CAPITALIZATION OF THE TRUST.....................................32 PRICE RANGE AND TRADING VOLUME OF THE TRUST UNITS............................33 RECORD OF CASH DISTRIBUTIONS.................................................33 USE OF PROCEEDS..............................................................35 DETAILS OF THE OFFERINGS.....................................................35 PLAN OF DISTRIBUTION.........................................................43 RELATIONSHIP AMONG THE TRUST AND CERTAIN UNDERWRITERS........................44 INTEREST OF EXPERTS..........................................................44 CANADIAN FEDERAL INCOME TAX CONSIDERATIONS...................................44 ELIGIBILITY FOR INVESTMENT...................................................50 RISK FACTORS.................................................................50 MATERIAL CONTRACTS...........................................................52 LEGAL PROCEEDINGS............................................................52 AUDITORS, TRANSFER AGENT AND REGISTRAR.......................................52 STATUTORY AND CONTRACTUAL RIGHTS OF RESCISSION AND STATUTORY RIGHTS OF WITHDRAWAL.........................................................52 AUDITORS' CONSENT............................................................53 AUDITORS' CONSENT............................................................53 AUDITORS' CONSENT............................................................53 SCHEDULE "A" - UNAUDITED PROFORMA CONSOLIDATED FINANCIAL STATEMENTS A-1 SCHEDULE "B" - SCHEDULE OF REVENUES AND EXPENSES B-1 SCHEDULE "C" - UNAUDITED FINANCIAL STATEMENTS OF MARKWEST RESOURCES CANADA CORP. FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2003 C-1 CERTIFICATE OF THE TRUST D-1 CERTIFICATE OF THE UNDERWRITERS D-2 6 SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements contained in this short form prospectus, and in certain documents incorporated by reference into this short form prospectus, constitute forward-looking statements. These statements relate to future events or the Trust's 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. The Trust and AOG believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this short form prospectus should not be unduly relied upon. These statements speak only as of the date of this short form prospectus or as of the date specified in the documents incorporated by reference into this short form prospectus, as the case may be. In particular, this short form prospectus, and the documents incorporated by reference, contain forward-looking statements pertaining to the following: o the timing of the closing of the proposed Acquisition; o the performance characteristics of the Trust's assets and the 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 short form prospectus: 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 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 short form prospectus and the documents incorporated by reference herein are expressly qualified by this cautionary statement. Neither the Trust, the Manager, nor AOG undertakes any obligation to publicly update or revise any forward-looking statements. 7 SELECTED ABBREVIATIONS In this short form prospectus, the abbreviations set forth below have the meanings indicated: "BBL" means one barrel "BOE/D" means barrels of oil equivalent per day "BBLS" means barrels "MBBLS" means one thousand barrels "BBLS/D" means barrels per day "MBOE" means one thousand barrels of oil equivalent "BCF" means one billion cubic feet "MMBOE" means one million barrels of oil equivalent "BOE" means barrels of oil equivalent. A "MCF" means one thousand cubic feet barrel of oil equivalent is determined by converting a volume of natural gas to barrels "MMCF" means one million cubic feet using the ratio of six mcf to one barrel. Boes may be misleading, particularly if used "MMCF/D" means one million cubic feet per day in isolation. The boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency "NGL" means natural gas liquids method primarily applicable at the burner tip and does not represent a value equivalency at "$M" or "M$" means thousands of dollars the wellhead.
DEFINITIONS In this short form prospectus, the terms set forth below have the meanings indicated: "7.50% DEBENTURES" means the 7.50% extendible convertible unsecured subordinated debentures of the Trust offered hereby; "7.50% FINAL MATURITY DATE" means October 1, 2009; "7.75% DEBENTURES" means the 7.75% extendible convertible unsecured subordinated debentures of the Trust offered hereby; "7.75% FINAL MATURITY DATE" means December 1, 2011; "8.25% DEBENTURES" means the 8.25% convertible unsecured subordinated debentures of the Trust due February 1, 2009; "8.50% NOTES" means the 8.50% unsecured subordinated promissory notes of AOG issued on December 2, 2003; "9.00% DEBENTURES" means the 9.00% convertible unsecured subordinated debentures of the Trust due August 1, 2008; "9 3/8% NOTES" means the 9 3/8% unsecured promissory notes of AOG issued on July 8, 2003; "10.00% DEBENTURES" means the 10.00% convertible unsecured subordinated debentures of the Trust due November 1, 2007; "10 3/8% NOTES" means the 10 3/8% unsecured promissory notes of AOG issued on October 18, 2002; "ABCA" means the BUSINESS CORPORATIONS ACT (Alberta), R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder; "ACQUISITION" means the acquisition by AOG, pursuant to the Acquisition Agreement, of the Assets; 8 "ACQUISITION AGREEMENT" means the Agreement of Purchase and Sale dated August 24, 2004 between Anadarko and AOG pursuant to which Anadarko agreed to sell and AOG agreed to purchase the Assets; "AIF" means the Renewal Annual Information Form of the Trust for the year ended December 31, 2003 dated May 12, 2004; "ANADARKO" means Anadarko Canada Corporation, the managing partner of Anadarko Canada Resources; "AOG" 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; "ARC" means credits or rebates in respect of Crown royalties which are paid or credited by the Crown, including those paid or credited under the ALBERTA CORPORATE TAX ACT which are commonly known as "Alberta Royalty Credits"; "ASSETS" means those petroleum and natural gas properties and related assets that the Trust will indirectly own following completion of the Acquisition, described in more detail under "Information Concerning the Assets"; "BUSINESS DAY" means a day, which is not a Saturday, Sunday or statutory holiday, when banks in the place at which any action is required to be taken hereunder are generally open for the transaction of commercial banking business; "CONSTANT PRICES AND COSTS" means prices and costs used in an estimate that are: (a) the issuer's prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies; and (b) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the issuer is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a); "CREDIT FACILITIES" has the meaning ascribed thereto in Note 1 to the table under "Consolidated Capitalization of the Trust"; "DEBENTURE TRUSTEE" means Computershare Trust Company of Canada or its successor as trustee under the Indenture; "DEBENTURES" means collectively, the 7.50% Debentures and the 7.75% Debentures; "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; 9 (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; "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 certainty; "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; "DEVELOPMENT WELL" means a well drilled inside the established limits of an oil and gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive; "ESCROW AGENT" means Computershare Trust Company of Canada or its successor as escrow agent under the Subscription Receipt Agreement; "ESCROWED FUNDS" means the proceeds from the sale of the Subscription Receipts; "EXPLORATION COSTS" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas Reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies; (b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records; (c) dry hole contributions and bottom hole contributions; (d) costs of drilling and equipping exploratory wells; and (e) costs of drilling exploratory type stratigraphic test wells; "FORECAST PRICES AND COSTS" means future prices and costs that are: (a) generally acceptable as being a reasonable outlook of the future; and (b) if and only to the extent that, there are fixed or presently determinable future prices or costs to which the issuer is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a); "GROSS" means: (a) in relation to an issuer's interest in production or Reserves, its "issuer gross Reserves", which are the issuer's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of such issuer; 10 (b) in relation to wells, the total number of wells in which the issuer has an interest; and (c) in relation to properties, the total area of properties in which the issuer has an interest; "INDENTURE" means, collectively, the trust indenture dated July 8, 2003 between the Trust, AOG and the Debenture Trustee and a second supplemental trust indenture to be dated as of the date of closing of the offering between the Trust, AOG and the Debenture Trustee governing the terms of the Debentures; "INITIAL MATURITY DATE" means November 1, 2004; "MANAGEMENT AGREEMENT" means the management, advisory and administration agreement dated May 24, 2001, as amended, among 925212 Alberta Ltd., the Manager and the Trustee, on behalf of the Trust; "MANAGER" means Advantage Investment Management Ltd., a corporation incorporated under the ABCA; "MARKWEST" means MarkWest Resources Canada Corp., a corporation incorporated under the ABCA which was acquired by AOG on December 2, 2003; "NET" means: (a) in relation to an issuer's interest in production or Reserves, its "issuer gross Reserves", which are the issuer's working interest (operating and non-operating) share after deduction of royalty obligations, plus the issuer's royalty interest in production or Reserves; (b) in relation to wells, the number of wells obtained by aggregating the issuer's working interest in each of its Gross wells; and (c) in relation to the issuer's interest in a property, the total area in which the issuer has an interest multiplied by the working interest owned by the issuer; "NOTES" means the 14% unsecured subordinated promissory notes of AOG originally issued on May 24, 2001; "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; "PERMITTED INVESTMENTS" means, with respect to up to 25% of the total assets of the Trust (unless otherwise approved by AOG's 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 maturing within 180 days after the date of acquisition; and (iv) trust units and limited partnership units in trusts and limited partnerships which invest in energy related assets, including all types of petroleum and natural gas and energy related assets, and including, without limitation, facilities of any kind, oil sands interests, coal, electricity or power generating assets, and pipeline, gathering, processing and transportation assets; "PETROLEUM SUBSTANCES" means petroleum, natural gas and related hydrocarbons (except coal) including, without limitation, all liquid hydrocarbons, and all other substances, including sulphur, whether gaseous, liquid or solid and whether hydrocarbon or not, produced in association with such petroleum, natural gas or related hydrocarbons; "PROVED RESERVES" are those Reserves that can be estimated with a high degree of certainty to be recoverable. There is believed to be at least a 90% probability that the quantities actually recovered will equal or exceed the estimated Proved Reserves; 11 "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 lesser than the sum of the estimated Proved plus Probable Reserves. There is believed to be at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable Reserves; "REDEMPTION NOTES" means notes issued in certain circumstances including by the Trust on a redemption of Trust Units; "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 (a) analysis of drilling, geological, geophysical and engineering data; (b) the use of established technology; and (c) specified economic conditions which are generally accepted as being reasonable; "ROYALTY" means the 95% interest in AOG's Petroleum Substances within, upon or under certain of its Oil and Natural Gas Properties granted pursuant to the Royalty Agreement; "ROYALTY AGREEMENT" means the amended and restated royalty agreement entered into between AOG and the Trust dated as of December 1, 2003 and providing for the creation of the Royalty; "SETTLED AMOUNT" means the amount of one hundred dollars in lawful money of Canada paid by the settlor of the Trust to the Trustee for the purpose of settling the Trust; "SPROULE" means Sproule Associates Limited, independent geological and petroleum engineering consultants of Calgary, Alberta; "SPROULE ANADARKO REPORT" means the independent engineering evaluation effective July 1, 2004 of the oil, NGL and natural gas Reserves and the present worth value of these Reserves for the oil, NGL and natural gas interests of Anadarko in the Assets prepared by Sproule, based on forecast and constant prices and costs as at July 1, 2004; "SUBSCRIPTION RECEIPT AGREEMENT" means the agreement to be dated the date of closing of the offering among the Trust, the Underwriters and the Escrow Agent governing the terms of the Subscription Receipts; "SUBSCRIPTION RECEIPTS" means the subscription receipts of the Trust offered hereby; "TAX ACT" means the INCOME TAX ACT (Canada), R.S.C. 1985, c. 1 (5th Supp), as amended, including the regulations promulgated thereunder; "TRUST" or "ADVANTAGE" means Advantage Energy Income Fund, a trust established under the laws of Alberta pursuant to the Trust Indenture. All references to the "Trust" or "Advantage", unless the context otherwise requires, are references to Advantage Energy Income Fund, its predecessors, and its subsidiaries; "TRUSTEE" means Computershare Trust Company of Canada or such other trustee, from time to time, of the Trust; "TRUST INDENTURE" means the trust indenture between Computershare Trust Company of Canada and AOG made as of April 17, 2001, supplemented as of May 22, 2002 and amended and restated as of June 25, 2002, May 28, 2003 and May 26, 2004; "TSX" means the Toronto Stock Exchange; "UNDERWRITERS" means, collectively, Scotia Capital Inc., BMO Nesbitt Burns Inc., National Bank Financial Inc. RBC Dominion Securities Inc., CIBC World Markets Inc., FirstEnergy Capital Corp. and Raymond James Ltd.; 12 "UNDERWRITING AGREEMENT" means the agreement dated August 24, 2004 among the Trust, AOG, the Manager and the Underwriters in respect of this offering; "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 (eg., Proved or Probable) to which they are assigned; "UNITED STATES" or "U.S." means the United States of America; "UNITHOLDERS" means the holders from time to time of the Units; and "UNITS" or "TRUST UNITS" means trust units of the Trust. Words importing the singular number only include the plural, and VICE VERSA, and words importing any gender include all genders. All dollar amounts set forth in this short form prospectus are in Canadian dollars, except where otherwise indicated. 13 NON-GAAP MEASURES In this prospectus, the Trust uses the terms "cash flow", "funds flow from operations" and "cash available for distribution" to refer to the amount of cash available for distribution to Unitholders and as indicators of financial performance. "Cash flow", "funds flow from operations" and "cash available for distribution" are not measures recognized by Canadian generally accepted accounting principles ("GAAP") and do not have standardized meanings prescribed by GAAP. Therefore, "cash flow", "funds flow from operations" and "cash available for distribution" of the Trust may not be comparable to similar measures presented by other issuers, and investors are cautioned that "cash flow", "funds flow from operations" and "cash available for distribution" should not be construed as alternatives to net earnings, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. All references to "cash flow" and "funds flow from operations" are based on cash flow before changes in non-cash working capital related to operating activities, as presented in the consolidated financial statements of the Trust. Cash available for distribution cannot be assured and future distributions may vary. The Trust uses such terms and, particularly, "cash available for distribution" as an indicator of financial performance because such terms are commonly utilized by investors to evaluate royalty trusts and income funds in the oil and gas sector. The Trust believes that "cash available for distribution" is a useful supplemental measure as it provides investors with information of what cash is available for distribution from the Trust to Unitholders in such periods. 14 DOCUMENTS INCORPORATED BY REFERENCE INFORMATION HAS BEEN INCORPORATED BY REFERENCE IN THIS SHORT FORM PROSPECTUS FROM DOCUMENTS FILED WITH SECURITIES COMMISSIONS OR SIMILAR AUTHORITIES IN CANADA. Copies of the documents incorporated herein by reference may be obtained on request without charge from the Vice President, Finance and Chief Financial Officer of AOG at Suite 3100, 150 - 6th Avenue S.W., Calgary, Alberta T2P 3H7, telephone (403) 261-8810. For the purpose of the Province of Quebec, this simplified prospectus contains information to be completed by consulting the permanent information record. A copy of the permanent information record may be obtained from the Vice President, Finance and Chief Financial Officer of Advantage at the above-mentioned address and telephone number. The following documents of the Trust, filed with the various securities commissions or similar authorities in the provinces of Canada, are specifically incorporated by reference into and form an integral part of this short form prospectus: 1. the Trust's Revised Renewal Annual Information Form (the "AIF") dated May 12, 2004; 2. the audited comparative consolidated financial statements of the Trust for the years ended December 31, 2003 and 2002, together with the report of the auditors' thereon; 3. management's discussion and analysis of Advantage for the year ended December 31, 2003; 4. the information circular - proxy statement of the Trust dated April 16, 2004 relating to the annual and special meeting of holders of Trust Units held on May 26, 2004 (excluding those portions thereof which appear under the headings "Performance Chart" and "Corporate Governance"); and 5. the unaudited interim comparative consolidated financial statements of the Trust and management's discussion and analysis of the financial condition and operations of the Trust as at and for the three and six month periods ended June 30, 2004 and 2003. Any material change reports (excluding confidential reports), comparative interim financial statements and information circulars (excluding those portions that are not required pursuant to National Instrument 44-101 of the Canadian Securities Administrators to be incorporated by reference herein) filed by the Trust with the securities commissions or similar authorities in the provinces of Canada subsequent to the date of this short form prospectus and prior to the termination of this distribution shall be deemed to be incorporated by reference in this short form prospectus. ANY STATEMENT CONTAINED IN A DOCUMENT INCORPORATED OR DEEMED TO BE INCORPORATED BY REFERENCE HEREIN SHALL BE DEEMED TO BE MODIFIED OR SUPERSEDED FOR THE PURPOSES OF THIS SHORT FORM PROSPECTUS TO THE EXTENT THAT A STATEMENT CONTAINED HEREIN OR IN ANY OTHER SUBSEQUENTLY FILED DOCUMENT WHICH ALSO IS, OR IS DEEMED TO BE, INCORPORATED BY REFERENCE HEREIN MODIFIES OR SUPERSEDES SUCH STATEMENT. THE MODIFYING OR SUPERSEDING STATEMENT NEED NOT STATE THAT IT HAS MODIFIED OR SUPERSEDED A PRIOR STATEMENT OR INCLUDE ANY OTHER INFORMATION SET FORTH IN THE DOCUMENT THAT IT MODIFIES OR SUPERSEDES. THE MAKING OF A MODIFYING OR SUPERSEDING STATEMENT SHALL NOT BE DEEMED AN ADMISSION FOR ANY PURPOSES THAT THE MODIFIED OR SUPERSEDED STATEMENT, WHEN MADE, CONSTITUTED A MISREPRESENTATION, AN UNTRUE STATEMENT OF A MATERIAL FACT OR AN OMISSION TO STATE A MATERIAL FACT THAT IS REQUIRED TO BE STATED OR THAT IS NECESSARY TO MAKE A STATEMENT NOT MISLEADING IN LIGHT OF THE CIRCUMSTANCES IN WHICH IT WAS MADE. ANY STATEMENT SO MODIFIED OR SUPERSEDED SHALL NOT BE DEEMED, EXCEPT AS SO MODIFIED OR SUPERSEDED, TO CONSTITUTE A PART OF THIS SHORT FORM PROSPECTUS. 15 ADVANTAGE ENERGY INCOME FUND ADVANTAGE ENERGY INCOME FUND, ADVANTAGE OIL & GAS LTD. AND ADVANTAGE INVESTMENT MANAGEMENT LTD. Advantage Energy Income Fund is an entity that provides monthly cash distributions to its Unitholders. Advantage was created under the laws of the Province of Alberta pursuant to the Trust Indenture. It is, for Canadian tax purposes, an open-ended mutual fund trust and is categorized as a "natural resource issuer" for the purposes of Canadian securities laws. The Trust is administered by the Trustee. The beneficiaries of the Trust are the Unitholders. AOG is an oil and natural gas exploitation and development company that is wholly-owned by the Trust. It was originally incorporated in 1979 as Westrex Energy Corp. ("WESTREX"). Through a plan of arrangement under the ABCA, Westrex merged with Search Energy Inc. on December 31, 1996, and changed its name to Search Energy Corp. ("SEARCH") on January 2, 1997. Effective May 24, 2001, all of the issued and outstanding common shares of Search were acquired by 925212 Alberta Ltd. ("ACQUISITIONCO"), a corporation wholly-owned by the Trust. Search and AcquisitionCo were then amalgamated and continued as "Search Energy Corp.". On July 26, 2001, Search acquired all of the shares of Due West Resources Inc. ("DUE WEST"). Effective August 1, 2001, Search and Due West were amalgamated and continued as "Search Energy Corp.". Effective January 1, 2002, Search acquired a number of natural gas properties located primarily in southern Alberta formerly administered by Gascan Resources Ltd. On June 26, 2002, Search changed its name to Advantage Oil & Gas Ltd. On November 18, 2002, AOG acquired all of the issued and outstanding shares of Best Pacific Resources Ltd. On December 2, 2003, AOG acquired MarkWest. MarkWest was amalgamated with AOG on December 31, 2003. In accordance with the Management Agreement, the Manager has agreed to act as manager of the Trust and AOG. The Manager is a Canadian-owned energy advisory management corporation, incorporated on March 19, 2001, pursuant to the provisions of the ABCA. The head office of the Trust and the Manager and the head office and the registered office of AOG is located at Suite 3100, 150 - 6th Avenue S.W., Calgary, Alberta, T2P 3Y6. The registered office of the Manager is located at Suite 3700, 400 - 3rd Avenue S.W., Calgary, Alberta, T2P 4H2. DESCRIPTION OF BUSINESS ADVANTAGE ENERGY INCOME FUND The principal undertaking of the Trust is to indirectly acquire and hold, through its wholly-owned subsidiary, AOG, interests in petroleum and natural gas properties and assets related thereto. The Trust's primary assets are currently the common shares of AOG, the Royalty, the Notes, the 10 3/8% Notes, the 9 3/8% Notes and the 8.50% Notes. In accordance with the terms of the Trust Indenture, the Trust will make cash distributions to Unitholders of the interest income earned from the Notes, the 10 3/8% Notes, the 9 3/8% Notes, the 8.50% Notes, royalty income earned on the Royalty, dividends (if any) received on, and amounts, if any, received on redemption of, AOG's common shares, non-voting 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. ADVANTAGE OIL & GAS LTD. AOG is actively engaged in the business of oil and gas exploitation, development, acquisition and production in the Provinces of Alberta, British Columbia and Saskatchewan. ADVANTAGE INVESTMENT MANAGEMENT LTD. Pursuant to the Management Agreement, the Manager has agreed to act as manager of the Trust and AOG. The board of directors of AOG has retained the Manager to provide comprehensive management services and has 16 delegated certain authority to the Manager to assist in the administration and regulation of the day-to-day operations of the Trust and AOG and assist in executive decisions which conform to the general policies and general principles previously established by the board of directors of AOG. The Manager is entitled to designate two directors to serve on the board of directors of AOG. The Manager also provides executive officers to AOG, subject to the approval of the board of directors of AOG. RECENT DEVELOPMENTS PROPOSED ACQUISITION OVERVIEW On August 24, 2004, AOG entered into the Acquisition Agreement with Anadarko providing for the acquisition of the Assets for a purchase price (the "PURCHASE PRICE") of approximately $186,000,000 (subject to adjustment). AOG has paid an $18,600,000 deposit (the "DEPOSIT") to Anadarko in connection with the proposed acquisition. The Acquisition is expected to close on or before the later of September 30, 2004 and two Business Days following receipt of approvals under the COMPETITION ACT (Canada) or such other date as Anadarko and AOG may agree in writing. The acquisition will have an effective date of July 1, 2004. AOG is currently conducting a title and an environmental review in respect of the Assets. Concurrently with the announcement of the Acquisition, the Trust announced an increase in the distributions payable on the Trust Units. See "Recent Developments - Distribution Announcement". ASSETS The Assets consist of oil, natural gas and NGL assets located in central Alberta, southern Alberta and southeast Saskatchewan with production weighted approximately 49% light oil and NGLs, 40% natural gas and 11% heavy oil (23o API), which are currently producing approximately 6,250 boe/d, before deduction of royalties owed to others (comprised of approximately 15,500 mcf/d of natural gas, 3,138 bbl/d of oil and 529 bbl/d of NGLs). Approximately 60% of the production from the properties is currently operated by Anadarko with nine properties representing approximately 87% of current production. The Manager believes that the Assets offer numerous low risk infill and development drilling locations and optimization opportunities to enhance production and Reserves. Approximately 8.5% of the current production from the Assets is subject to rights of first refusal. The Acquisition Agreement provides for an adjustment to the Purchase Price to the extent that such rights of first refusal are exercised prior to the closing of the Acquisition. Any excess funds resulting from the exercise of rights of first refusal will be used to reduce bank indebtedness. The Sproule Anadarko Report assigned approximately 13.9 million boe of Proved and Probable Reserves to the Assets effective as at July 1, 2004. Included in the Assets are approximately 149,000 gross (80,000 net) acres of undeveloped land at an average 53% working interest as well as a licensed copy of approximately 1,626 kilometres of 2D seismic data and 407 square kilometres of 3D seismic data to assist the Trust in ongoing identification and evaluation of upside potential associated with the Assets. For more detail regarding the Assets, see "Information Concerning the Assets" and "Effect of the Acquisition on the Trust" for additional information on the Assets. CLOSING CONDITIONS, DEPOSIT AND LIABILITY ARRANGEMENTS Conditions to closing of the Acquisition under the Acquisition Agreement include the following: the continued accuracy of representations and warranties; receipt of customary approvals under the COMPETITION ACT (Canada); and no substantial physical damage of the Assets having occurred prior to closing which would, after deducting amounts Anadarko has agreed to pay and any insurance proceeds in respect of such damages, adversely affect the value of the Assets by more than $2,000,000. In accordance with the terms of the Acquisition Agreement, if the Acquisition is 17 completed, the Deposit will be credited to the Purchase Price. If the Acquisition does not occur due to a failure of AOG to satisfy specified conditions to closing, Anadarko shall be entitled as its sole remedy to retain the Deposit. If the closing does not occur due to a failure of Anadarko to satisfy certain closing conditions, the Deposit will be returned to AOG. In connection with the Acquisition, Anadarko has indemnified AOG in respect of certain liabilities that are a direct result of the breach of the Acquisition Agreement, including any breaches of the representations and warranties made by Anadarko, subject to certain exceptions. The aggregate liability of Anadarko under the Acquisition Agreement is limited to the Purchase Price and Anadarko shall not be liable to AOG unless the aggregate amount of such liability exceeds a deductible equal to 2% of the unadjusted Purchase Price, after which point, AOG will be entitled to recover from Anadarko only with respect to the amount which exceeds such deductible. AOG has indemnified Anadarko for certain liabilities that are a direct result of the breach of the Acquisition Agreement by AOG including, any breaches of the representations and warranties of AOG, subject to certain exceptions. In addition, AOG has indemnified Anadarko for all liabilities which relate to the Assets which occur or accrue on or after July 1, 2004 and for all past, present and future environmental liabilities, in each case, subject to certain limited exceptions. STATUS OF UNITHOLDER LIMITED LIABILITY LEGISLATION In May 2004 the Alberta legislature passed Bill 34, which would enact a new statute, to be called the INCOME TRUSTS LIABILITY ACT, to create a statutory limitation on the liability of unitholders of Alberta income trusts such as the Trust. The Bill received Royal Assent on May 19, 2004 and came into force July 1, 2004. The legislation provides that a unitholder will not be, as a beneficiary, liable for any act, default, obligation or liability of the trustee that arises after the legislation comes into force. DISTRIBUTION ANNOUNCEMENT On August 24, 2004 the Trust announced that, subject to the closing of the Acquisition on or before September 30, 2004 its distribution to be paid on November 15, 2004 for Unitholders of record on October 29, 2004 will be $0.25 per Trust Unit, being an increase of 8.7% from the previous distribution level of $0.23 per Trust Unit. OPERATIONAL UPDATE ON THE NEVIS PROPERTY The Trust's Nevis property is situated 50 kilometers east of the City of Red Deer Alberta. The majority of the production from this property has historically consisted of natural gas from over 32 sections of land with varying working interests. The Trust's primary development target from the area is light crude oil presently being produced from the Wabamun formation. To develop the Wabamun reservoir, the Trust is primarily utilizing horizontal drilling. The horizontal drilling targets have been and will be guided by the use of existing 3D seismic that covers the majority of the property. The Trust is also proposing that portions of the property not currently covered with 3D seismic will be shot during the third quarter, with a program covering in excess of 10 sections of land. During the first six months of 2004 the Trust drilled five horizontal oil wells, one standing horizontal well, one vertical oil well, one vertical natural gas well and one dry vertical well, all with a 100% working interest to the Trust. During the third quarter to date, four horizontal oil wells and four vertical oil wells have been drilled. These oil wells are expected to be on production by the end of the third quarter. Two additional horizontal wells are currently drilling, with an additional eight horizontal wells scheduled for the remainder of the year. The Trust has acquired a 100% working interest in an additional 16 sections of land through a successful program of freehold leasing, crown land acquisitions, acreage swaps and a farmin arrangement and has extended the oil bearing area an additional three miles to the southeast and to the southwest from the discovery oil wells. The drilling program in the third quarter has satisfied the earning component of the farmin arrangement. Daily production from the Nevis property is currently at 1,240 boe/d of which 360 boe/d was added from three newly drilled horizontal oilwells brought into production during the second quarter. 18 POTENTIAL TRANSACTIONS The Trust continues to evaluate potential acquisitions of all types of petroleum and natural gas and other energy-related assets as part of its ongoing acquisition program. The Trust is normally in the process of evaluating several potential acquisitions at any one time which individually or together could be material. As of the date hereof, other than as otherwise disclosed herein, the Trust has not reached agreement on the price or terms of any potential material acquisitions. The Trust cannot predict whether any current or future opportunities will result in one or more acquisitions for the Trust. In addition, the Trust continues to review and evaluate opportunities to dispose of or rationalize its non-core assets where favourable opportunities arise. INFORMATION CONCERNING THE ASSETS As the Trust does not currently own the Assets, the following information has been summarized from information obtained from Anadarko and other third parties. The Reserves data for the Assets set forth below is based upon an evaluation by Sproule with an effective date of July 1, 2004 contained in the Sproule Anadarko Report. The Reserves data summarizes the natural gas Reserves of the Assets and the net present values of future net revenue for these Reserves using Constant prices and costs and Forecast prices and costs. References to production herein indicate the relevant party's working interest share prior to the deduction of royalties owned by others. Except where otherwise indicated, the Reserves data conforms to the requirements of National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). All Reserves associated with the Assets are located in Canada and, specifically, in the provinces of Alberta 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 OR FORECAST PRICES AND COSTS OR OTHER ASSUMPTIONS WILL BE ATTAINED AND VARIANCES COULD BE MATERIAL. RESERVES DATA (FORECAST PRICES AND COSTS) The following tables provide Reserves data and future net revenues associated with the Assets based on the Sproule Anadarko Report using Forecast prices and costs. SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE AS OF JULY 1, 2004 FORECAST PRICES AND COSTS
RESERVES ------------------------------------------------------------------------------------------------------- LIGHT AND NATURAL GAS MEDIUM OIL HEAVY OIL NATURAL GAS LIQUIDS BOE ------------------ ----------------- ------------------- --------------- ------------------ GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET RESERVES CATEGORY (MBBL) (MBBL) (MBBL) (MBBL) (MMCF) (MMCF) (MBBL) (MBBL) (MBOE) (MBOE) ------------------------- -------- ------- ------- ------- -------- -------- ------ ------ ------- ------- Proved Developed Producing 3,757.8 3,110.3 1,254.6 1,149.0 16,424.2 11,741.2 513.6 369.2 8,263.4 6,585.3 Developed Non-Producing 45.6 42.4 - - 1,262.0 1,005.3 30.7 23.5 286.6 233.4 Undeveloped 641.9 593.1 - - 145.3 132.6 7.6 7.5 673.7 622.8 -------- ------- ------- ------- -------- -------- ------ ------ ------- ------- Total Proved 4,445.3 3,745.8 1,254.6 1,149.0 17,831.6 12,879.0 552.0 400.2 9,223.8 7,441.5 Probable 2,725.8 2,366.6 261.4 237.8 8,517.2 6,082.4 251.6 176.0 4,658.3 3,794.1 -------- ------- ------- ------- -------- -------- ------ ------ ------- ------- Total Proved Plus Probable 7,171.1 6,112.4 1,515.9 1,386.7 26,348.8 18,961.5 803.6 576.2 13,882.1 11,235.6 ======== ======= ======= ======= ======== ======== ====== ====== ======= =======
19
NET PRESENT VALUES OF FUTURE NET REVENUE(1) ----------------------------------------------------------------------------------------------------- BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR) AFTER INCOME TAXES DISCOUNTED AT (%/YEAR) -------------------------------------------------- ------------------------------------------------- 0 5 10 15 20 0 5 10 15 20 RESERVES CATEGORY (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) -------------------------- -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Proved Developed Producing 148,447 126,868 112,172 101,382 93,042 148,447 126,868 112,172 101,382 93,042 Developed Non-Producing 5,289 4,646 4,134 3,717 3,370 5,289 4,646 4,134 3,717 3,370 Undeveloped 9,506 7,912 6,644 5,610 4,751 9,506 7,912 6,644 5,610 4,751 -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Total Proved 163,242 139,299 122,740 110,446 100,867 163,242 139,299 122,740 110,446 100,867 Probable 83,422 59,541 45,762 36,922 30,808 83,422 59,541 45,762 36,922 30,808 -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Total Proved Plus Probable 246,665 198,840 168,502 147,367 131,676 246,665 198,840 168,502 147,367 131,676 ======== ======== ======== ======== ======== ======== ======== ======== ======== ========
Note: (1) The numbers shown are as represented in the Sproule Anadarko Report. Slight differences may be due to rounding.
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF JULY 1, 2004 FORECAST PRICES AND COSTS(1) FUTURE NET FUTURE NET WELL REVENUE REVENUE OPERATING DEVELOPMENT ABANDONMENT BEFORE INCOME AFTER RESERVES CATEGORY REVENUE ROYALTIES COSTS COSTS COSTS INCOME TAXES TAXES INCOME TAXES ----------------- ------- --------- --------- ---------- ----------- ------------ -------- ------------ (m$) (m$) (m$) (m$) (m$) (m$) (m$) (m$) Proved Reserves 362,300 72,077 115,000 10,598 - 163,200 - 163,200 Proved Plus 545,900 104,800 176,300 14,999 - 246,700 - 246,700 Probable Reserves
Note: (1) The numbers shown are as represented in the Sproule Anadarko Report. Slight differences may be due to rounding.
FUTURE NET REVENUE BY PRODUCTION GROUP AS OF JULY 1, 2004 FORECAST PRICES AND COSTS FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED AT 10%/YEAR) RESERVES CATEGORY PRODUCTION GROUP (M$) --------------------------- ----------------------------------------------------------------------------- ------------------- Proved Reserves Light and Medium Crude Oil (including solution gas and other by-products) 53,387 Heavy Oil (including solution gas and other by-products) 7,441 Natural Gas (including by-products but excluding solution gas from oil wells) 61,912 Proved Plus Probable Light and Medium Crude Oil (including solution gas and other by-products) 75,248 Reserves Heavy Oil (including solution gas and other by-products) 9,354 Natural Gas (including by-products but excluding solution gas from oil wells) 83,899
20 RESERVES DATA (CONSTANT PRICES AND COSTS) The following tables provide Reserves data and future net revenue of the Assets based on the Sproule Anadarko Report using Constant prices and costs.
SUMMARY OF OIL AND GAS RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE AS OF JULY 1, 2004 CONSTANT PRICES AND COSTS RESERVES ------------------------------------------------------------------------------------------------------ LIGHT AND NATURAL GAS MEDIUM OIL HEAVY OIL NATURAL GAS LIQUIDS BOE ------------------ ----------------- ------------------- --------------- ------------------ GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET RESERVES CATEGORY (MBBL) (MBBL) (MBBL) (MBBL) (MMCF) (MMCF) (MBBL) (MBBL) (MBOE) (MBOE) ------------------------- -------- ------- ------- ------- -------- -------- ------ ------ ------- ------- Proved Developed Producing 3,879.6 3,187.6 1,281.4 1,168.8 17,271.0 12,310.4 522.4 373.5 8,561.9 6,781.7 Developed Non-Producing 47.2 43.7 - - 1,308.6 1,047.6 31.3 24.0 296.6 242.3 Undeveloped 655.7 604.1 - - 159.6 145.9 7.7 7.6 690.1 636.0 -------- ------- ------- ------- -------- -------- ------ ------ ------- ------- Total Proved 4,582.5 3,835.4 1,281.4 1,168.8 18,739.1 13,503.9 561.5 405.1 9,548.6 7,660 Probable 2,939.3 2,526.2 285.2 258.1 9,107.0 6,483.9 258.4 179.3 5,000.7 4,044.3 -------- ------- ------- ------- -------- -------- ------ ------ ------- -------- Total Proved Plus Probable 7,521.8 6,361.6 1,566.6 1,426.9 27,846.1 19,987.8 819.9 584.5 14,549.3 11,704.3 ======== ======= ======= ======= ======== ======== ====== ====== ======= ======== NET PRESENT VALUES OF FUTURE NET REVENUE(1) ----------------------------------------------------------------------------------------------------- BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR) AFTER INCOME TAXES DISCOUNTED AT (%/YEAR) -------------------------------------------------- ------------------------------------------------- 0 5 10 15 20 0 5 10 15 20 RESERVES CATEGORY (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) -------------------------- -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Proved Developed Producing 186,326 155,258 134,739 120,010 108,832 186,326 155,258 134,739 120,010 108,832 Developed Non-Producing 7,013 6,010 5,249 4,652 4,172 7,013 6,010 5,249 4,652 4,172 Undeveloped 12,904 10,723 9,043 7,699 6,598 12,904 10,723 9,043 7,699 6,598 -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Total Proved 206,243 171,809 148,739 132,002 119,203 206,243 171,809 148,739 132,002 119,203 Probable 110,566 77,535 58,641 46,649 38,450 110,566 77,535 58,641 46,649 38,450 -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Total Proved Plus Probable 316,810 249,344 207,380 178,651 157,653 316,810 249,344 207,380 178,651 157,653 ======== ======== ======== ======== ======== ======== ======== ======== ======== ======== TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF JULY 1, 2004 CONSTANT PRICES AND COSTS FUTURE NET FUTURE NET WELL REVENUE REVENUE OPERATING DEVELOPMENT ABANDONMENT BEFORE INCOME AFTER RESERVES CATEGORY REVENUE ROYALTIES COSTS COSTS COSTS INCOME TAXES TAXES INCOME TAXES ----------------- ------- --------- --------- ---------- ----------- ------------ -------- ------------ (m$) (m$) (m$) (m$) (m$) (m$) (m$) (m$) Proved Reserves 424,000 90,307 115,000 10,560 - 206,200 - 206,200 Proved Plus 650,300 135,300 179,000 14,946 - 316,800 - 316,800 Probable Reserves
21 FUTURE NET REVENUE BY PRODUCTION GROUP AS OF JULY 1, 2004 CONSTANT PRICES AND COSTS
FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED AT 10%/YEAR) RESERVES CATEGORY PRODUCTION GROUP (M$) --------------------------- -------------------------------------------------------------------------------- ------------------ Proved Reserves Light and Medium Crude Oil (including solution gas and other by-products 65,384 Heavy Oil (including solution gas and other by-products) 10,762 Natural Gas (including by-products but excluding solution gas from oil wells) 72,594 Proved Plus Probable Light and Medium Crude Oil (including solution gas and other by-products 94,467 Reserves Heavy Oil (including solution gas and other by-products) 13,373 Natural Gas (including by-products but excluding solution gas from oil wells) 99,539 from oil wells)
PRICING ASSUMPTIONS The following tables set forth the benchmark reference prices and pricing assumptions used in preparing the Reserves data for the Assets and, in the case of Forecast prices and costs, the inflation rate assumptions.
SUMMARY OF PRICING ASSUMPTIONS AS OF JULY 1, 2004 CONSTANT PRICES AND COSTS OIL -------------------------------------------------- EDMONTON HARDISTY CROMER WTI PAR PRICE HEAVY MEDIUM NATURAL CUSHING 40(DEGREE) 12(DEGREE) 29.3(DEGREE) AECO GAS EDMONTON EDMONTON EDMONTON EXCHANGE OKLAHOMA API API API PRICE PROPANE BUTANE PENTANES RATE ---------- -------- ---------- ---------- ----------- ----------- --------- --------- -------- ---------- ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/$Cdn) 2004 38.49 49.81 32.07 44.31 7.64 31.18 37.13 51.02 0.75 (6 mths)
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SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS AS OF JULY 1, 2004 FORECAST PRICES AND COSTS OIL -------------------------------------------------- EDMONTON HARDISTY CROMER PAR PRICE HEAVY MEDIUM NATURAL WTI 40(DEGREE) 12(DEGREE) 29.3(DEGREE) AECO GAS EDMONTON INFLATION EXCHANGE NYMEX API API API PRICE HENRY HUB BUTANE RATES RATE ---------- -------- ---------- ---------- ----------- ----------- --------- --------- ---------- ---------- ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/$Cdn) Forecast 2004 (6 mths) 37.17 49.76 39.28 47.29 6.93 6.52 39.53 1.5 0.750 2005 35.08 46.88 36.24 44.37 6.85 6.28 36.85 1.5 0.750 2006 33.42 44.59 33.79 42.04 6.27 5.78 34.71 1.5 0.750 2007 32.42 43.51 32.47 40.90 5.80 5.36 33.62 1.5 0.750 2008 31.83 42.68 31.48 40.04 5.50 5.13 32.79 1.5 0.750 2009 31.55 42.36 31.13 39.88 5.40 5.02 32.58 1.5 0.750 2010 31.57 42.05 30.74 39.56 5.27 4.95 32.26 1.5 0.750 2011 31.92 42.82 31.25 40.27 5.24 4.91 32.83 1.5 0.750 2012 33.75 45.35 33.60 42.75 5.21 4.89 35.01 1.5 0.750 2013 33.54 45.35 33.34 42.70 5.27 4.92 34.88 1.5 0.750 2014 34.69 46.60 34.51 43.93 5.31 4.99 35.97 1.5 0.750 2016+ +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr 1.5 0.750
OIL AND GAS PROPERTIES The following is a description of the principal oil and natural gas properties to be acquired by AOG pursuant to the Acquisition Agreement. The Assets are focused in central Alberta, southern Alberta and southeast Saskatchewan. The term "net", when used to describe Anadarko's share of production, means the aggregate of Anadarko's working interest share before deduction of royalties owned by others. CENTRAL ALBERTA BRAZEAU RIVER The Brazeau River property is located approximately 30 miles west of the town of Drayton Valley, Alberta. The property produces sour light oil and natural gas primarily from Devonian aged Nisku pinnacle reefs. The majority of the production is from a non-operated 50% working interest in the Nisku C, D and E pools and a 17% working interest in the Nisku A unit. Sweet natural gas is also produced from eight natural gas wells out of reservoirs in either of the Cretaceous aged Cardium, Viking or Lower Mannville Formations. Major facility interests include a 25.7% working interest in the West Pembina Sour Gas Plant and a 31.6% working interest in the Brazeau River Gas Plant. The net production from the property at July 1, 2004 was 1,222 boe/d consisting of 5,693 mcf/d natural gas, 63 bbl/d NGLs and 211 bbl/d of crude oil. The Sproule Anadarko Report assigned Proved plus Probable Reserves of 1,884 mboe to the property as at July 1, 2004. OPEN LAKE The Open Lake property is located approximately 20 miles north of the town of Rocky Mountain House, Alberta. Anadarko operates and has a 100% working interest in the Open Lake property. Oil and natural gas production from this property is multi-zoned from various Cretaceous and Jurassic reservoirs including the Rock Creek, Ellerslie, Ostracod, Viking, Second White Specks and Belly River Formations. The net production from the property at July 1, 2004 was 716 boe/d consisting of 2,297 mcf/d natural gas, 135 bbl/d NGLs and 199 bbl/d of crude oil. The Sproule Anadarko Report assigned Proved plus Probable Reserves of 1,342 mboe to the property as at July 1, 2004. 23 CARSTAIRS The Carstairs property is situated in the town of Carstairs, Alberta. The property produces from carbonates in the Mississippian aged Elkton Formation. The property is operated by Anadarko with a 70.8% (oil) and 62.7% (gas) working interest in the East Crossfield Elkton G Pool Unit #1. A 65.9% working interest is held in the oil processing facility. The net production from the property at July 1, 2004 was approximately 579 boe/d consisting of 2,553 mcf/d natural gas, 91 bbl/d NGLs and 63 bbl/d oil. The Sproule Anadarko Report assigned total Proved plus Probable Reserves of 970 mboe to the property as at July 1, 2004. GULL LAKE The Gull Lake property consists of production from a number of sections north of the City of Red Deer, Alberta. The net production was 24 boe/d as of July 1, 2004 from properties with reserves assigned. The Sproule Anadarko Report assigned total Proved plus Probable reserves of 38 mboe. One newly drilled well at a 50% non-operated working interest began producing late in May 2004. It is currently producing 1.3 mmcf/d of natural gas net to Anadarko. No reserve assignments have been made to this well due to the early stage of production. FIR The Fir property is located approximately 40 miles northwest of the town of Edson, Alberta. This property is comprised of two wells with an average working interest of 71% producing co-mingled natural gas from Triassic aged Montney Formations. The property is operated by Anadarko with a 43.6% working interest in the compressor facility. The net natural gas production from the property at July 1, 2004 was 2,072 mcf/d. The Anadarko Sproule Report assigned total Proved plus Probable Reserves of 684 mboe to the property as at July 1, 2004. WINDFALL Windfall is an area consisting of certain blocks of land east of the Fir property, located approximately 35 miles north of the town of Edson, Alberta. Light oil and natural gas is produced from a wide range of geological intervals with interests ranging from overriding royalties to 100% working interest. The majority of the production is operated and originates from the Cretaceous aged Gething Formation. Anadarko has a 100% working interest in two gas compressor facilities and a 50% working interest in a 2 phase separator. The net production from the property at July 1, 2004 was 163 boe/d consisting of 814 mcf/d natural gas, 22 bbl/d of NGLs and 6 bbl/d crude oil. The Sproule Anadarko Report assigned total Proved plus Probable Reserves of 437 mboe to the property as at July 1, 2004. SOUTHERN ALBERTA RETLAW The Retlaw property is located approximately 30 miles north of the City of Lethbridge. It is a medium gravity crude oil property which is operated at an average 40% working interest. Production occurs from Cretaceous aged Glauconite channels defined with 3D seismic. There is a 50% working interest in the oil battery which includes water injection facilities. The net production as of July 1, 2004 is 367 boe/d consisting of 514 mcf/d of natural gas and 282 bbls/d of crude oil. The Sproule Anadarko Report assigned total Proved plus Probable Reserves of 506 mboe to the property as at July 1, 2004. LOST LAKE The Lost Lake property is located approximately 45 miles north of the City of Lethbridge. It is a heavy gravity crude oil property which as of July 1, 2004 had net production of 358 boe/d consisting of 117 mcf/d natural gas and 338 bbls/d crude oil. Oil production occurs primarily from the Cretaceous aged Glauconite channels. The working interest in the property is 76% and 87.5% in the oil battery and water injection facility. The Sproule Anadarko Report assigned Proved plus Probable Reserves of 601 mboe to the property as at July 1, 2004. 24 LITTLE BOW The Little Bow property is located west of the Lost Lake property, north of the City of Lethbridge. The property produces heavy gravity crude oil which as of July 1, 2004 had net production of 265 boe/d consisting of 185 mcf/d of natural gas and 234 bbls/d of crude oil. It produces from Cretaceous aged Glauconite channels. The working interest is operated by Anadarko at 63%. Anadarko's interest in the oil treating and water injection facilities is 68.1%. The Sproule Anadarko Report assigned total Proved plus Probable Reserves of 1,226 mboe to the property as at July 1, 2004. SOUTHEASTERN SASKATCHEWAN MIDALE The Midale property is located north of the town of Midale, Saskatchewan. This property produces primarily from the Ordovician aged Red River Formation. Light oil production occurs from more than a dozen pools within reservoirs which occur as carbonate buildups in this formation. Anadarko operates the property and has an average working interest of 76% in the area. A 100% working interest is held in the oil battery. The net production from the property at July 1, 2004 was 602 bbl/d of crude oil. The Sproule Anadarko Report assigned total Proved plus Probable Reserves of 1,145 mboe to the property as at July 1, 2004. STEELMAN The Steelman property is located south of the town of Browning, Saskatchewan and has an average working interest of 85% consisting of light oil production. Production is taken from Ordovician aged Red River Formation, Devonian aged Winnipegosis Formation and Mississippian aged Frobisher Formation. Anadarko has a 100% working interest in the oil battery. The net production at July 1, 2004 was 492 bbls/d of crude oil from the property. The Sproule Anadarko Report assigned total Proved plus Probable Reserves of 1,382 mboe to the property as at July 1, 2004. WEYBURN The Weyburn property is located southeast of the town of Weyburn, Saskatchewan. This property consists of an extensive land base, including operated interests adjacent to the CO2 miscible flood as well as operated interests with active area partners. Net production consisting of 236 bbls/d of light crude oil originates primarily from the Mississippian aged Frobisher Formation. Anadarko has a 100% working interest in the sour battery. The Sproule Anadarko Report assigned total Proved plus Probable Reserves of 528 mboe to the property as at July 1, 2004. FROUDE The Froude property is located approximately two miles west of Froude, Saskatchewan. The operated production at an average working interest of 93% occurs from the Ordovician Red River, Devonian Winnipegosis and Mississippian Frobisher formations. Net production as of July 1, 2004 was 203 bbls/d of light crude oil. Facilities are 100% owned. The Sproule Anadarko Report assigned total Proved plus Probable Reserves of 669 mboe to the property as at July 1, 2004. UNDEVELOPED RESERVES The Proved Undeveloped Reserves by product type, attributed to the Assets are 641.9 mbbl of light/medium crude oil, 145.3 mmcf of natural gas and 7.6 mbbl of NGL and the Probable Undeveloped Reserves by product type attributed to the Assets are 759.1 mmbl of light/medium crude oil and 126.6 mmcf of natural gas, in each case as estimated in the Sproule Anadarko Report, based on company interest Reserves and based on Forecast prices and costs. AOG plans to continue pursuing development opportunities on the Assets such as drilling, completions, and facilities upgrades in order to move Proved Undeveloped and Probable Reserves into Proved Developed Producing Reserves. In instances where land rights are expected to expire within one year, AOG may engage in farmout 25 arrangements, which would likely eliminate the potential expiry and possibly result in some Proved Undeveloped and Probable Reserves becoming Proved Developed Producing Reserves. SIGNIFICANT FACTORS AND UNCERTAINTIES The process of evaluating Reserves is inherently complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The Reserve estimates contained herein are based on current production forecasts, prices and economic conditions. AOG's Reserves and the Reserves set forth in the Sproule Anadarko Report have been evaluated by Sproule, an independent engineering firm. These factors and assumptions include among others: (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of Reserves; (v) success of future development activities; (vi) marketability of production; (vii) effects of government regulations; and (viii) other government levies imposed over the life of the Reserves. AS CIRCUMSTANCES CHANGE AND ADDITIONAL DATA BECOMES AVAILABLE, RESERVE ESTIMATES ALSO CHANGE. ESTIMATES ARE REVIEWED AND REVISED, EITHER UPWARD OR DOWNWARD, AS WARRANTED BY THE NEW INFORMATION. REVISIONS ARE OFTEN REQUIRED DUE TO CHANGES IN WELL PERFORMANCE, PRICES, ECONOMIC CONDITIONS AND GOVERNMENTAL RESTRICTIONS. REVISIONS TO RESERVE ESTIMATES CAN ARISE FROM CHANGES IN YEAR-END PRICES, RESERVOIR PERFORMANCE AND GEOLOGIC CONDITIONS OR PRODUCTION. THESE REVISIONS CAN BE EITHER POSITIVE OR NEGATIVE. FUTURE DEVELOPMENT COSTS The following table sets forth development costs deducted in the estimation of the future net revenue attributable to the Assets in the Sproule Anadarko Report in the Reserve categories noted below.
FORECAST PRICES AND COSTS (M$) CONSTANT PRICES AND COSTS (M$) ------------------------------------------------------- ----------------------------- Year PROVED RESERVES PROVED PLUS PROBABLE RESERVES PROVED RESERVES --------------------- ----------------------------- ----------------------------- 0% 10% 0% 10% 0% 10% ------- ------- ------- ------- -------- ------- 2004 10,340 10,098 13,662 13,398 10,340 10,098 2005 147 134 1,227 1,118 145 132 2006 - - - - - - 2007 - - - - - - 2008 - - - - - - Thereafter 111 20 111 20 75 14 ------- ------- ------- ------- -------- ------- Total 10,598 10,252 14,999 14,536 10,560 10,244
The future development costs are capital expenditures required in the future for the Assets to convert Proved Undeveloped Reserves and Probable Reserves into Proved Developed Producing Reserves. AOG anticipates using a combination of internally generated cash flow, debt and equity financing to fund these future development costs. Based on the commodity price and cost assumptions adopted for both the Constant prices and costs case and the Forecast prices and costs case, all the expenditures included in the future development costs are economic as they enhance the net present values of the Proved Developed Reserves. 26 OIL AND GAS WELLS The following table sets forth the number and status of wells in which AOG will acquire a working interest pursuant to the Acquisition.
OIL WELLS NATURAL GAS WELLS ----------------------------------------- ------------------------------------------- PRODUCING NON-PRODUCING(1) PRODUCING NON-PRODUCING(1) ------------------- ----------------- ------------------ ------------------ GROSS (2) NET GROSS NET GROSS (2) NET GROSS NET --------- ------ ----- ------ --------- ------ ----- ----- Alberta 155 88.2 6 4.7 88 21.2 5 4.3 Saskatchewan 97 78.4 16 14.5 - - - - --------- ------ ----- ------ --------- ------ ----- ----- Total 252 166.6 22 19.2 88 21.2 5 4.3 ========= ====== ===== ====== ========= ====== ===== =====
Notes: (1) Non-Producing wells means wells which have encountered and are capable of producing crude oil or natural gas but which are not producing due to lack of available transportation facilities, available markets or other reasons. (2) Gross wells include unit wells. PROPERTIES WITH NO ATTRIBUTED RESERVES The following table sets out for the Assets the total land holdings of Proved and unproved properties to be acquired by AOG. Approximately 30,355 gross (18,213 net) acres will expire by August 2005.
UNPROVED DEVELOPED (ACRES) PROPERTIES (ACRES) TOTAL (ACRES) ----------------- -------------------- -------------------- GROSS NET GROSS NET GROSS NET ------ ----- -------- ------- ------- ------ Alberta 12,524 9,138 85,682 34,667 98,206 43,805 Saskatchewan 1,081 832 63,667 44,168 64,448 45,000 ------ ----- -------- ------- ------- ------ Total 13,605 9,970 149,349 78,835 162,654 88,805 ====== ===== ======== ======= ======= ======
COSTS INCURRED A total of $6.5 million and $1.2 million, respectively, in costs were incurred in respect of the Assets for the year ended December 31, 2003 and the six months ended June 30, 2004, as follows: SIX MONTHS ENDED YEAR ENDED JUNE 30, 2004 DECEMBER 31, 2003 ---------------- ----------------- (unaudited) (unaudited) Property Acquisitions - - Development Expenditures 1,157,713 6,544,593 Exploration Expenditures - - TOTAL 1,157,713 6,544,593 EXPLORATION AND DEVELOPMENT ACTIVITIES The following table sets forth the Gross and Net exploratory and development wells drilled on the Assets during the periods indicated.
SIX MONTHS ENDED JUNE 30, 2004 YEAR ENDED DECEMBER 31, 2003 ------------------------------ ---------------------------- GROSS NET GROSS NET -------------- ------------ ----------- ----------- Light and Medium Oil 1 0.4 11 6.0 Natural Gas 1 0.5 - - -------------- ------------ ----------- ----------- Total 2 0.9 11 6.0 ============== ============ =========== ===========
27 PRODUCTION ESTIMATES The following table sets out the volume of production estimated for the period from July 1, 2004 to December 31, 2004 for the Assets, which is reflected in the estimate of future net revenue disclosed in the tables contained under "Information Concerning the Assets - Reserves Data".
LIGHT AND MEDIUM OIL HEAVY OIL NATURAL GAS NATURAL GAS LIQUIDS BOE ---------- --------- ----------- ------------------- ------- (bbls/d) (bbls/d) (mcf/d) (bbls/d) (boe/d) 2004 (6 months) 3,008 652 14,012 459 6,454
PRODUCTION HISTORY The following tables summarize certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback in respect of the Assets for the periods indicated. Current production from the Assets is approximately 6,250 boe/d consisting of 15.5 mmcf/d of natural gas, 3,138 bbls/d of crude oil and 529 bbls/d of NGLs.
QUARTER ENDED ------------------------------------------------------------------------- 2004 2003 -------------------- ----------------------------------------------- JUNE 30 MAR. 31 DEC. 31 SEPT. 30 JUNE 30 MAR. 31 ------- ------- ------- -------- ------- ------- Average Daily Production Light and Medium Crude Oil 3,054 3,396 3,540 3,796 3,958 4,097 (bbls/d) Gas (mcf/d) 14,619 15,149 15,921 17,024 17,653 17,854 NGL (bbls/d) 485 551 774 806 881 515 Combined (boe/d) 5,975 6,472 6,968 7,440 7,782 7,588 Average Price Received Light and Medium Crude Oil 44.17 40.14 34.94 36.86 35.40 40.65 ($/bbls) Gas ($/mcf) 7.16 6.90 5.72 6.18 7.02 8.10 NGL ($/bbls) 38.93 36.69 24.16 24.45 21.30 39.28 Combined ($/boe) 43.26 40.33 33.50 35.61 36.35 43.67 Royalties Light and Medium Crude Oil 20.5% 23.0% 23.6% 23.6% 21.8% 22.7% ($bbls/d) Gas (mcf/d) 24.1% 26.2% 27.2% 25.7% 24.8% 28.4% NGL (bbls/d) 19.8% 25.7% 25.1% 25.5% 24.4% 27.3% Combined (boe/d) 21.9% 24.5% 25.1% 24.5% 23.3% 25.5% Operating expenses Combined ($/boe) 11.44 9.04 10.55 9.87 8.59 8.47 Netback Received Combined ($/boe) 22.34 21.42 14.54 17.00 19.30 24.09
The following table indicates the average daily production from the important fields associated with the Assets for the year ended December 31, 2003:
CRUDE OIL NATURAL GAS NGL TOTAL --------- ----------- -------- --------- (bbls/d) (mcf/d) (bbls/d) (boe/d) CENTRAL ALBERTA Brazeau River 233 6,773 161 1,523 Open Lake 212 2,919 179 878 Carstairs 67 2,012 153 555 Fir 1 1,757 49 343 Windfall 6 1,344 16 246 Gull Lake 1 103 4 22 Other 133 990 191 489 --------- ----------- -------- --------- TOTAL CENTRAL ALBERTA 653 15,898 753 4,056
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CRUDE OIL NATURAL GAS NGL TOTAL --------- ----------- -------- --------- (bbls/d) (mcf/d) (bbls/d) (boe/d) SOUTHERN ALBERTA Retlaw 352 392 13 430 Lost Lake 405 210 1 441 Little Bow 4-25 195 111 0 214 Little Bow 16-20 67 370 1 130 Other 207 - 207 TOTAL SOUTHERN ALBERTA 1,226 1,083 15 1,422 SOUTHEAST SASKATCHEWAN Midale 678 57 - 688 Weyburn 248 - - 248 Froude 218 - - 218 Steelman 605 66 - 616 Other 218 3 - 219 TOTAL SOUTHEAST SASKATCHEWAN 1,967 126 - 1,988 TOTAL 3,846 17,107 768 7,465
Note: (1) Production numbers reflect total production averaged over the course of the year. EFFECT OF THE ACQUISITION ON THE TRUST The following table sets out certain operational information for the Trust and the Assets and certain pro forma combined operational information after giving effect to the Acquisition.
SELECTED PRO FORMA COMBINED OPERATIONAL INFORMATION TRUST ASSETS PRO FORMA COMBINED ----------- --------- ------------------ AVERAGE DAILY PRODUCTION (before royalties, for the six months ended June 30, 2004) Crude oil and NGL (bbls/d) 2,974 3,743 6,717 Natural Gas (mcf/d) 74,466 14,884 89,350 Oil equivalent (boe/d) 15,385 6,223 21,608 AVERAGE DAILY PRODUCTION (1) (before royalties, for the year ended December 31, 2003) Crude oil and NGL (bbls/d) 2,756 4,614 7,370 Natural gas (mcf/d) 57,631 17,107 74,738 Oil equivalent (boe/d) 12,361 7,465 19,826 PROVED RESERVES (2) (before royalties, as at December 31, 2003, except the Assets which are as at July 1, 2004) Crude oil and NGL (mbbls) 8,261 6,252 14,513 Natural gas (bcf) 184.4 17.8 202.2 Oil equivalent (mboe) 38,998 9,224 48,222
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TRUST ASSETS PRO FORMA COMBINED ----------- --------- ------------------ PROVED PLUS PROBABLE RESERVES (2) (before royalties, as at December 31, 2003, except the Assets which are as at July 1, 2004) Crude oil and NGL (mbbls) 13,697 9,491 23,188 Natural gas (bcf) 237.4 26.3 263.7 Oil equivalent (mboe) 53,271 13,882 67,153
Notes: (1) Average daily production for the Trust for the year ended December 31, 2003 includes production from the properties acquired pursuant to the acquisition of MarkWest from the date of closing of such acquisition. (2) Reserve information for the Assets is as at July 1, 2004, using Sproule's July 1, 2004 price forecast and the Trust's Reserve information is as at December 31, 2003, using Sproule's December 31, 2003 price forecast. SELECTED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION Certain selected pro forma consolidated financial information is set forth in the following tables. SUCH INFORMATION SHOULD BE READ IN CONJUNCTION WITH THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF THE TRUST AFTER GIVING EFFECT TO THE ACQUISITION AS AT AND FOR THE SIX MONTHS ENDED JUNE 30, 2004 AND THE YEAR ENDED DECEMBER 31, 2003 INCLUDED IN THIS SHORT FORM PROSPECTUS. The pro forma adjustments are based upon the assumptions described in the notes to the unaudited pro forma consolidated financial statements. The pro forma consolidated financial statements are presented for illustrative purposes only and are not necessarily indicative of the operating or financial results that would have occurred had the Acquisition actually occurred at the times contemplated by the notes to the unaudited pro forma consolidated financial statements or of the results expected in future periods. The information presented below and in the unaudited pro forma consolidated financial statements of the Trust assumes completion of the Acquisition and the issuance of 3,500,000 Subscription Receipts, $75,000,000 aggregate principal amount of 7.50% Debentures and $50,000,000 aggregate principal amount of 7.75% Debentures pursuant to the offering.
AS AT AND FOR THE SIX MONTHS ENDED JUNE 30, 2004 --------------------------------------------------------- PRO FORMA TRUST (4) ASSETS(6) CONSOLIDATED (7) ----------- ----------- --------------- (stated in thousands of dollars, except unit amounts) Revenue - net (1) 86,887 37,643 124,530 Net income 18,734 4,639 23,373 Funds from operations (2) 64,353 24,056 88,409 Total assets 595,862 183,198 779,060 Long term debt and working capital (3) 186,380 (5,910) 180,470 Equity 288,675 182,510 471,185 Units outstanding (thousands as at June 30, 2004) 39,952 3,500 43,452
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FOR THE YEAR ENDED DECEMBER 31, 2003 ---------------------------------------------------------------------- PRO FORMA ADJUSTMENTS PRO FORMA TRUST (4) BEFORE ASSETS(5) ASSETS(6) CONSOLIDATED(7) ------------ ---------------- --------- --------------- (restated)(8) (stated in thousands of dollars) Revenue - net (1) 137,584 33,172 80,058 250,814 Net income 44,024 10,061 13,475 67,560 Funds from operations(2) 99,440 21,909 53,800 175,149
Notes: (1) Revenue - net consists of gross revenue net of applicable royalties. (2) Funds from operations is before changes in non-cash working capital. As such, it is not a measure recognized by Canadian generally accepted accounting principles ("GAAP") and does not have a standardized meaning prescribed by GAAP. Therefore, funds from operations of the Trust may not be comparable to similar measures presented by other issuers, and investors are cautioned that it should not be construed as an alternative to net income, cash flow from operating activities or other measures of financial performance calculated in accordance with GAAP. (3) Long term debt and working capital includes bank indebtedness, all current liabilities (net of current assets) and hedging. (4) The Trust's financial information for the year ended December 31, 2003 was obtained from the Trust's audited consolidated financial statements for the year ended December 31, 2003 and as at and for the six months ended June 30, 2004 was obtained from the Trust's unaudited consolidated financial statements as at and for the six months ended June 30, 2004. (5) See Note 2 to the unaudited pro forma consolidated financial statement of operations for the year ended December 31, 2003 set forth herein. (6) The Anadarko properties financial information for the year ended December 31, 2003 was obtained from the audited schedules of revenues and expenses for the Assets for the year ended December 31, 2003 set forth herein and for the six months ended June 30, 2004 was obtained from the unaudited schedules of revenues and expenses for the Assets for the six months ended June 30, 2004 set forth herein, and reflects the pro forma adjustments as noted in the Pro Forma Consolidated Financial Statements set forth herein. (7) See the notes to the unaudited pro forma consolidated financial statements set forth herein for assumptions and adjustments. The unaudited pro forma consolidated financial statements may not be indicative of results that actually would have occurred if the events reflected herein had been in effect on the dates indicated or of the results expected in future periods. (8) Advantage's consolidated financial statements for the year ended December 31, 2003 have been restated to reflect a change in accounting policy with respect to asset retirement obligations. The change in policy is more fully described in Advantage's unaudited interim consolidated financial statements as at and for the three and six months ended June 30, 2004. DESCRIPTION OF TRUST UNITS TRUST UNITS An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. As at July 30, 2004, 40,080,956 Trust Units were issued and outstanding. Each Trust Unit represents an equal fractional undivided beneficial interest in any distributions from, and in any net assets of, the Trust in the event of termination or winding up of the Trust. The beneficial interests in the Trust are divided into interests in two classes as follows: (i) described and designated as "Trust Units", which are entitled to the rights, subject to limitations, restrictions and conditions set out in the Trust Indenture; and (ii) described and designated as "Special Voting Units", which shall be issued to a trustee and shall be entitled to such number of votes at meetings of Trust Unitholders as is equal to the number of Trust Units reserved for issuance that such Special Voting Units represent, such number of votes and any other rights or limitations to be prescribed by the board of directors of AOG. The Special Voting Units give AOG the flexibility to acquire the securities of another issuer in consideration for securities which are ultimately exchangeable for Trust Units. There are currently no Special Voting Units outstanding. All Trust Units are of the same class with equal rights and privileges. Each Trust Unit is transferable, entitles the holder thereof to participate equally in distributions, including the distributions of net income and net realized capital gains of the Trust, and distributions on liquidation, is fully paid and non-assessable and entitles the holder thereof to one vote at all meetings of Trust Unitholders for each Trust Unit held. 31 Corporate law does not govern the Trust and the rights of Unitholders. 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. CASH DISTRIBUTIONS The board of directors of AOG intends for the Trust to make monthly cash distributions. Cash distributions will be made monthly to the Unitholders of record on the last day of each month (unless such day is not a Business Day, in which case the date of record shall be the next following Business Day; provided that December 31 shall always be a date of record) and shall be payable on the 15th day of each month or, if such day is not a Business Day, the next following Business Day or such other date as determined from time to time by the Trustee. For additional information respecting the Trust Units, including information respecting Unitholders' limited liability, cash distributions, the redemption right attached to the Trust Units, meetings of Unitholders, and amendments to the Trust Indenture, see "Additional Information Respecting Advantage Energy Income Fund" at pages 29 through 35, inclusive, of the Trust's AIF. EARNINGS COVERAGE The earnings coverage ratios set forth below have been prepared in accordance with Canadian disclosure requirements. These ratios have been prepared using financial information prepared in accordance with Canadian generally accepted accounting principles. The ratios and notes have been prepared for each of the twelve month periods ended December 31, 2003 and June 30, 2004, after giving effect to the offering of Subscription Receipts and Debentures. The ratios for the twelve month period ended June 30, 2004 are based on unaudited financial information. Additional information is provided in the notes to the following table. TWELVE MONTHS ENDED TWELVE MONTHS ENDED DECEMBER 31, 2003 JUNE 30, 2004 ------------------- ------------------- Earnings coverage(1)(2)(3)(4)(5) 5.0 3.4 Notes: (1) Earnings coverage is equal to net income before interest expense on all long term debt, including the Debentures, the 8.25% Debentures, the 9.00% Debentures and the 10.00% Debentures, and before income taxes, all divided by interest expense on all long term debt, excluding the Debentures, the 8.25% Debentures, the 9.00% Debentures and the 10.00% Debentures. Under Canadian generally accepted accounting principles the 10.00% Debentures, the 9.00% Debentures and the 8.25% Debentures are, and the Debentures will be, included in Unitholders' equity and the associated interest payments will be charged to equity. (2) The Trust's interest requirements amount to $6.4 million for the 12 month period ended December 31, 2003 and $5.7 million for the 12 month period ended June 30, 2004. The Trust's earnings before interest and income tax for the 12 month period ended December 31, 2003 and the 12 month period ended June 30, 2004 was $32.2 million and $19.4 million, respectively. The earnings in the coverage ratios are not assumed to change as a result of net proceeds from the offering. (3) If the interest from the Debentures, the 8.25% Debentures, the 9.00% Debentures and the 10.00% Debentures were included in interest expense, the earnings coverage ratios would be 1.5 and less than 1 (with a coverage deficiency of $1.6 million) for the 12 month periods ended December 31, 2003 and June 30, 2004, respectively. The Trust's interest requirements after giving effect to the issue of the Debentures amounted to $21.7 million for the 12 months ended December 31, 2003 and $21.0 million for the 12 months ended June 30, 2004. The Trust's earnings before interest and income tax for the 12 months ended December 31, 2003 was $32.2 million and for the 12 months ended June 30, 2004 was $19.4 million, which is 1.5 times and less than one times Advantage's interest requirements for the respective periods. (4) After giving effect to the Acquisition and if the interest from the Debentures, the 8.25% Debentures, the 9.00% Debentures and the 10.00% Debentures were included in interest expense, the PRO FORMA earnings coverage ratio would be 2.4 times for the twelve month period ended December 31, 2003. (5) Financial information for the year ended December 31, 2003 is based on amounts as revised to reflect changes in the accounting for asset retirement obligations. 32 CONSOLIDATED CAPITALIZATION OF THE TRUST The following table sets forth the consolidated capitalization of the Trust as at December 31, 2003 and as at June 30, 2004, both before and after giving effect to the offering and the Acquisition:
AS AT JUNE 30, 2004 BEFORE GIVING EFFECT TO THE AS AT JUNE 30, 2004 AFTER OFFERING AND THE GIVING EFFECT TO THE OFFERING AS AT ACQUISITION(4) AND THE ACQUISITION(1)(2) DESIGNATION (AUTHORIZED) DECEMBER 31, 2003 (UNAUDITED) (UNAUDITED) ------------------------------------------------------------------------------------------------------------------------- ($ thousands except unit amounts) Bank Debt $102,968 $161,707 $156,397(6) ($220 million)(1) Unitholders' Equity Trust Units(3)(5) $302,496 $339,279 $401,789 (unlimited) (36,717,206 Trust Units) (39,952,085 Trust Units) (43,452,085 Trust Units) 10.00% Debentures $10,214 $6,756 $6,756 ($55,000) 9.00% Debentures $30,000 $27,055 $27,055 ($30,000) 8.25% Debentures $59,770 $32,585 $32,585 ($60,000) 7.50% Debentures Nil Nil $75,000 ($75,000) 7.75% Debentures Nil Nil $50,000 ($50,000) Special Voting Units Nil Nil Nil (unlimited)
Notes: (1) Advantage has credit facilities (the "CREDIT FACILITIES") which provide for a $210 million extendible revolving loan facility and a $10 million operating loan facility. The loan's interest rate is based on either prime or bankers acceptance rates at the Trust's option subject to certain basis point or stamping fee adjustments ranging from 0% to 2.0% depending on the Trust's debt to cash flow ratio. The Credit Facilities are secured by a $250 million floating charge demand debenture, a general security agreement and a subordination agreement from the Trust covering all assets and cash flows. The Credit Facilities are subject to review on an annual basis, with the next review anticipated to take place in May 2005. Various borrowing options are available under the Credit Facilities, including prime rate-based advances and bankers' acceptances loans. The Credit Facilities constitute a revolving facility for a 364 day term which is extendible annually for a further 364 day revolving period, subject to a one year term maturity as to lenders not agreeing to such annual extension. The Credit Facilities contain standard commercial covenants for facilities of this nature, and distributions by AOG to the Trust (and effectively by the Trust to Unitholders) are subordinated to the repayment of any amounts owing under the Credit Facilities. Distributions to Unitholders are not permitted if the Trust is in default of such Credit Facilities or if the amount of the Trust's outstanding indebtedness under such facilities exceeds the then existing current borrowing base. The current borrowing base under the Credit Facilities is $220 million. Interest payments under the Debentures are also subordinated to indebtedness under the Credit Facilities and payments under the Debentures are similarly restricted. (2) Based on the issuance of 3,500,000 Subscription Receipts (and the issue of 3,500,000 Units pursuant thereto), $75,000,000 aggregate principal amount of 7.50% Debentures and $50,000,000 aggregate principal amount of 7.75% Debentures for aggregate gross proceeds of $190,800,000 less the Underwriters' fee of $8,290,000 and expenses of the issue estimated to be $600,000, the net proceeds from this issue are estimated to be $181,910,000, and which will be applied to satisfy a portion of the purchase price of the Acquisition. (3) In addition, as at June 30, 2004, 295,000 incentive rights are outstanding under the Trust's trust unit incentive rights plan. (4) As at June 30, 2004, Unitholders' equity of the Trust incorporated Unitholders' capital of $339,279,000, contributed surplus of $1,036,000, accumulated cash distributions up to June 30, 2004 of $206,080,000 and accumulated income of $80,044,000. 33 (5) The amount recorded for the Trust Units at December 31, 2003 includes $19,592,000 for the accrual of the non-cash performance incentive amounts which were subsequently settled through the issuance of 1,099,104 Trust Units. (6) Assumes net proceeds from the offering of $181,910,000 (net of costs of the offering of $600,000 and the Underwriters' commissions of $8,290,000) and assuming a Purchase Price, net of adjustments, on closing of the Acquisition of $176,600,000. PRICE RANGE AND TRADING VOLUME OF THE TRUST UNITS The outstanding Trust Units are traded on the TSX under the trading symbol "AVN.UN". The following table sets forth the price range and trading volume of the Trust Units as reported by the TSX for the periods indicated. Period High Low Volume 2001 May 29 - 31(1) $12.55 $12.30 117,537 June $12.40 $9.25 1,219,309 Third Quarter $10.50 $7.42 2,226,952 Fourth Quarter $8.40 $7.05 7,381,300 2002 First Quarter $11.35 $7.91 11,207,717 Second Quarter $12.14 $10.00 7,006,294 Third Quarter $13.25 $10.40 7,350,914 Fourth Quarter $13.75 $11.65 7,582,352 2003 First Quarter $15.59 $11.80 7,622,480 Second Quarter $16.95 $14.15 7,995,072 Third Quarter $17.15 $14.92 8,001,055 Fourth Quarter $17.95 $15.65 9,684,205 2004 First Quarter $19.00 $16.01 7,666,480 April $19.84 $18.80 4,120,250 May $20.08 $19.05 3,367,746 June $19.37 $17.80 3,169,079 July $19.65 $18.63 2,095,637 August $19.70 $18.51 3,219,044 September 1 and 2 $19.99 $19.60 347,000 Note: (1) The Trust Units commenced trading on the TSX on May 29, 2001. On August 23, 2004, the last trading day prior to the public announcement of the offering, the closing price of the Trust Units on the TSX was $19.35. On September 2, 2004, the closing price of the Trust Units on the TSX was $19.96. RECORD OF CASH DISTRIBUTIONS The following is a summary of the distributions declared by Advantage from its inception in May 2001 to August 25, 2004. -------------------------------------------------------------------------------- FOR THE 2001 PERIOD ENDED DISTRIBUTIONS PER UNIT PAYMENT DATE -------------------------------------------------------------------------------- June 30 $0.28 July 16, 2001 July 31 $0.28 August 15, 2001 August 31 $0.22 September 17, 2001 September 30 $0.22 October 15, 2001 October 31 $0.15 November 15, 2001 November 30 $0.15 December 17, 2001 December 31 $0.15 January 15, 2002 ----- Total $1.45 34 -------------------------------------------------------------------------------- FOR THE 2001 PERIOD ENDED DISTRIBUTIONS PER UNIT PAYMENT DATE -------------------------------------------------------------------------------- January 31 $0.15 February 15, 2002 February 28 $0.13 March 15, 2002 March 31 $0.13 April 15, 2002 April 30 $0.13 May 15, 2002 May 31 $0.13 June 17, 2002 June 30 $0.13 July 15, 2002 July 31 $0.13 August 15, 2002 August 31 $0.13 September 16, 2002 September 30 $0.13 October 15, 2002 October 31 $0.18 November 15, 2002 November 30 $0.18 December 16, 2002 December 31 $0.18 January 15, 2003 ----- Total $1.73 -------------------------------------------------------------------------------- FOR THE 2001 PERIOD ENDED DISTRIBUTIONS PER UNIT PAYMENT DATE -------------------------------------------------------------------------------- January 31 $0.18 February 18, 2003 February 28 $0.23 March 17, 2003 March 31 $0.23 April 15, 2003 April 30 $0.23 May 15, 2003 May 31 $0.23 June 16, 2003 June 30 $0.23 July 15, 2003 July 31 $0.23 August 15, 2003 August 31 $0.23 September 15, 2003 September 30 $0.23 October 15,2003 October 31 $0.23 November 17, 2003 November 30 $0.23 December 15, 2003 December 31 $0.23 January 15, 2004 ----- Total $2.71 -------------------------------------------------------------------------------- FOR THE 2001 PERIOD ENDED DISTRIBUTIONS PER UNIT PAYMENT DATE -------------------------------------------------------------------------------- January 31 $0.23 February 17, 2004 February 29 $0.23 March 15, 2004 March 31 $0.23 April 15, 2004 April 30 $0.23 May 17, 2004 May 31 $0.23 June 15, 2004 June 30 $0.23 July 15, 2004 July 31 $0.23 August 16, 2004 August 31(1) $0.23 September 15, 2004 ----- Total $1.84 Note: (1) The Trust announced on August 17, 2004 that a distribution of $0.23 per Trust Unit will be paid on September 15, 2004 to Unitholders of record on August 31, 2004. On August 24, 2004 the Trust announced that subject to closing the Acquisition on or before September 30, 2004, the monthly distribution of distributable cash to be paid on November 15, 2004 to Unitholders of record on October 29, 2004 will be $0.25 per Unit. The Trust intends to make cash distributions on the 15th day of each month (or the first Business Day thereafter) to holders of Trust Units of record on the immediately preceding record date. 35 Accordingly, if the Acquisition closes on or before September 30, 2004 as currently contemplated, holders of Subscription Receipts will become holders of Units on or before September 30, 2004 and will be entitled as Unitholders, provided they are the holders of record of Units received pursuant to the Subscription Receipts on September 30, 2004, to receive the monthly distribution expected to be paid on October 15, 2004 to Unitholders of record on September 30, 2004. If the closing of the Acquisition occurs after September 30, 2004, but on or before November 1, 2004, holders of record of Subscription Receipts on the date they are exchanged for Units will be entitled to receive a payment equivalent to the distribution that will be paid by the Trust to Unitholders of record on September 30, 2004 or any subsequent Unit distribution record date (being on or about the last day of each month) prior to such closing. See "Details of the Offering". USE OF PROCEEDS The net proceeds to the Trust from the sale of the Subscription Receipts and the Debentures hereunder are estimated to be $181,910,000 after deducting the fees of $8,290,000 payable to the Underwriters and the estimated expenses of the issue of $600,000. The net proceeds of the offering will be used by the Trust to pay the purchase price of the Acquisition and to repay indebtedness under the Credit Facilities. See "Recent Developments" and "Relationship Among the Trust and Certain Underwriters". DETAILS OF THE OFFERINGS SUBSCRIPTION RECEIPTS The following is a summary of the material attributes and characteristics of the Subscription Receipts. This summary does not purport to be complete and is subject to, and qualified in its entirety by, reference to the terms of the Subscription Receipt Agreement. At closing, a certificate representing the Subscription Receipts will be issued in registered form to CDS or its nominee, CDS & Co., and will be deposited with CDS on the closing date of this offering pursuant to the book-entry only system. Unless the book-entry only system is terminated, and except in certain limited circumstances, owners of beneficial interests in Subscription Receipts shall not receive a certificate for subscription receipts or, unless requested, for the Trust Units issuable on the exchange of the Subscription Receipts. Beneficial interests in Subscription Receipts will generally be represented solely through the book-entry only system and such interests will be evidenced by customer confirmations of purchase from the Underwriters. The Escrowed Funds will be delivered to and held by the Escrow Agent and invested in short-term obligations of, or guaranteed by, the Government of Canada (and other approved investments) pending the closing of the Acquisition. Provided that the closing of the Acquisition occurs by 5:00 p.m. (Calgary time) on November 1, 2004, the Escrowed Funds and the interest earned thereon will be released to the Trust and the Units will be issued to holders of Subscription Receipts who will receive, without payment of additional consideration or further action, one Unit for each Subscription Receipt held. Forthwith upon the closing of the Acquisition, the Trust will execute and deliver to the Escrow Agent a notice thereof, and will issue and deliver the Units to the Escrow Agent. Contemporaneously with the delivery of such notice, the Trust will issue a press release specifying that the Units have been issued. If the closing of the Acquisition does not take place by 5:00 p.m. (Calgary time) on November 1, 2004, the Acquisition is terminated at any earlier time or the Trust has advised the Underwriters or announced to the public that it does not intend to proceed with the Acquisition (in any case, the "TERMINATION TIME"), holders of Subscription Receipts shall be entitled to receive an amount equal to the full subscription price therefor and their PRO RATA entitlements to interest on such amount. The Escrowed Funds and interest earned thereon will be applied toward payment of such amount. If the closing of the Acquisition takes place prior to the Termination Time and holders of Subscription Receipts become entitled to receive Units pursuant to the Subscription Receipt Agreement, holders of record of Subscription Receipts on the date they are exchanged for Units will be entitled to receive an amount per Subscription Receipt equal to the amount per Unit of any cash distributions for which record dates have occurred during the period from the date of closing of the offering to the date immediately preceding the date the Units are issued pursuant to the Subscription Receipts (the "SPECIAL INTEREST"). All or a portion of this amount will be satisfied by the payment by 36 the Escrow Agent to holders of Subscription Receipts of interest earned on the Escrowed Funds. The difference, if any, between the amount of interest earned on the Escrowed Funds and the Special Interest will be paid by the Trust. If holders of Subscription Receipts become entitled to receive Units, the Escrow Agent and the Trust will pay such amounts to holders of record of Subscription Receipts on the date they are exchanged for Units on the later of the date the Units are issued and the date such distribution(s) is paid to Unitholders. For greater certainty, if the closing of the Acquisition takes place on a date that is a Unit distribution record date, holders of record of Subscription Receipts on such date shall not be entitled as such to receive a payment in respect of the cash distribution for such record date but shall instead be deemed to be holders of record of Units on such date and will be entitled as Unitholders to receive such monthly distribution. Accordingly, if the Acquisition closes on or before September 30, 2004 as currently contemplated, holders of Subscription Receipts will become holders of Units on or before September 30, 2004 and will be entitled as Unitholders, provided they are the holders of record of Units received pursuant to the Subscription Receipts on September 30, 2004, to receive the monthly distribution expected to be paid on October 15, 2004 to Unitholders of record on September 30, 2004. If the closing of the Acquisition occurs after September 30, 2004, but on or before November 1, 2004, holders of record of Subscription Receipts on the date they are exchanged for Units will be entitled to receive a payment equivalent to the distribution that will be paid by the Trust to Unitholders of record on September 30, 2004 or any subsequent Unit distribution record date (being on or about the last day of each month) prior to such closing. Under the Subscription Receipt Agreement, original purchasers of Subscription Receipts under the offering will have a contractual right of rescission following the issuance of Units to such purchaser upon the exchange of the Subscription Receipts to receive the amount paid for the Subscription Receipts if this short form prospectus (including documents incorporated by reference) and any amendment contains a misrepresentation or is not delivered to such purchaser, provided such remedy for rescission is exercised within 180 days of closing of the offering. HOLDERS OF SUBSCRIPTION RECEIPTS ARE NOT UNITHOLDERS. HOLDERS OF SUBSCRIPTION RECEIPTS ARE ENTITLED ONLY TO RECEIVE UNITS ON SURRENDER OF THEIR SUBSCRIPTION RECEIPTS TO THE ESCROW AGENT OR TO A RETURN OF THE SUBSCRIPTION PRICE FOR THE SUBSCRIPTION RECEIPTS TOGETHER WITH ANY PAYMENTS IN LIEU OF INTEREST OR DISTRIBUTIONS, AS APPLICABLE, AS DESCRIBED ABOVE. DEBENTURES The offering of Debentures consists of 75,000 7.50% Debentures and 50,000 7.75% Debentures, each at a price of $1,000 per Debenture. The following is a summary of the material attributes and characteristics of the Debentures. This summary does not purport to be complete and is subject to, and qualified in its entirety by, reference to the terms of the Indenture referred to below. GENERAL The Debentures will be issued under the Indenture. The Debentures authorized for issue immediately will be limited in aggregate principal amount to $75,000,000 7.50% Debentures and $50,000,000 7.75% Debentures. The Trust may, however, from time to time, without the consent of the holders of the Debentures but subject to the limitations described herein, issue additional debentures of the same series or of a different series under the Indenture, in addition to the Debentures offered hereby. The Debentures will be issuable only in denominations of $1,000 and integral multiples thereof. The 7.50% Debentures will be dated as of the closing date of the offering and will have an initial maturity date of November 1, 2004. If the closing of the Acquisition takes place by the Termination Time in all material respects as contemplated in the Acquisition Agreement, the maturity date will be automatically extended from the Initial Maturity Date to October 1, 2009. If the closing of the Acquisition does not take place by the Termination Time, the 7.50% Debentures will mature on the Initial Maturity Date. 37 The 7.50% Debentures will bear interest from the date of issue at 7.50% per annum, which will be payable semi-annually in arrears on April 1 and October 1 in each year, commencing with April 1, 2005. The first interest payment will include interest accrued from the closing of the offering to but excluding April 1, 2005. The 7.75% Debentures will be dated as of the closing date of the offering and will have an initial maturity date of November 1, 2004. If the closing of the Acquisition takes place by the Termination Time in all material respects as contemplated in the Acquisition Agreement, the maturity date will be automatically extended from the Initial Maturity Date to December 1, 2011. If the closing of the Acquisition does not take place by the Termination Time, the 7.75% Debentures will mature on the Initial Maturity Date. The 7.75% Debentures will bear interest from the date of issue at 7.75% per annum, which will be payable semi-annually in arrears on June 1 and December 1 in each year, commencing with June 1, 2005. The first interest payment will include interest accrued from the closing of the offering to but excluding June 1, 2005. The principal amount of the Debentures will be payable in lawful money of Canada or, at the option of the Trust and subject to applicable regulatory approval, by payment of Units as further described under "Payment upon Redemption or Maturity" and "Redemption and Purchase". The interest on the Debentures will be payable in lawful money of Canada including, at the option of the Trust and subject to applicable regulatory approval, in accordance with the Unit Interest Payment Obligation as described under "Interest Payment Option". The Debentures will be direct obligations of the Trust and will not be secured by any mortgage, pledge, hypothec or other charge and will be subordinated to other liabilities of the Trust as described under "Subordination". Other than as described herein, the Indenture will not restrict the Trust from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its properties to secure any indebtedness. CONVERSION PRIVILEGE The 7.50% Debentures will be convertible at the holder's option into fully paid and non-assessable Units at any time prior to 5:00 p.m. (Calgary time) on the earlier of the maturity date, being the Initial Maturity Date or the 7.50% Final Maturity Date, as applicable, and the business day immediately preceding the date specified by the Trust for redemption of the 7.50% Debentures, at a conversion price of $20.25 per Unit (the "7.50% CONVERSION PRICE"), being a conversion rate of 49.3827 Units for each $1,000 principal amount of 7.50% Debentures. No adjustment will be made for distributions on Units issuable upon conversion or for interest accrued on 7.50% Debentures surrendered for conversion; however, holders converting their 7.50% Debentures will receive accrued and unpaid interest thereon. Notwithstanding the foregoing, no 7.50% Debentures may be converted during the three business days preceding April 1 and October 1 in each year, commencing April 1, 2005, as the registers of the Debenture Trustee will be closed during such periods. The 7.75% Debentures will be convertible at the holder's option into fully paid and non-assessable Units at any time prior to 5:00 p.m. (Calgary time) on the earlier of the maturity date, being the Initial Maturity Date or the 7.75% Final Maturity Date, as applicable, and the business day immediately preceding the date specified by the Trust for redemption of the 7.75% Debentures, at a conversion price of $21.00 per Unit (the "7.75% CONVERSION PRICE"), being a conversion rate of 47.6190 Units for each $1,000 principal amount of 7.75% Debentures. No adjustment will be made for distributions on Units issuable upon conversion or for interest accrued on 7.75% Debentures surrendered for conversion; however, holders converting their 7.75% Debentures will receive accrued and unpaid interest thereon. Notwithstanding the foregoing, no 7.75% Debentures may be converted during the three business days preceding June 1 and December 1 in each year, commencing June 1, 2005, as the registers of the Debenture Trustee will be closed during such periods. "CONVERSION PRICE" means the 7.50% Conversion Price in respect of the 7.50% Debentures and the 7.75% Conversion Price in respect of the 7.75% Debentures. Subject to the provisions thereof, the Indenture will provide for the adjustment of the Conversion Price in certain events including: (a) the subdivision or consolidation of the outstanding Units; (b) the distribution of Units to holders of Units by way of distribution or otherwise other than an issue of securities to holders of Units who have elected to receive distributions in securities of the Trust in lieu of receiving cash distributions paid in the ordinary course; (c) the issuance of options, rights or warrants to holders of Units entitling them to acquire Units or other securities convertible into Units at less than 95% of the then current market price (as defined below under "Payment upon 38 Redemption or Maturity") of the Units; and (d) the distribution to all holders of Units of any securities or assets (other than cash distributions and equivalent distributions in securities paid in lieu of cash distributions in the ordinary course). There will be no adjustment of the Conversion Price in respect of any event described in (b), (c) or (d) above if the holders of the Debentures are allowed to participate as though they had converted their Debentures prior to the applicable record date or effective date. The Trust will not be required to make adjustments in the Conversion Price unless the cumulative effect of such adjustments would change the conversion price by at least 1%. The term "current market price" will be defined in the Indenture to mean the weighted average trading price of the Units on the TSX for the 20 consecutive trading days ending on the fifth trading day preceding the date fixed for redemption or the maturity date, as the case may be. In the case of any reclassification or capital reorganization (other than a change resulting from consolidation or subdivision) of the Units or in the case of any consolidation, amalgamation or merger of the Trust with or into any other entity, or in the case of any sale or conveyance of the properties and assets of the Trust as, or substantially as, an entirety to any other entity, or a liquidation, dissolution or winding-up of the Trust, the terms of the conversion privilege shall be adjusted so that each holder of a Debenture shall, after such reclassification, capital reorganization, consolidation, amalgamation, merger, sale, conveyance, liquidation, dissolution or winding up, be entitled to receive the number of Units or other securities or property such holder would be entitled to receive if on the effective date thereof, it had been the holder of the number of Units into which the Debenture was convertible prior to the effective date of such reclassification, capital reorganization, consolidation, amalgamation, merger, sale, conveyance, liquidation, dissolution or winding up. No fractional Units will be issued on any conversion but in lieu thereof the Trust shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest. REDEMPTION AND PURCHASE The 7.50% Debentures will not be redeemable on or before October 1, 2007. After October 1, 2007 and prior to maturity, the 7.50% Debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days prior notice, at a redemption price of $1,050 per 7.50% Debenture after October 1, 2007 and on or before October 1, 2008 and at a redemption price of $1,025 per 7.50% Debenture after October 1, 2008 and before maturity (each a "7.50% REDEMPTION PRICE"), in each case, plus accrued and unpaid interest thereon, if any. The 7.75% Debentures will not be redeemable on or before December 1, 2007. After December 1, 2007 and prior to maturity, the 7.75% Debentures may be redeemed in whole or in part from time to time at the option of the Trust on not more than 60 days and not less than 30 days prior notice, at a redemption price of $1,050 per 7.75% Debenture after December 1, 2007 and on or before December 1, 2008, at a redemption price of $1,025 per 7.75% Debenture after December 1, 2008 and on or before December 1, 2009 and at a redemption price of $1,000 per 7.75% Debenture after December 1, 2009 and before maturity (each a "7.75% REDEMPTION PRICE"), in each case, plus accrued and unpaid interest thereon, if any. "REDEMPTION PRICE" means the 7.50% Redemption Price in respect of the 7.50% Debentures and the 7.75% Redemption Price in respect of the 7.75% Debentures. In the case of redemption of less than all of the Debentures, the Debentures to be redeemed will be selected by the Debenture Trustee on a PRO RATA basis or in such other manner as the Debenture Trustee deems equitable, subject to the consent of the TSX. The Trust will have the right to purchase Debentures in the market, by tender or by private contract. PAYMENT UPON REDEMPTION OR MATURITY On redemption or at maturity, the Trust will repay the indebtedness represented by the Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, together with accrued and unpaid interest thereon. The Trust may, at its option, on not 39 more than 60 days and not less than 40 days prior notice and subject to applicable regulatory approval, elect to satisfy its obligation to pay the Redemption Price of the Debentures which are to be redeemed or the principal amount of the Debentures which have matured, as the case may be, by issuing Units to the holders of the Debentures. Any accrued and unpaid interest thereon will be paid in cash. The number of Units to be issued will be determined by dividing the aggregate Redemption Price of the outstanding Debentures which are to be redeemed or the principal amount of the outstanding Debentures which have matured, as the case may be, by 95% of the current market price on the date fixed for redemption or the maturity date, as the case may be. Although the Trust will have the option to satisfy its obligation to pay the principal amount of the Debentures due on the Initial Maturity Date by issuing Trust Units, if the Acquisition is not completed prior to the Termination Time, the Trust currently intends to repay the amounts due on the Initial Maturity Date with cash. No fractional Units will be issued on redemption or maturity but in lieu thereof the Trust shall satisfy fractional interests by a cash payment equal to the current market price of any fractional interest. SUBORDINATION The payment of the principal of, and interest on, the Debentures will be subordinated in right of payment, as set forth in the Indenture, to the prior payment in full of all Senior Indebtedness of the Trust and indebtedness to trade creditors of the Trust. "Senior Indebtedness" of the Trust will be defined in the Indenture as the principal of and premium, if any, and interest on and other amounts in respect of all indebtedness of the Trust (whether outstanding as at the date of the Indenture or thereafter incurred), other than indebtedness evidenced by the Debentures and all other existing and future debentures or other instruments of the Trust which, by the terms of the instrument creating or evidencing the indebtedness, is expressed to be PARI PASSU with, or subordinate in right of payment to, the Debentures. The Indenture will provide that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings relative to the Trust, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding-up of the Trust, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of the Trust, then those holders of Senior Indebtedness, including any indebtedness to trade creditors, will receive payment in full before the holders of Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any of the Debentures or any unpaid interest accrued thereon. The Indenture will also provide that the Trust will not make any payment, and the holders of the Debentures will not be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including, without any limitation, by set-off, combination of accounts or realization of security or otherwise in any manner whatsoever) on account of indebtedness represented by the Debentures (a) in a manner inconsistent with the terms (as they exist on the date of issue) of the Debentures or (b) at any time when an event of default has occurred under the Senior Indebtedness and is continuing and the notice of such event of default has been given by or on behalf of the holders of Senior Indebtedness to the Trust, unless the Senior Indebtedness has been repaid in full. The Debentures will also be effectively subordinate to claims of creditors of the Trust's subsidiaries except to the extent the Trust is a creditor of such subsidiaries ranking at least PARI PASSU with such other creditors. The Debentures will also be subordinated in right of payment to the prior payment in full of all indebtedness under the Credit Facilities. PRIORITY OVER TRUST DISTRIBUTIONS The Trust Indenture provides that certain expenses of the Trust must be deducted in calculating the amount to be distributed to the Unitholders. Accordingly, the funds required to satisfy the interest payable on the Debentures, as well as the amount payable upon redemption or maturity of the Debentures or upon an Event of Default (as defined below), will be deducted and withheld from the amounts that would otherwise be payable as distributions to Unitholders. 40 CHANGE OF CONTROL OF THE TRUST Within 30 days following the occurrence of a change of control of the Trust involving the acquisition of voting control or direction over 66?% or more of the Units (a "CHANGE OF CONTROL"), the Trust will be required to make an offer in writing to purchase all of the Debentures then outstanding (the "DEBENTURE OFFER"), at a price equal to 101% of the principal amount thereof plus accrued and unpaid interest (the "DEBENTURE OFFER PRICE"). The Indenture contains notification and repurchase provisions requiring the Trust to give written notice to the Debenture Trustee of the occurrence of a Change of Control within 30 days of such event together with the Debenture Offer. The Debenture Trustee will thereafter promptly mail to each holder of Debentures a notice of the Change of Control together with a copy of the Debenture Offer to repurchase all the outstanding Debentures. If 90% or more of the aggregate principal amount of the Debentures outstanding on the date of the giving of notice of the Change of Control have been tendered to the Trust pursuant to the Debenture Offer, the Trust will have the right and obligation to redeem all the remaining Debentures at the Debenture Offer Price. Notice of such redemption must be given by the Trust to the Debenture Trustee within 10 days following the expiry of the Debenture Offer, and as soon as possible thereafter, by the Debenture Trustee to the holders of the Debentures not tendered pursuant to the Debenture Offer. INTEREST PAYMENT OPTION The Trust may elect, from time to time, to satisfy its obligation to pay all or any part of the interest on the Debentures (the "INTEREST OBLIGATION"), on the date it is payable under the Indenture (an "INTEREST PAYMENT Date"), by delivering sufficient Units to the Debenture Trustee to satisfy all or the part, as the case may be, of the Interest Obligation in accordance with the Indenture (the "UNIT INTEREST PAYMENT ELECTION"). The Indenture will provide that, upon such election, the Debenture Trustee shall (a) accept delivery from the Trust of Units, (b) accept bids with respect to, and consummate sales of, such Units, each as the Trust shall direct in its absolute discretion, (c) invest the proceeds of such sales in short-term permitted government securities (as defined in the Indenture) which mature prior to the applicable Interest Payment Date, and use the proceeds received from such permitted government securities, together with any proceeds from the sale of Units not invested as aforesaid, to satisfy the Interest Obligation, and (d) perform any other action necessarily incidental thereto. The Indenture will set forth the procedures to be followed by the Trust and the Debenture Trustee in order to effect the Unit Interest Payment Election. If a Unit Interest Payment Election is made, the sole right of a holder of Debentures in respect of interest will be to receive cash from the Debenture Trustee out of the proceeds of the sale of Units (plus any amount received by the Debenture Trustee from the Trust attributable to any fractional Units) in full satisfaction of the Interest Obligation, and the holder of such Debentures will have no further recourse to the Trust in respect of the Interest Obligation. Neither the Trust's making of the Unit Interest Payment Election nor the consummation of sales of Units will (a) result in the holders of the Debentures not being entitled to receive on the applicable Interest Payment Date cash in an aggregate amount equal to the interest payable on such Interest Payment Date, or (b) entitle such holders to receive any Units in satisfaction of the Interest Obligation. EVENTS OF DEFAULT The Indenture will provide that an event of default ("EVENT OF DEFAULT") in respect of the Debentures will occur if any one or more of the following described events has occurred and is continuing with respect of the Debentures: (a) failure for 10 days to pay interest on the Debentures when due; (b) failure to pay principal or premium, if any, on the Debentures when due, whether at maturity, upon redemption, by declaration or otherwise; (c) certain events of bankruptcy, insolvency or reorganization of the Trust under bankruptcy or insolvency laws; or (d) default in the observance or performance of any material covenant or condition of the Indenture and continuance of such default for a period of 30 days after notice in writing has been given by the Debenture Trustee to the Trust specifying such default and requiring the Trust to rectify the same. If an Event of Default has occurred and is continuing, the Debenture Trustee may, in its discretion, and shall upon request of holders of not less than 25% of the principal amount of Debentures then outstanding, declare the principal of and interest on all outstanding Debentures to be 41 immediately due and payable. In certain cases, the holders of more than 50% of the principal amount of the Debentures then outstanding may, on behalf of the holders of all such Debentures, waive any Event of Default and/or cancel any such declaration upon such terms and conditions as such holders shall prescribe. Certain Events of Default under the Indenture may only be Events of Default in relation to a particular series of debentures in which case such provisions would apply only in relation to such series. OFFERS FOR DEBENTURES The Indenture will contain provisions to the effect that if an offer is made for the Debentures which is a take-over bid for Debentures within the meaning of the SECURITIES ACT (Alberta) and not less than 90% of the Debentures (other than Debentures held at the date of the take-over 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 Debentures held by the holders of Debentures who did not accept the offer on the terms offered by the offeror. MODIFICATION The rights of the holders of the Debentures as well as any other series of debentures that may be issued under the Indenture may be modified in accordance with the terms of the Indenture. For that purpose, among others, the Indenture will contain certain provisions which will make binding on all Debenture holders resolutions passed at meetings of the holders of Debentures by votes cast thereat by holders of not less than 66?% of the principal amount of the Debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66?% of the principal amount of the Debentures then outstanding. In certain cases, the modification will, instead or in addition, require assent by the holders of the required percentage of Debentures of each particularly affected series. LIMITATION ON ISSUANCE OF ADDITIONAL DEBENTURES The Indenture will provide that the Trust shall not issue additional convertible debentures of equal ranking if the principal amount of all issued and outstanding convertible debentures of the Trust exceeds 25% of the Total Market Capitalization of the Trust immediately after the issuance of such additional convertible debentures. "Total Market Capitalization" will be defined in the Indenture as the total principal amount of all issued and outstanding debentures of the Trust which are convertible at the option of the holder into Units of the Trust plus the amount obtained by multiplying the number of issued and outstanding Units of the Trust (including Trust Units represented by Subscription Receipts) by the current market price of the Units on the relevant date. LIMITATION ON NON-RESIDENT OWNERSHIP AOG may, at any time and from time to time, in its sole discretion, request that the Debenture Trustee make reasonable efforts, as practicable in the circumstances, to obtain declarations as to beneficial ownership of Debentures, perform residency searches of holders of Debentures and beneficial holders of Debentures mailing address lists and take such other steps specified by AOG to determine or estimate as best possible the residence of the beneficial owners of Debentures. If at any time the board of directors of AOG, in its sole discretion, determines that it is in the best interest of the Trust, AOG may: (i) require the Debenture Trustee to refuse to accept a subscription for the Debentures from, or issue or register a transfer of Trust Units to, a person unless the person provides a declaration to AOG that the Debentures to be issued or transferred to such person will not when issued or transferred be beneficially owned by a non-resident of Canada; (ii) to the extent practicable in the circumstances, send a notice to registered holders of the Debentures which are beneficially owned by non-residents of Canada, chosen in inverse order to the order of acquisition or registration of such Debentures beneficially owned by non-residents of Canada or in such other manner as AOG may consider equitable and practicable, requiring them to sell their Debentures which are beneficially owned by non-residents of Canada or a specified portion thereof within a specified period of not less than 60 days. If the holders of Debentures receiving such notice have not sold the specified number of such Debentures or provided AOG with satisfactory evidence that such Debentures are not beneficially owned by non-residents within such period, AOG may, on behalf of such registered holder of Debentures, sell such Debentures and, in the interim, suspend the rights attached to such Debentures; and (iii) take such other actions as the board of directors of AOG determines, in its sole discretion, are appropriate in the 42 circumstances that will reduce or limit the number of Debentures held by non-residents to ensure that the Trust is not maintained primarily for the benefit of non-residents of Canada. BOOK-ENTRY SYSTEM FOR DEBENTURES The Debentures will be issued in "book-entry only" form and must be purchased or transferred through a participant in the depository service of CDS (a "PARTICIPANT"). On the closing date of the offering, the Debenture Trustee will cause the Debentures to be delivered to CDS and registered in the name of its nominee. The Debentures will be evidenced by a single book-entry only certificate. Registration of interests in and transfers of the Debentures will be made only through the depository service of CDS. Except as described below, a purchaser acquiring a beneficial interest in the Debentures (a "BENEFICIAL OWNER") will not be entitled to a certificate or other instrument from the Debenture Trustee or CDS evidencing that purchaser's interest therein, and such purchaser will not be shown on the records maintained by CDS, except through a Participant. Such purchaser will receive a confirmation of purchase from the Underwriter or other registered dealer from whom Debentures are purchased. Neither the Trust nor the Underwriters will assume any liability for: (a) any aspect of the records relating to the beneficial ownership of the Debentures held by CDS or the payments relating thereto; (b) maintaining, supervising or reviewing any records relating to the Debentures; or (c) any advice or representation made by or with respect to CDS and contained in this short form prospectus and relating to the rules governing CDS or any action to be taken by CDS or at the direction of its Participants. The rules governing CDS provide that it acts as the agent and depositary for the Participants. As a result, Participants must look solely to CDS and Beneficial Owners must look solely to Participants for the payment of the principal and interest on the Debentures paid by or on behalf of the Trust to CDS. As indirect holders of Debentures, investors should be aware that they (subject to the situations described below): (a) may not have Debentures registered in their name; (b) may not have physical certificates representing their interest in the Debentures; (c) may not be able to sell the Debentures to institutions required by law to hold physical certificates for securities they own; and (d) may be unable to pledge Debentures as security. The Debentures will be issued to Beneficial Owners in fully registered and certificate form (the "DEBENTURE CERTIFICATES") only if: (a) required to do so by applicable law; (b) the book-entry only system ceases to exist; (c) the Trust or CDS advises the Debenture Trustee that CDS is no longer willing or able to properly discharge its responsibilities as depositary with respect to the Debentures and the Trust is unable to locate a qualified successor; (d) the Trust, at its option, decides to terminate the book-entry only system through CDS; or (e) after the occurrence of an Event of Default (as defined herein), provided that Participants acting on behalf of Beneficial Owners representing, in the aggregate, more than 25% of the aggregate principal amount of the Debentures then outstanding advise CDS in writing that the continuation of a book-entry only system through CDS is no longer in their best interest, and provided further that the Debenture Trustee has not waived the Event of Default in accordance with the terms of the Indenture. Upon the occurrence of any of the events described in the immediately preceding paragraph, the Debenture Trustee must notify CDS, for and on behalf of Participants and Beneficial Owners, of the availability through CDS of Debenture Certificates. Upon surrender by CDS of the single certificate representing the Debentures and receipt of instructions from CDS for the new registrations, the Debenture Trustee will deliver the Debentures in the form of Debenture Certificates and thereafter the Trust will recognize the holders of such Debenture Certificates as debentureholders under the Indenture. Interest on the Debentures will be paid directly to CDS while the book-entry only system is in effect. If Debenture Certificates are issued, interest will be paid by cheque drawn on the Trust and sent by prepaid mail to the registered holder or by such other means as may become customary for the payment of interest. Payment of principal, including payment in the form of Units if applicable, and the interest due, at maturity or on a redemption date, will be paid directly to CDS while the book-entry only system is in effect. If Debenture Certificates are issued, payment of principal, including payment in the form of Units if applicable, and interest due, at maturity or on a redemption date, will be paid upon surrender thereof at any office of the Debenture Trustee or as otherwise specified in the Indenture. 43 PLAN OF DISTRIBUTION Pursuant to the Underwriting Agreement, the Trust has agreed to issue and sell an aggregate of 3,500,000 Subscription Receipts, an aggregate of 75,000 7.50% Debentures and an aggregate of 50,000 7.75% Debentures to the Underwriters, and the Underwriters have severally agreed to purchase such Subscription Receipts and Debentures on September 14, 2004, or such other date as may be agreed among the parties to the Underwriting Agreement. Delivery of the Subscription Receipts and Debentures is conditional upon payment on closing of $18.80 per Subscription Receipt by the Underwriters to the Escrow Agent and $1,000 per Debenture by the Underwriters to the Trust. The Underwriting Agreement provides that the Trust will pay the Underwriters' fee of $0.94 per Subscription Receipt for Subscription Receipts issued and sold by the Trust and $40 per Debenture for Debentures issued and sold by the Trust, for an aggregate fee payable by the Trust of $8,290,000, in consideration for their services in connection with the offering. The Underwriters' fee in respect of the Subscription Receipts is payable as to 50% upon the closing of the offering and 50% upon closing of the Acquisition. If the Acquisition is not completed by November 1, 2004, the Underwriters' fee in respect of the Subscription Receipts will be reduced to the amount payable upon closing of the offering. The Underwriters' fee in respect of the Debentures is payable on closing of the offering. The terms of the offering were determined by negotiation between AOG and the Manager, on behalf of the Trust, and Scotia Capital Inc., on its own behalf and on behalf the other Underwriters. The obligations of the Underwriters under the Underwriting Agreement are several and not joint, and may be terminated at their discretion upon the occurrence of certain stated events. THE OBLIGATIONS OF THE TRUST AND THE UNDERWRITERS UNDER THE UNDERWRITING AGREEMENT TO COMPLETE THE PURCHASE AND SALE OF THE SUBSCRIPTION RECEIPTS AND DEBENTURES WILL TERMINATE AUTOMATICALLY IF THE ACQUISITION IS TERMINATED OR THE TRUST HAS ADVISED THE UNDERWRITERS OR ANNOUNCED TO THE PUBLIC THAT IT DOES NOT INTEND TO PROCEED WITH THE ACQUISITION. If an Underwriter fails to purchase the Subscription Receipts or the Debentures that it has agreed to purchase, the other Underwriters may, but are not obligated to, purchase such Subscription Receipts or Debentures. The Underwriters are, however, obligated to take up and pay for all Subscription Receipts and Debentures if any are purchased under the Underwriting Agreement. The Underwriting Agreement also provides that the Trust and AOG will indemnify the Underwriters and their directors, officers, agents, shareholders and employees against certain liabilities and expenses. Except in certain limited circumstances, the Subscription Receipts and the Debentures will be issued in "book-entry only" form and must be purchased or transferred through a participant in the depository service of CDS. See "Details of the Offering - Subscription Receipts" and "Details of the Offering - Book-Entry System for Debentures". The Trust has been advised by the Underwriters that, in connection with the offering, the Underwriters may effect transactions that stabilize or maintain the market price of the Subscription Receipts, the Units or the Debentures at levels other than those that might otherwise prevail in the open market. Such transactions, if commenced, may be discontinued at any time. The Trust has agreed that, subject to certain exceptions, it will not offer or issue, or enter into an agreement to offer or issue, Units or any securities convertible or exchangeable into Units for a period of 90 days subsequent to the closing date of the offering without the consent of Scotia Capital Inc., on behalf of the Underwriters, which consent may not be unreasonably withheld. The TSX has conditionally approved the listing of the Subscription Receipts, 7.50% Debentures and the 7.75% Debentures offered hereunder and the Units issuable pursuant to the Subscription Receipts and on the conversion, redemption and maturity of the Debentures. Listing will be subject to the Trust fulfilling all of the listing requirements of the TSX on or before November 24, 2004. THE SUBSCRIPTION RECEIPTS AND THE DEBENTURES OFFERED HEREBY AND THE UNITS ISSUABLE PURSUANT TO THE SUBSCRIPTION RECEIPTS AND ON CONVERSION, REDEMPTION OR MATURITY OF THE DEBENTURES (THE "SECURITIES") HAVE NOT BEEN AND WILL NOT BE REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE "U.S. 44 SECURITIES ACT"), OR ANY STATE SECURITIES LAWS, AND, ACCORDINGLY, THE SUBSCRIPTION RECEIPTS AND THE DEBENTURES MAY NOT BE OFFERED OR SOLD WITHIN THE UNITED STATES OR TO U.S. PERSONS (AS SUCH TERM IS DEFINED IN REGULATION S UNDER THE U.S. SECURITIES ACT). EACH UNDERWRITER HAS AGREED THAT IT WILL NOT OFFER OR SELL THE SUBSCRIPTION RECEIPTS OR DEBENTURES WITHIN THE UNITED STATES OR TO, OR FOR THE ACCOUNT OF, UNITED STATES PERSONS, AND WILL NOT CONDUCT ANY DIRECTED SELLING EFFORTS IN THE UNITED STATES (AS SUCH TERM IS DEFINED IN REGULATION S TO THE U.S. SECURITIES ACT) OR ANY OTHER JURISDICTION OUTSIDE OF CANADA. RELATIONSHIP AMONG THE TRUST AND CERTAIN UNDERWRITERS Four of the Underwriters, are direct or indirect wholly owned subsidiaries of four of the lenders of the Trust pursuant to the Credit Facilities. Accordingly, the Trust may be considered a connected issuer of Scotia Capital Inc., BMO Nesbitt Burns Inc., National Bank Financial Inc. and RBC Dominion Securities Inc. under applicable securities laws. As at June 30, 2004, approximately $161,707,000 was outstanding under the Credit Facilities. See "Consolidated Capitalization of the Trust". The Trust is in compliance with all material terms of the agreement governing the Credit Facilities and none of the lenders under the Credit Facilities has waived any breach by the Trust of that agreement since its execution. Neither the financial position of the Trust nor the value of the security under the Credit Facilities has changed substantially since the indebtedness under the Credit Facilities was incurred. The decision to distribute the Subscription Receipts and Debentures offered hereunder and the determination of the terms of the distribution were made through negotiations primarily between the Manager and AOG, on behalf of the Trust, and Scotia Capital Inc. on its own behalf and on behalf of the other Underwriters. The lenders under the Credit Facilities did not have any involvement in such decision or determination, but have been advised of the issuance and terms thereof. As a consequence of this issuance, Scotia Capital Inc., BMO Nesbitt Burns Inc., National Bank Financial Inc. and RBC Dominion Securities Inc. will receive their respective share of the Underwriters' fee. In addition, the Trust currently intends to utilize any proceeds from the offering not used for the Acquisition to repay a portion of its indebtedness under the Credit Facilities. INTEREST OF EXPERTS Certain legal matters relating to the offering will be passed upon by Burnet, Duckworth & Palmer LLP on behalf of the Trust, and by Macleod Dixon LLP on behalf of the Underwriters. As at the date hereof, the partners and associates of Burnet, Duckworth & Palmer LLP, as a group and Macleod Dixon LLP, as a group, each own, directly or indirectly, less than 1% of the Trust Units. Reserves estimates contained herein and in the AIF, incorporated by reference into this short form prospectus, are based upon a reports prepared by Sproule. As of the date hereof, the principles of Sproule, as a group, beneficially own, directly or indirectly, less than 1% of the Trust Units. CANADIAN FEDERAL INCOME TAX CONSIDERATIONS In the opinion of Burnet, Duckworth & Palmer LLP and Macleod Dixon LLP (collectively, "COUNSEL"), the following summary fairly describes the principal Canadian federal income tax considerations pursuant to the Tax Act generally applicable to a subscriber who acquires Subscription Receipts or Debentures pursuant to the offering and who, for purposes of the Tax Act, holds the Subscription Receipts, the Debentures and the Units issued pursuant to the Subscription Receipts or on the conversion, redemption or repayment of the Debentures (collectively, the "SECURITIES") as capital property and deals at arm's length with the Trust and the Underwriters. Generally speaking, the Securities will be considered to be capital property to a holder provided the holder does not hold the Securities in the course of carrying on a business of trading or dealing in securities and has not acquired them in one or more transactions considered to be an adventure in the nature of trade. Certain holders who might not otherwise be considered to hold their Securities as capital property may, in certain circumstances, be entitled to have such Securities (other than Subscription Receipts) treated as capital property by making the election permitted by subsection 39(4) of the Tax Act. This summary is not applicable to: (i) a holder that is a "financial institution", as defined in the Tax Act for purposes of the mark-to-market rules; (ii) a holder an interest in which would be a "tax shelter investment" as defined in the Tax Act; or (iii) a holder that is a "specified financial institution" as defined in the Tax Act. Any such holder should consult its own tax advisor with respect to an investment in the Securities. 45 This summary is based upon the provisions of the Tax Act in force as of the date hereof and Counsel's understanding of the current published administrative practices of the Canada Revenue Agency ("CRA"). Except for specifically proposed amendments (the "PROPOSED AMENDMENTS") to the Tax Act that have been publicly announced by the federal Minister of Finance prior to the date hereof, this summary does not take into account or anticipate changes in the income tax law, whether by legislative, governmental or judicial action, nor any changes in the administrative practices of the CRA. This summary is not exhaustive of all Canadian federal income tax considerations nor does it take into account any provincial, territorial or foreign tax considerations arising from the acquisition, ownership or disposition of the Securities. Except as otherwise indicated, this summary is based on the assumption that all transactions described herein occur at fair market value. THIS SUMMARY IS OF A GENERAL NATURE ONLY AND IS NOT INTENDED TO BE, NOR SHOULD IT BE CONSTRUED TO BE, LEGAL OR TAX ADVICE TO ANY PROSPECTIVE PURCHASER OR HOLDER OF SECURITIES, AND NO REPRESENTATIONS WITH RESPECT TO THE INCOME TAX CONSEQUENCES TO ANY PROSPECTIVE PURCHASER OR HOLDER ARE MADE. CONSEQUENTLY, PROSPECTIVE HOLDERS SHOULD CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THEIR PARTICULAR CIRCUMSTANCES. TAXATION OF HOLDERS OF SUBSCRIPTIONS RECEIPTS RESIDENT IN CANADA No gain or loss will be realized by a holder on the issuance of a Unit pursuant to a Subscription Receipt. However, if the Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt, in addition to receiving a Unit in exchange therefor, will be entitled to receive an amount equal to the distributions that the holder would have received on such Unit had the Unit been issued to the holder on the date of closing of this offering. Counsel is of the view that the treatment of this additional amount is unclear and it should either be included as income or characterized as a purchase price adjustment. Counsel is advised that the Trust will treat such amount as consideration for use of money. The cost of any Units acquired must be averaged with the cost of any other Units held by the Unitholder as capital property to determine the adjusted cost base of each Unit held. In the event the Acquisition does not close before the Termination Time or if the Acquisition is terminated at an earlier time, holders of Subscription Receipts will be required to include their proportionate share of interest on the Escrowed Funds in computing their income for purposes of the Tax Act. A disposition or deemed disposition by a holder of a Subscription Receipt, other than on the exchange thereof for a Unit, but including on the repayment of the issue price thereof by the Trust in the event the Acquisition is not completed before the Termination Time, will generally result in the holder realizing a capital gain (or capital loss) equal to the amount by which the proceeds of disposition are greater (or less) than the aggregate of the holder's adjusted cost base thereof and any reasonable costs of disposition. In the event that a holder becomes entitled to the repayment of the issue price of a Subscription Receipt as a consequence of the Acquisition not becoming effective prior to the Termination Time, any amount that is paid to the holder by the Trust as or on account of interest will be included in the holder's income and excluded from the holder's proceeds of disposition. One-half of any capital gain realized by the holder will be included in the holder's income under the Tax Act for the year of disposition as a taxable capital gain. One-half of any capital loss realized on a disposition of a Subscription Receipt may be deducted against taxable capital gains realized by the holder in the year of disposition, in the three preceding taxation years or in any subsequent taxation year, to the extent and under the circumstances described in the Tax Act. A capital gain realized by a holder who is an individual may give rise to a liability for alternative minimum tax. A holder that is throughout the year a "Canadian-controlled private corporation" (as defined in the Tax Act) may be liable to pay an additional refundable tax of 6 ?% on certain investment income, including interest and taxable capital gains. TAXATION OF HOLDERS OF SUBSCRIPTIONS RECEIPTS NOT RESIDENT IN CANADA No gain or loss will be realized by a holder on the issuance of a Unit pursuant to a Subscription Receipt. However, if the Acquisition is completed prior to the Termination Time, the holder of a Subscription Receipt, in addition to receiving a Unit in exchange therefor, will be entitled to receive an amount equal to the distributions that the holder would have received on such Unit had the Unit been issued to the holder on the date of closing of this offering. 46 Counsel is advised that the Trust will be withholding for Canadian withholding tax on such additional amounts at the rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the Unitholder's jurisdiction of residence. Counsel is advised that where a unitholder is resident in the United States and entitled to claim the benefit of the Canada-US Tax Convention the Trust will be withholding at a rate of 10%. In the event the Acquisition does not close before the Termination Time or if the Acquisition is terminated at an earlier time, a holder of Subscription Receipts who is not resident or deemed to be resident in Canada will be subject to withholding tax on such holder's proportionate share of interest on the Escrowed Funds which is paid or credited to such holders at the rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the holder's jurisdiction of residence. A holder resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention will generally be entitled to have the rate of withholding reduced to 10% of the amount of any interest paid or credited. If and to the extent the Escrowed Funds are invested in obligations of, or guaranteed by, the Government of Canada, interest on such obligations that is paid or credited to a non-resident holder of Subscription Receipts will not be subject to Canadian tax. A disposition or deemed disposition of Subscription Receipts will not give rise to any capital gains subject to tax under the Tax Act to a holder who is not resident or deemed to be resident in Canada provided that the Subscription Receipts are not "taxable Canadian property" of the holder for the purposes of the Tax Act. Generally, Subscription Receipts will not constitute "taxable Canadian property" to a non-resident holder at the time of the disposition or deemed disposition thereof unless (i) the holder uses or holds or is deemed to use or hold the Subscription Receipts (or the Trust Units issuable pursuant thereto) in, or in the course of, carrying on a business in Canada, (ii) the Subscription Receipts (or the Trust Units issuable pursuant thereto) are "designated insurance property" of the holder for purposes of the Tax Act, or (iii) the holder, persons with whom the holder does not deal at arm's length (within the meaning of the Tax Act) or the holder together with such persons owned 25% or more of the Units at any time during the 60-month period immediately preceding the disposition. TAXATION OF HOLDERS OF DEBENTURES RESIDENT IN CANADA A holder of Debentures that is a corporation, partnership, unit trust or any trust of which a corporation or a partnership is a beneficiary will be required to include in computing its income for a taxation year all interest on the Debentures that accrues to it to the end of the particular taxation year or that has become receivable or is received by it before the end of that taxation year, except to the extent that such interest was included in computing the holder's income for a preceding taxation year. Any other holder will be required to include in computing income for a taxation year all interest on the Debentures that is received or receivable by the holder in that taxation year (depending upon the method regularly followed by the holder in computing income), except to the extent that the interest was included in the holder's income for a preceding taxation year. In addition, such holder will be required to include in computing income for a taxation year any interest that accrues to the holder on the Debenture to the end of any "anniversary day" (as defined in the Tax Act) in that year to the extent such interest was not otherwise included in the holder's income for that year or a preceding year. A holder of a Debenture who exchanges the Debenture for Units pursuant to the conversion privilege will be considered to have disposed of the Debenture for proceeds of disposition equal to the aggregate of the fair market value of the Units so acquired at the time of the exchange and the amount of any cash received in lieu of any fractional Unit. The cost to the holder of the Units so acquired will be equal to their fair market value at the time of the exchange and must be averaged with the adjusted cost base of all other Units held at that time as capital property by the holder for the purpose of calculating the adjusted cost base of each such Unit. If the Trust redeems a Debenture prior to maturity or repays a Debenture upon maturity and the holder does not exercise the conversion privilege prior to such redemption or repayment, the holder will be considered to have disposed of the Debenture for proceeds of disposition equal to the amount received by the holder (other than the amount received or deemed to be received as interest) on such redemption or repayment. Generally a premium paid on redemption or repurchase prior to maturity will be deemed to be interest. If the holder receives Units on 47 redemption or repayment, the holder will be considered to have received proceeds of disposition equal to the fair market value of the Units so received and the amount of any cash received in lieu of any fractional Unit. The cost to the holder of the Units so received will be equal to their fair market value at the time of the exchange and must be averaged with the adjusted cost base of all other Units held at that time as capital property by the holder for the purpose of calculating the adjusted cost base of each such Unit. On any disposition or deemed disposition of a Debenture as described above or otherwise, the holder thereof will generally realize a capital gain (or capital loss) equal to the amount by which the proceeds of disposition (adjusted as described below) are greater (or less) than the aggregate of the holder's adjusted cost base of the Debenture and any reasonable costs of the disposition. Upon such a disposition or deemed disposition of a Debenture, interest accrued thereon to the date of disposition or otherwise deemed to be received will be included in computing the holder's income, except to the extent such amount was otherwise included in the holder's income, and will be excluded in computing the holder's proceeds of disposition of the Debenture. One-half of any capital gain realized by the holder will be included in the holder's income under the Tax Act for the year of disposition as a taxable capital gain. One-half of any capital loss realized on a disposition of a Debenture may be deducted against taxable capital gains realized by the holder in the year of disposition, in the three preceding taxation years or in any subsequent taxation year, to the extent and under the circumstances described in the Tax Act. A capital gain realized by a holder who is an individual may give rise to a liability for alternative minimum tax. A holder that is throughout the year a "Canadian-controlled private corporation" (as defined in the Tax Act) may be liable to pay an additional refundable tax of 6 2 /3 % on certain investment income, including interest and taxable capital gains. TAXATION OF HOLDERS OF DEBENTURES NOT RESIDENT IN CANADA A holder of a Debenture who is not resident or deemed to be resident in Canada will generally be subject to Canadian withholding tax at the rate of 25% on interest paid or credited pursuant to the Debenture, unless such rate is reduced under the provisions of a tax treaty between Canada and the holder's jurisdiction of residence. A holder of a Debenture resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention will generally be entitled to have the rate of withholding reduced to 10% of the amount of any interest paid or credited. Any premium paid on a redemption or repurchase of Debentures prior to maturity will be deemed to be interest paid or credited and subject to withholding tax. A disposition or deemed disposition of a Debenture, whether on conversion, redemption, or otherwise, will not give rise to any capital gains subject to tax under the Tax Act to a holder who is not resident or deemed to be resident in Canada provided that (i) the holder does not hold or use and is not deemed to hold or use the Debenture in the course of carrying on business in Canada; (ii) the Debenture is not a "designated insurance property" of the holder for purposes of the Tax Act; and (iii) the Debenture does not otherwise constitute "taxable Canadian property" to the holder within the meaning of the Tax Act. Generally, a Debenture will not otherwise constitute taxable Canadian property to a non-resident holder at the time of the disposition or deemed disposition thereof unless (i) the holder, persons with whom the holder does not deal at arm's length (within the meaning of the Tax Act) or the holder together with such persons owned 25% or more of the Units at any time during the 60-month period immediately preceding the disposition, or (ii) the Trust is not a mutual fund trust for the purposes of the Tax Act on the date of disposition. If a Debenture is sold or transferred by a non-resident holder to a purchaser that is resident in Canada at a time when interest has accrued and remains unpaid on the Debenture, the portion of the purchase or transfer price attributable to such accrued interest will be deemed to be interest, and there will be liability on the part of the purchaser to remit withholding tax on such deemed interest (and any other amounts deemed to be interest) under the Tax Act. THE COMPUTATION OF THE AMOUNT OF INTEREST WHICH IS DEEMED TO HAVE BEEN PAID ON A TRANSFER OF DEBENTURES, INCLUDING A CONVERSION, IS COMPLEX, AND IN SOME CIRCUMSTANCES UNCLEAR. NON-RESIDENT SELLERS OR TRANSFERORS OF DEBENTURES SHOULD CONSULT THEIR OWN ADVISORS AS TO WHETHER ANY WITHHOLDING OBLIGATION APPLIES. 48 STATUS OF THE TRUST Based upon representations made by the Manager, in the opinion of Counsel, the Trust presently qualifies as a "mutual fund trust" as defined by the Tax Act, and this summary assumes that the Trust will continue to so qualify. Counsel is advised by the Manager that it is intended that the requirements necessary for the Trust to qualify as a mutual fund trust will continue to be satisfied so that the Trust will continue to qualify as a mutual fund trust at all times throughout its existence. In the event that the Trust were not to so qualify, the income tax considerations would in some respects be materially different from those described herein. TAXATION OF THE TRUST The Trust is required to include in its income for each taxation year all net realized capital gains, dividends, accrued interest and amounts accrued in respect of the Royalty. The Trust may deduct in respect of each taxation year an amount not exceeding 20% of the total issue expenses of the offering and other offerings of its Units or debt obligations (subject to proration for a short taxation year) to the extent that those expenses were not otherwise deductible in a preceding year, and may also deduct reasonable management and administration fees incurred by it in the year. The Trust may also deduct, in computing its income from all sources for a taxation year, an amount not exceeding 10.00% on a declining balance basis of its cumulative Canadian oil and gas property expense ("COGPE") account at the end of that year, prorated for short taxation years. To the extent that the Trust has any income for a taxation year after the inclusions and deductions outlined above, the Trust will be permitted to deduct all amounts of income which are paid or become payable by it to Unitholders in the year. An amount will be considered payable to a Unitholder in a taxation year only if it is paid in the year by the Trust or the Unitholder is entitled in the year to enforce payment of the amount. Counsel is advised that the Trust intends to deduct, in computing its income, the full amount available for deduction in each year to the extent of its taxable income for the year otherwise determined. As a result of such deduction from income, it is expected that the Trust will not be liable for any material amount of tax under the Tax Act; however no assurances can be given in this regard. Under the Trust Indenture, income received by the Trust may be used to finance cash redemptions of Trust Units. Further, it is possible that income received by the Trust will be used to repay the principal amount of any outstanding indebtedness (including the Debentures and the Redemption Notes). Accordingly, such income so utilized will not be payable to holders of the Trust Units by way of cash distributions. In such circumstances, such income may be payable to holders of Trust Units in the form of additional Trust Units ("Reinvested Units"). TAXATION OF UNITHOLDERS RESIDENT IN CANADA Each Unitholder is required to include in computing his income for a particular taxation year the portion of the net income of the Trust that is paid or payable to the Unitholder in that taxation year, whether or not the amount was actually paid to the Unitholder in that year. Income of a Unitholder from the Units will be considered to be income from property and not resource income (or "resource profits") for purposes of the Tax Act. Any loss of the Trust for purposes of the Tax Act cannot be allocated to, or treated as a loss of a Unitholder. Reinvested Units issued to a Unitholder in lieu of a cash distribution will have a cost equal to the fair market value of such units and will be averaged with the adjusted cost base of all other Units held by the Unitholder at that time as capital property in order to determine the adjusted cost base of each Unit. Any amounts paid or payable by the Trust to a Unitholder in excess of the Unitholder's share of the income of the Trust and the non-taxable portion of capital gains made payable to Unitholders in the year will generally not be included in the income of the Unitholder but will reduce the adjusted cost base of such Unitholder's Trust Units. To the extent that the adjusted cost base to a holder of a Trust Unit would otherwise be less than nil, the negative amount will be deemed to be a capital gain of the Unitholder from the disposition of the Trust Unit in the year in which the negative amount arises. The non-taxable portion of capital gains of the Trust that is paid or made payable to the Unitholder in a year will not be included in computing the Unitholder's income for the year and will not reduce the adjusted cost base to the Unitholder of the Trust Units. 49 An actual or deemed disposition (other than in a tax deferred transaction) of Units by a Unitholder, whether on a redemption or otherwise, will give rise to a capital gain (or capital loss) equal to the amount by which the proceeds of disposition (excluding any amount payable by the Trust which represents an amount that must otherwise be included in the Unitholder's income as described above) are greater than (or less than) the aggregate of the adjusted cost base of the Units to the Unitholder plus any reasonable costs associated with the disposition. One-half of any capital gain realized by a Unitholder on a disposition of a Unit will be included in the Unitholder's income under the Tax Act for the year of disposition as a taxable capital gain. One-half of any capital loss realized on a disposition of a Unit may be deducted against taxable capital gains realized by the Unitholder in the year of disposition, in the three preceding taxation years or in any subsequent taxation year, to the extent and under the circumstances described in the Tax Act. Taxable capital gains realized by a Unitholder who is an individual may give rise to alternative minimum tax depending on such Unitholder's circumstances. A Unitholder that throughout the relevant year is a "Canadian-controlled private corporation" as defined in the Tax Act may be liable to pay an additional refundable tax of 6 2/3% on certain investment income, including taxable capital gains. A redemption of Units in consideration for cash, Notes or Redemption Notes, as the case may be, will be a disposition of such Units for proceeds of disposition equal to the amount of such cash or the fair market value of such Notes or Redemption Notes, as the case may be, less any portion thereof that is considered to be a distribution out of the income of the Trust. Redeeming Unitholders will consequently realize a capital gain, or sustain a capital loss, depending upon whether such proceeds exceed, or are exceeded by, the adjusted cost base of the Units so redeemed. The receipt of Notes or Redemption Notes in substitution for Units may result in a change in the income tax characterization of distributions. Holders of Notes or Redemption Notes generally will be required to include in income interest that is received or receivable or that accrues (depending on the status of the Unitholder as an individual, corporation or trust) on the Notes or Redemption Notes. The cost to a Unitholder of any property distributed to a Unitholder by the Trust will be deemed to be equal to the fair market value of such property at the time of distribution. Unitholders should consult with their own tax advisors as to the consequences of receiving Notes or Redemption Notes on a redemption. TAXATION OF UNITHOLDERS NOT RESIDENT IN CANADA Any distribution of income of the Trust to a Unitholder who is not resident or deemed to be resident in Canada will generally be subject to Canadian withholding tax at the rate of 25%, unless such rate is reduced under the provisions of a tax treaty between Canada and the Unitholder's jurisdiction of residence. A Unitholder resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention will be entitled to have the rate of withholding reduced to 15% of the amount of any income distributed. Pursuant to the Proposed Amendments, the Trust will, beginning in 2005, also be obligated to withhold on all capital distributions to non-residents at the rate of 15%. Where a non-resident sustains a capital loss on a disposition of Units such loss may reduce the non-resident's tax liability in respect of capital distributions. A disposition or deemed disposition of a Unit, whether on redemption or otherwise, will not give rise to any capital gains subject to tax under the Tax Act to a holder who is not resident or deemed to be resident in Canada provided that the Units are not "taxable Canadian property" of the holder for the purposes of the Tax Act. Units will not be considered taxable Canadian property to such a holder unless: (a) the holder holds or uses, or is deemed to hold or use the Units in the course of carrying on business in Canada; (b) the Units are "designated insurance property" of the holder for purposes of the Tax Act; (c) at any time during the 60 month period immediately preceding the disposition of the Units the holder or persons with whom the holder did not deal at arm's length or any combination thereof, held 25% or more of the issued Units; or (d) the Trust is not a mutual fund trust for the purposes of the Tax Act on the date of disposition. Interest paid or credited on notes to a non-resident Unitholder who receives Notes or Redemption Notes on a redemption of Units will be subject to Canadian withholding tax at a rate of 25%, unless such rate is reduced under the provisions of an applicable tax treaty. A Unitholder resident in the United States who is entitled to claim the benefit of the Canada-US Tax Convention generally will be entitled to have the rate of withholding reduced to 10% of the amount of such interest. 50 ELIGIBILITY FOR INVESTMENT Provided the Trust qualifies as a mutual fund trust, the Subscription Receipts, the Debentures and the Units issuable pursuant to the Subscription Receipts and on conversion, redemption or maturity of the Debentures will be qualified investments under the Tax Act for trusts governed by registered retirement savings plans, registered retirement income funds, deferred profit sharing plans ("DPSPS") (except, in the case of the Debentures, a DPSP to which the Trust has made a contribution) and registered education savings plans (collectively, the "PLANS") provided that in the case of Subscription Receipts, the Trust deals at arm's length with each person who is an annuitant, a beneficiary, an employee or subscriber under the governing plan of the plan trust for such plans. If the Trust ceases to qualify as a mutual fund trust, Subscription Receipts, the Debentures and the Units issuable pursuant to the Subscription Receipts and on conversion, redemption or maturity of the Debentures will cease to be qualified investments for Plans. Adverse tax consequences may apply to a Plan, or an annuitant thereunder, if the Plan acquires or holds property that is not a qualified investment for the Plan. Where a Plan receives Notes or Redemption Notes as a result of a redemption of Units, such Notes or Redemption Notes may not be qualified investments for the Plan under the Tax Act depending upon the circumstances at the time, and this could give rise to adverse consequences to the Plan or the annuitant thereunder. Accordingly, Plans that own Units should consult their own advisors before deciding to exercise the redemption rights thereunder. Provided the Trust restricts its holdings in foreign property within the limits provided in the Tax Act and provided the Trust qualifies as a mutual fund trust, the Subscription Receipts, the Debentures and the Units issuable pursuant to the Subscription Receipts and on conversion, redemption or maturity of the Debentures will not be foreign property for Plans (other than registered education savings plans), registered pension plans or other persons subject to tax under Part XI of the Tax Act. Registered education savings plans are not subject to tax under Part XI of the Tax Act. See also "Risk Factors - Consequences of Loss of Mutual Fund Trust Status". RISK FACTORS An investment in the securities of Advantage is subject to certain risks. INVESTORS SHOULD CAREFULLY CONSIDER THE RISKS DESCRIBED UNDER "RISK FACTORS", BEGINNING ON PAGE 50 OF THE AIF AS WELL AS THE FOLLOWING RISK FACTORS: POSSIBLE FAILURE TO REALIZE ANTICIPATED BENEFITS OF ACQUISITIONS The Trust is proposing to complete the Acquisition to strengthen its position in the oil and natural gas industry and to create the opportunity to realize certain benefits including, among other things, potential cost savings. Achieving the benefits of these and future acquisitions the Trust may complete depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as the Trust's and AOG's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Trust. The integration of acquired businesses requires the dedication of substantial management effort, time and resources which may divert management's focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the loss of key employees and the disruption of ongoing business, customer and employee relationships that may adversely affect the Trust's ability to achieve the anticipated benefits of these and future acquisitions. POSSIBLE FAILURE TO COMPLETE THE ACQUISITION The Acquisition is subject to normal commercial risk that the Acquisition may not be completed on the terms negotiated or at all. If closing of the Acquisition does not take place by the Termination Time, the Escrow Agent and the Trust will repay to holders of Subscription Receipts, commencing on or before the second Business Day following the Termination Time, an amount equal to the issue price therefor plus a PRO RATA share of the interest earned on the Escrowed Funds and the Debentures will mature on the Initial Maturity Date. 51 OPERATIONAL AND RESERVES RISKS RELATING TO THE ASSETS The risk factors set forth in the Trust's AIF and in this short form prospectus relating to the oil and natural gas business and the operations and Reserves of the Trust apply equally in respect of the Assets that the Trust is acquiring pursuant to the Acquisition. In particular, the Reserves and recovery information contained in the Sproule Anadarko Report in respect of the Assets is only an estimate and the actual production from and ultimate Reserves of those properties may be greater or less than the estimates contained in such report. MARKET FOR SECURITIES There is currently no market through which the Subscription Receipts or the Debentures may be sold and purchasers may not be able to resell Subscription Receipts or Debentures purchased under this short form prospectus. There can be no assurance that an active trading market will develop for the Subscription Receipts or the Debentures after the offering, or if developed, that such a market will be sustained at the price level of the offering. PRIOR RANKING INDEBTEDNESS; ABSENCE OF COVENANT PROTECTION The Debentures will be subordinate to all Senior Indebtedness and to any indebtedness of creditors of the Trust. The Debentures will also be effectively subordinate to claims of creditors of the Trust's subsidiaries except to the extent the Trust is a creditor of such subsidiaries ranking at least PARI PASSU with such other creditors. Other than as described herein, the Indenture will not limit the ability of the Trust to incur additional debt or liabilities (including Senior Indebtedness) or to make distributions. The Indenture does not contain any provision specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving the Trust. However, the Trust Indenture, among other things, restricts the Trust's level of indebtedness, provides operating investment guidelines, mandates the making of distributions and specifies the nature of its business. CHANGES IN ACCOUNTING STANDARDS APPLICABLE TO CONVERTIBLE DEBENTURES For 2005 and future years, the amounts outstanding for the Debentures will be classified as liabilities and the interest cost on the Debentures will be included as interest expense in the determination of net income. CONSEQUENCES OF LOSS OF MUTUAL FUND TRUST STATUS If the Trust no longer qualified as a mutual fund trust or such status was successfully challenged by a relevant tax authority, certain adverse consequences may arise for the Trust and Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows: o The Trust would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties held by the Trust. Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax. o The Trust would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws if it ceased to be a mutual fund trust. o Trust Units held by Unitholders that are not residents of Canada would become taxable Canadian property. These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Trust Units held by them. o The Trust Units would not constitute qualified investments for Plans. If, at the end of any month, one of these Plans hold 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 Plan. An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units. If an RESP holds non-qualified Trust Units, it may have its registration revoked by the Canada Revenue Agency. 52 o The Trust would no longer be exempt from the application of the alternative minimum tax provisions of the Tax Act. In addition, the Trust may take certain measures in the future to the extent the Trust believes them necessary to maintain its status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units. KEY MAN INSURANCE The Trust does not have key man insurance in effect for its senior management. The contributions of these individuals to the immediate future operations of the Trust are important and the loss of such individuals could adversely impact on the Trust's growth and profitability. MATERIAL CONTRACTS The material contracts entered into or to be entered into by the Trust in connection with the offering are as follows: (a) the Subscription Receipt Agreement referred to under "Details of the Offering - Subscription Receipts"; (b) the Indenture referred to under "Details of the Offering - Debentures"; and (c) the Underwriting Agreement referred to under "Plan of Distribution". Copies of each of the foregoing agreements (in draft form prior to closing in the case of the Subscription Receipt Agreement and the Indenture) may be inspected during regular business hours at the offices of the Trust, at 3100, 150 - 6th Avenue S.W., Calgary, Alberta, T2P 3Y7 until the expiry of the 30-day period following the date of the final short form prospectus. LEGAL PROCEEDINGS There are no outstanding legal proceedings material to the Trust to which the Trust is a party or in respect of which any of its properties are subject, nor are there any such proceedings known to be contemplated. AUDITORS, TRANSFER AGENT AND REGISTRAR The auditors of the Trust are KPMG LLP, Chartered Accountants, Suite 1200, 205 - 5th Avenue S.W., Calgary, Alberta T2P 4B9. The transfer agent and registrar for the Units, the Subscription Receipts and Debentures is Computershare Trust Company of Canada at its principal offices in Calgary, Alberta and Toronto, Ontario. STATUTORY AND CONTRACTUAL RIGHTS OF RESCISSION AND STATUTORY RIGHTS OF WITHDRAWAL Securities legislation in certain of the provinces of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two business days after receipt or deemed receipt of a prospectus and any amendment. In several of the provinces, securities legislation further provides a purchaser with remedies for rescission or, in some jurisdictions, damages if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser's province. The purchaser should refer to any applicable provisions of the securities legislation of the province in which the purchaser resides for the particulars of these rights or consult with a legal advisor. In addition, original purchasers of Subscription Receipts will have the benefit of a contractual right of rescission exercisable following the issuance of Units to such purchasers. See "Details of the Offering - Subscription Receipts". 53 AUDITORS' CONSENT The Board of Directors of Advantage Oil & Gas Ltd. We have read the short form prospectus of Advantage Energy Income Fund (the "TRUST") dated September 3, 2004 relating to the sale and issue of subscription receipts and extendible convertible unsecured subordinated debentures of the Trust. We have complied with Canadian Generally Accepted Standards for an auditor's involvement with offering documents. We consent to the use, through incorporation by reference in the above mentioned short form prospectus, of our report to the Unitholders of the Trust on the consolidated balance sheets of the Trust as at December 31, 2003 and 2002 and the consolidated statements of income and accumulated income and cash flows for each of the years then ended. Our report is dated April 7, 2004. (signed) KPMG LLP Chartered Accountants Calgary, Canada September 3, 2004 AUDITORS' CONSENT The Board of Directors of Advantage Oil & Gas Ltd. We have read the short form prospectus of Advantage Energy Income Fund (the "TRUST") dated September 3, 2004 relating to the sale and issue of subscription receipts and extendible convertible unsecured subordinated debentures of the Trust. We have complied with Canadian Generally Accepted Standards for an auditor's involvement with offering documents. We consent to the use in the above-mentioned short form prospectus of our report to the directors of Advantage Oil & Gas Ltd. on the schedule of revenues and expenses for the Acquired Assets for the year ended December 31, 2003. Our report is dated August 24, 2004. (signed) KPMG LLP Chartered Accountants Calgary, Canada September 3, 2004 AUDITORS' CONSENT We have read the short form prospectus of Advantage Energy Income Fund (the "TRUST") dated September 3, 2004 relating to the qualification for distribution of 3,500,000 subscription receipts each representing the right to receive one trust unit of the Trust, $75,000,000 principal amount of 7.50% extendible convertible unsecured subordinated debentures of the Trust and $50,000,000 principal amount of 7.75% extendible convertible unsecured subordinated debentures of the Trust. We have complied with Canadian generally accepted standards for an auditor's involvement with offering documents. We consent to the use through incorporation by reference in the above-mentioned short form prospectus of our report to the directors of MarkWest Resources Canada Corp. ("MARKWEST") on the balance sheet of MarkWest as at December 31, 2002 and the statements of earnings and retained earnings (deficit) and cash flows for the year then ended. Our report is dated November 12, 2003. (signed) PRICEWATERHOUSECOOPERS LLP Chartered Accountants Calgary, Canada September 3, 2004 A-1 SCHEDULE "A" UNAUDITED PROFORMA CONSOLIDATED FINANCIAL STATEMENTS A-2 The Board of Directors of Advantage Oil & Gas Ltd. We have read the accompanying unaudited pro forma consolidated balance sheet of Advantage Energy Income Fund (the "Fund") as at June 30, 2004 and unaudited pro forma consolidated statement of operations for the six months then ended and for the year ended December 31, 2003, and have performed the following procedures: 1. Compared the figures in the columns captioned "Advantage" to the unaudited consolidated financial statements of the Fund as at June 30, 2004 and for the six months then ended, and the audited consolidated financial statements of the Fund for the year ended December 31, 2003, as restated and described in the unaudited consolidated financial statements as at June 30, 2004 and for the six months then ended, respectively, and found them to be in agreement. 2. Compared the figures in the columns captioned "Acquired Assets " to the unaudited schedule of revenues and expenses of the Acquired Assets for the six months ended June 30, 2004 and the audited schedule of revenues and expenses of the Acquired Assets for the year ended December 31, 2003. 3. Compared the figures in the columns captioned "MarkWest" to the unaudited financial statements of MarkWest Resources Canada Corp. as at September 30, 2003 and for the nine months then ended and to the unaudited accounting records of MarkWest Resources Canada Corp. for the period from October 1, 2003 to December 2, 2003 and found them to be in agreement. 4. Made enquiries of certain officials of the Company who have responsibility for financial and accounting matters about: (a) The basis for determination of the pro forma adjustments; and (b) Whether the pro forma consolidated financial statements comply as to form in all material respects with the securities regulations of various provinces. The officials: (a) described to us the basis for determination of the pro forma adjustments, and (b) stated that the pro forma consolidated financial statements comply as to form in all material respects with the securities regulations of various provinces. 5. Read the notes to the pro forma consolidated financial statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments. 6. Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the other columns as at June 30, 2004 and for the six months then ended, and for the year ended December 31, 2003, and found the amounts in the column captioned "Pro Forma Consolidated" to be arithmetically correct. A pro forma financial statement is based on management assumptions and adjustments, which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management's assumptions, the pro forma adjustments, and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma consolidated financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements. (signed) KPMG LLP Chartered Accountants Calgary, Canada September 3, 2004 A-3 ADVANTAGE ENERGY INCOME FUND PROFORMA CONSOLIDATED BALANCE SHEET (unaudited) (thousands of dollars)
Advantage Pro Forma Pro Forma June 30, 2004 Adjustments Consolidated ------------- ----------- ------------- ------------ ASSETS Current assets Accounts receivable $ 35,988 $ - $ 35,988 Property and equipment 532,101 183,198 (note 2a) 715,299 Goodwill 27,773 - 27,773 ------------- ------------ -------------- $ 595,862 $ 183,198 $ 779,060 ============= ============ ============== LIABILITIES Current liabilities Accounts payable and accrued liabilities $ 41,248 $ - $ 41,248 Cash distributions payable to Unitholders 9,189 - 9,189 Hedging liability 10,224 - 10,224 Bank indebtedness 161,707 (5,910) (note 2a) 155,797 ------------- ------------ -------------- 222,368 (5,910) 216,458 Capital lease obligation 1,885 - 1,885 Asset retirement obligations 14,477 6,598 (note 2a) 21,075 Future income taxes 68,457 - 68,457 ------------- ------------ -------------- 307,187 688 307,875 ------------- ------------ -------------- UNITHOLDERS' EQUITY Unitholders' capital 339,279 62,510 (note 2a) 401,789 Convertible debentures 66,396 125,000 (note 2a) 191,396 Contributed surplus 1,036 - 1,036 Accumulated income 88,044 (5,000) (note 2a) 83,044 Accumulated cash distributions (206,080) - (206,080) ------------- ------------ -------------- 288,675 182,510 471,185 ------------- ------------ -------------- $ 595,862 $ 183,198 $ 779,060 ============= ============ ==============
SEE ACCOMPANYING NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS A-4 ADVANTAGE ENERGY INCOME FUND PROFORMA CONSOLIDATED STATEMENT OF OPERATIONS (thousands of dollars) (unaudited)
Acquired Advantage Assets Six Months Six Months Ended Ended Pro Forma Pro Forma June 30, 2004 June 30, 2004 Adjustments Consolidated ------------- ------------- ----------- ----------- ------------ REVENUE Petroleum and natural gas sales $ 108,017 $ 48,640 $ - $ 156,657 Royalties, net of Alberta Royality Credit (21,130) (10,997) (32,127) ----------- ----------- ----------- ---------- 86,887 37,643 - 124,530 ----------- ----------- ----------- ---------- EXPENSES Operating 16,538 13,130 - 29,668 General and administrative 1,634 - - 1,634 Stock-based compensation 1,036 - - 1,036 Interest 2,677 - (112) (note 2c) 2,565 Management fees 1,055 - 368 (note 2d) 1,423 Non-cash performance incentive 2,900 - - 2,900 Unrealized hedging loss 10,224 - - 10,224 Depletion, depreciation and accretion 41,001 - 19,417 (note 2e) 60,418 ----------- ----------- ----------- ---------- 77,065 13,130 19,673 109,868 ----------- ----------- ----------- ---------- Income before taxes 9,822 24,513 (19,673) 14,662 TAXES Future income tax recovery (9,542) - - (9,542) Income and capital taxes 630 - 201 (note 2f) 831 ----------- ----------- ----------- ---------- (8,912) - 201 (8,711) ----------- ----------- ----------- ---------- NET INCOME $ 18,734 $ 24,513 $ (19,874) $ 23,373 =========== =========== =========== ========== Net income per trust unit (note 2g) Basic $ 0.36 Diluted $ 0.36
SEE ACCOMPANYING NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS A-5 ADVANTAGE ENERGY INCOME FUND PROFORMA CONSOLIDATED STATEMENT OF OPERATIONS (thousands of dollars) (unaudited)
MarkWest MarkWest Acquired Advantage Nine Months October 1 Assets Year ended Ended to Year Ended MarkWest Assets December 31 September 30, December 2, December 31, ProForma ProForma 2003 2003 2003 2003 Adjustments Adjustment Consolidated (restated) REVENUE Petroleum and natural $ 166,075 $ 37,695 $ 8,884 $ 104,809 $ - $ - $ 317,463 gas sales Royalties, net of (28,491) (11,263) (2,144) (24,751) - - (66,649) Alberta Royalty Credit 137,584 26,432 6,740 80,058 - - 250,814 EXPENSES Operating 25,618 7,641 1,884 25,310 - - 60,453 General and 3,216 1,787 784 - - - 5,787 administrative Interest 6,378 1,822 - - (3,592) (284) (note 2c) 4,324 Management fees 1,679 - - - 355 821 (note 2d) 2,855 Non-cash performance 19,592 - - - - - 19,592 incentive Depletion, depreciation 54,027 15,295 5,144 (1,448) 40,325 (note 2e) 113,343 and accretion Other - 151 - - - - 151 110,510 26,696 7,812 25,310 (4,685) 40,862 206,505 Income (loss) before taxes 27,074 (264) (1,072) 54,748 4,685 (40,862) 44,309 TAXES Future income tax recovery (18,203) (7,143) - - - - (25,346) Income and capital taxes 1,253 431 - - - 411 (note 2f) 2,095 (16,950) (6,712) - - - 411 (23,251) NET INCOME $ 44,024 $ 6,448 $ (1,072) $ 54,748 $ 4,685 $ (41,273) $ 67,560 Net income per trust unit (note 2g) Basic 1.26 Diluted 1.26
SEE ACCOMPANYING NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS A-6 ADVANTAGE ENERGY INCOME FUND NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS SIX MONTHS ENDED JUNE 30, 2004 AND YEAR ENDED DECEMBER 31, 2003 (UNAUDITED) 1. BASIS OF PRESENTATION On August 24, 2004 Advantage Oil & Gas Ltd. entered into an agreement to acquire properties from Anadarko Canada Corporation ("Acquired Assets"). The acquisition is expected to close on September 30, 2004. On December 2, 2003, Advantage Oil & Gas Ltd. acquired all of the issued and outstanding shares of MarkWest Resources Canada Corp. ("MarkWest") for cash consideration of $97 million. The accompanying unaudited pro forma consolidated financial statements have been prepared by management of Advantage Energy Income Fund ("Advantage") in accordance with Canadian generally accepted accounting principles. In the opinion of management the pro forma consolidated financial statements include all material adjustments necessary for fair presentation in accordance with Canadian generally accepted accounting principles. These pro forma consolidated financial statements may not be indicative either of the results that actually would have occurred if the events reflected herein had been in effect on the dates indicated or of the results which may be obtained in the future. The unaudited pro forma consolidated balance sheet of Advantage has been prepared based on the unaudited consolidated balance sheet of Advantage as at June 30, 2004. The unaudited pro forma consolidated statement of operations for the six-month period ended June 30, 2004 has been prepared from: o The unaudited consolidated statement of operations of Advantage for the six-month period ended June 30, 2004; and o The unaudited schedule of revenues and expenses of the Acquired Assets for the six-month period ended June 30, 2004. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2003 has been prepared from: o The audited consolidated statement of operations of Advantage for the year ended December 31, 2003; o The audited schedule of revenues and expenses of the Acquired Assets for the year ended December 31, 2003; and o The unaudited statement of earnings of MarkWest for the nine-month period ended September 30, 2003; o The unaudited accounting information of MarkWest for the period from October 1, 2003 to December 1, 2003. Advantage's financial statements for the year ended December 31, 2003 have been restated to reflect a change in accounting policy with respect to asset retirement obligations. This change in accounting policy is more fully described in the unaudited consolidated financial statements of Advantage as at and for the six-month period ended June 30, 2004. The restated amounts are reflected in the pro forma consolidated financial statements. A-7 2. PRO FORMA TRANSACTIONS AND ASSUMPTIONS The pro forma consolidated balance sheet gives effect to the following transactions and assumptions as if they had occurred on June 30, 2004, while the pro forma consolidated statements of operations for the six month period ended June 30, 2004 and the year ended December 31, 2003 gives effect to the following transactions and assumptions as if they had occurred on January 1, 2004 and January 1, 2003 respectively: (a) The acquisition of the Acquired Assets by Advantage for cash consideration of $186,000,000 before purchase price adjustments. The acquisition is being accounted for under the purchase method. The acquisition is to be financed through the issuance of $50,000,000 of 7.75% and $75,000,000 of 7.50% extendible convertible unsecured subordinated debentures and the issuance of 3.5 million subscription receipts at a price of $18.80 per unit. Associated underwriters' fees related to convertible debentures of $5,000,000 are included in accumulated income. Excess proceeds over the purchase price of the Acquired Assets will be used to reduce bank debt. (b) The operations from the MarkWest acquisition described in note 1 have been included in the statement of operations of Advantage beginning December 2, 2003. As a result, the pro forma statement of operations for the year ended December 31, 2003 has been adjusted to reflect the operations of MarkWest for the period from January 1 to December 1, 2003. (c) Interest expense has been calculated by applying applicable bank interest rates for the period to the reduction in bank debt due to the proceeds from the financing exceeding the expected purchase price. (d) Management fees have been adjusted to reflect the additional expense associated with the increase in operating income. (e) Depletion and depreciation has been determined using the full cost method of accounting based on combined proved reserves, future development costs, production volumes and the costs of acquiring the Acquired Assets and MarkWest. Accretion expense has been adjusted to reflect the additional asset retirement obligation associated with the Acquired Assets and MarkWest. (f) Current taxes have been adjusted to reflect changes in large corporation tax. It is assumed that any additional future income tax effect resulting from the pro forma adjustments will be offset by additional deductions to the Trust. (g) Pro forma basic per unit amounts are based on the weighted average number of Advantage units outstanding for the period plus the additional units issued pursuant to the prospectus. Pro forma diluted per unit amounts are based on the weighted average number of diluted Advantage units outstanding for the period plus the additional units that would be issued on the conversion of the convertible debentures referenced under 2 (a). B-1 SCHEDULE "B" SCHEDULE OF REVENUES AND EXPENSES B-2 Schedule of Revenues and Expenses of the ACQUIRED ASSETS For the year ended December 31, 2003 B-3 AUDITORS' REPORT To the Board of Directors of Advantage Oil and Gas Ltd. At the request of Advantage Energy Income Fund we have audited the schedule of revenues and expenses of the Acquired Assets for the year ended December 31, 2003. This financial information is the responsibility of management. Our responsibility is to express an opinion on this financial information based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial information is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial information. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial information. In our opinion, this financial information presents fairly, in all material respects, the revenues and expenses of the Acquired Assets for the year ended December 31, 2003. (signed) KPMG LLP Chartered Accountants Calgary, Canada August 24, 2004 B-4
ADVANTAGE ENERGY INCOME FUND Schedule of Revenues and Expenses of the Acquired Assets ------------------------------------------------------------------------------------------------------------------- Six-month period ended June 30, Year ended ---------------------------------- December 31, 2004 2003 2003 ------------------------------------------------------------------------------------------------------------------- (unaudited) Revenue $ 48,639,651 $ 57,561,573 $ 104,809,129 Royalties (10,996,552) (13,768,361) (24,751,107) ------------------------------------------------------------------------------------------------------------------- 37,643,099 43,793,212 80,058,022 Operating Costs (13,129,975) (12,139,884) (25,309,551) ------------------------------------------------------------------------------------------------------------------- Operating Income $ 24,513,124 $ 31,653,328 $ 54,748,471 -------------------------------------------------------------------------------------------------------------------
See accompanying notes to schedule of revenues and expenses. B-5 ADVANTAGE ENERGY INCOME FUND Notes to Schedule of Revenues and Expenses of the Acquired Assets Year ended December 31, 2003 (Information for the six months ended June 30, 2004 is unaudited) -------------------------------------------------------------------------------- 1. BASIS OF PRESENTATION: Pursuant to an agreement dated August 24, 2004, Advantage Energy Income Fund ("Advantage"), through its wholly-owned subsidiary, Advantage Oil & Gas Ltd., acquired interests in certain petroleum and natural gas properties ("Acquired Assets") from Anadarko Canada Corporation ("Anadarko"). The schedule of revenue and expenses for selected properties includes the operations of the acquired properties of Anadarko. The schedule of revenue and expenses for the acquired properties includes only revenues, royalties and operating costs applicable to the working interest of Anadarko for the acquired properties. The schedule of revenue and expenses for selected properties does not include any provision for the depletion and depreciation, site restoration, future capital costs, impairment of unevaluated properties, general and administrative costs and income taxes for the selected properties as these amounts are based on the consolidated operations of Anadarko of which the selected properties form only a part of. 2. SIGNIFICANT ACCOUNTING POLICIES: (a) Revenue: Revenue from the sale of oil, natural gas liquids and natural gas is recognized at the time the product is produced and sold. Pricing used in the schedule of revenues and expenses is the current market price net of transportation costs. (b) Royalties: Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance with the applicable regulations or the terms of individual royalty agreements. (c) Operating costs: Operating costs include amounts incurred to bring the oil and natural gas to the surface, gather, process, treat and store the product in the field. C-1 SCHEDULE "C" UNAUDITED FINANCIAL STATEMENTS OF MARKWEST RESOURCES CANADA CORP. FOR THE NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2003 C-2 Financial Statements of MARKWEST RESOURCES CANADA CORP. Nine months ended September 30, 2003 C-3
MARKWEST RESOURCES CANADA CORP. Balance Sheet ------------------------------------------------------------------------------------------------------------------- September 30, December 31, 2003 2002 ------------------------------------------------------------------------------------------------------------------- (unaudited) Assets Current assets: Cash $ - $ 3,345,099 Accounts receivable 7,581,616 5,238,507 Prepaids and other current assets 456,463 574,714 ------------------------------------------------------------------------------------------------------------------- 8,038,079 9,158,320 Deferred financing costs 168,195 319,571 Property, plant and equipment (note 3) 156,396,341 142,334,142 ------------------------------------------------------------------------------------------------------------------- $ 164,602,615 $ 151,812,033 ------------------------------------------------------------------------------------------------------------------- Liabilities and Shareholders' Equity Current liabilities: Cash, less outstanding cheques $ 2,969,853 $ - Accounts payable and accrued liabilities 14,651,559 9,948,858 Current portion of capital lease obligations (note 5) 312,499 - Advances from parent (note 6) 51,210,654 16,265,710 Current portion of long-term debt (note 4) 21,000,000 - ------------------------------------------------------------------------------------------------------------------- 90,144,565 26,214,568 Long-term debt (note 4) - 53,000,000 Capital lease obligations (note 5) 2,129,543 - Provision for future site restoration (note 7) 1,585,203 1,159,212 Future income tax 38,217,486 45,360,728 ------------------------------------------------------------------------------------------------------------------- 41,932,232 125,734,508 Shareholders' equity: Share capital (note 8) 28,542,263 28,542,263 Retained Earnings (deficit) 3,983,555 (2,464,738) ------------------------------------------------------------------------------------------------------------------- 32,525,818 26,077,525 Commitments (note 9) Subsequent events (note 11) ------------------------------------------------------------------------------------------------------------------- $ 164,602,615 $ 151,812,033 -------------------------------------------------------------------------------------------------------------------
See accompanying notes to financial statements. C-4
MARKWEST RESOURCES CANADA CORP. Statement of Earnings and Retained Earnings (deficit) ------------------------------------------------------------------------------------------------------------------- Nine months ended Year ended September 30, December 31, 2003 2002 ------------------------------------------------------------------------------------------------------------------- (unaudited) Revenue: Petroleum and natural gas revenue $ 37,649,367 $ 41,747,575 Royalties, net of Alberta Royalty Tax Credit (11,262,603) (10,026,021) ------------------------------------------------------------------------------------------------------------------- 26,386,764 31,721,554 Other income 46,237 33,967 ------------------------------------------------------------------------------------------------------------------- 26,433,001 31,755,521 Expenses: Production 7,641,336 7,244,966 General and administrative 1,787,330 2,629,180 Depletion, depreciation, amortization and site restoration 15,295,368 21,248,048 Interest expense 1,821,428 1,596,929 Other 151,375 1,079,330 ------------------------------------------------------------------------------------------------------------------- 26,696,837 33,798,453 ------------------------------------------------------------------------------------------------------------------- Loss before income taxes (263,836) (2,042,932) Income taxes: Current tax expense (recovery) 431,113 (160,291) Future tax recovery (7,143,242) (2,445,256) ------------------------------------------------------------------------------------------------------------------- (6,712,129) (2,605,547) ------------------------------------------------------------------------------------------------------------------- Net earnings for the period 6,448,293 562,615 Deficit, beginning of period (2,464,738) (3,027,353) ------------------------------------------------------------------------------------------------------------------- Retained earnings (deficit), end of period $ 3,983,555 $ (2,464,738) -------------------------------------------------------------------------------------------------------------------
See accompanying notes to financial statements. C-5
MARKWEST RESOURCES CANADA CORP. Statement of Cash Flows ------------------------------------------------------------------------------------------------------------------- Nine months ended Year ended September 30, December 31, 2003 2002 ------------------------------------------------------------------------------------------------------------------- (unaudited) Cash provided by (used in): Net earnings for the period $ 6,448,293 $ 562,615 Items not affecting cash: Depreciation, depletion and amortization and site restoration 15,295,368 21,248,048 Future income taxes (7,143,242) (2,445,256) Amortization of deferred financing costs 151,376 1,079,330 ------------------------------------------------------------------------------------------------------------------- 14,751,795 20,444,737 Net change in non-cash working capital items 2,267,667 2,265,829 ------------------------------------------------------------------------------------------------------------------- 17,019,462 22,710,566 Investing activities: Property, plant and equipment additions (28,776,848) (25,490,063) Proceeds on disposition of property, plant and equipment 2,579,439 - Abandonment expenditures (103,183) (5,151) Change in capital accrual 210,176 (1,637,235) ------------------------------------------------------------------------------------------------------------------- (26,090,416) (27,132,449) Financing activities: Repayment of long-term debt (32,000,000) - Advances from parent 34,944,944 5,646,530 Decrease in capital lease obligations (188,942) - ------------------------------------------------------------------------------------------------------------------- 2,756,002 5,646,530 ------------------------------------------------------------------------------------------------------------------- (Decrease) increase in cash (6,314,952) 1,224,647 Cash, beginning of period 3,345,099 2,120,452 ------------------------------------------------------------------------------------------------------------------- Cash, end of period $ (2,969,853) $ 3,345,099 ------------------------------------------------------------------------------------------------------------------- Supplementary information: ------------------------------------------------------------------------------------------------------------------- Interest paid on long-term debt $ 1,726,896 $ 2,692,095 Income taxes paid (received) (199,369) (500,783) Non-cash items: Assets acquired under capital lease 2,630,984 - -------------------------------------------------------------------------------------------------------------------
See accompanying notes to financial statements. C-6 MARKWEST RESOURCES CANADA CORP. Notes to Financial Statements Nine months ended September 30, 2003 -------------------------------------------------------------------------------- NATURE OF OPERATIONS: MarkWest Resources Canada Corp. (the "Company") explores for and produces oil and natural gas and is a wholly owned subsidiary of MarkWest Hydrocarbons, Inc. 1. SIGNIFICANT ACCOUNTING POLICIES: (a) Cash: Cash consists of the balance with the bank, cash on hand and short-term investments with a maturity of three months or less when purchased. (b) Property, plant and equipment: The Company follows the full cost method of accounting for oil and gas operations, whereby all costs of exploring for and developing oil and gas properties and related reserves are capitalized. Such costs include land acquisition costs, cost of drilling both productive and non-productive wells, and geological and geophysical expenses and related overhead. Proceeds of disposition are applied against the cost pools with no gain or loss recognized expect where the disposition results in a significant change in the rate of depletion. The carrying value is limited to the recoverable amount as determined by estimating the future net revenues from proven properties (based on period end prices and costs) and the value of unproven properties (at the lower of cost and net realizable value) less estimated future site restoration costs, general and administrative expenses and financing costs. Capitalize costs, excluding costs relating to unproven properties, are depleted using the unit-of-production method based on estimated proven reserves of oil and gas before royalties as determined by independent petroleum engineers. For purposes of the depletion calculation, oil and natural gas reserves and production are converted to a common unit-of-measure. Other assets are depreciated on a straight-line basis over the estimated service lives of the assets. Assets under capital lease are recorded at the present value of the lease payments at the inception of the lease. (c) Provision for future site restoration: The Company estimates its future site restoration and abandonment costs for its oil and gas properties. The costs represent management's best estimate of the future restoration and abandonment costs based upon current legislation and industry practices. The total estimated costs are being provided for on a unit-of-production basis. The annual provision is included in amortization expense and actual site restoration costs are charged to the liability account as incurred. C-7 MARKWEST RESOURCES CANADA CORP. Notes to Financial Statements Nine months ended September 30, 2003 -------------------------------------------------------------------------------- 1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED): (d) Joint ventures: Certain of the Company's activities are conducted jointly with other parties. These financial statements reflect the Company's proportionate interest in such activities. (e) Financial instruments: The Company's financial instruments are comprised of accounts receivable, accounts payable and accrued liabilities, advances from parent, long term debt and commodity instruments (note 10). The fair value of the financial instruments approximates their carrying amount. A significant portion of the Company's accounts receivable is from oil and gas companies. Although collection of these receivables could be influenced by economic factors affecting this industry, the risk of significant loss is considered remote. (f) Income taxes: The Company follows the liability method of accounting for income taxes. Under this method, the Company records future income taxes for the affect of any differences between the accounting and the income tax basis of an asset or liability using income tax rates substantially enacted on the balance sheet date. The effect of a change in income tax rates on the future income tax assets and liabilities is recognized in income in the period of the change. (g) Measurement uncertainty: The amount recorded for depletion and depreciation of capital assets and the provision for future site restoration costs are based on estimates. The ceiling test calculation is based on estimates of proven reserves, production rates, oil and gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements from change in such estimates in future periods could be significant.
3. PROPERTY, PLANT AND EQUIPMENT: -------------------------------------------------------------------------------------------------------------- Accumulated Net book September 30, 2003 Cost depreciation value -------------------------------------------------------------------------------------------------------------- Petroleum and natural gas properties and equipment $ 197,741,457 $ 44,074,741 $ 153,666,716 Furniture and equipment 370,806 206,392 164,414 Assets under capital lease 2,630,984 65,773 2,565,211 -------------------------------------------------------------------------------------------------------------- $ 200,743,247 $ 44,346,906 $ 156,396,341 --------------------------------------------------------------------------------------------------------------
C-8 MARKWEST RESOURCES CANADA CORP. Notes to Financial Statements Nine months ended September 30, 2003 --------------------------------------------------------------------------------
3. PROPERTY, PLANT AND EQUIPMENT: ------------------------------------------------------------------------------------------------------------------- Accumulated Net book Cost depreciation value ------------------------------------------------------------------------------------------------------------------- Petroleum and natural gas properties and equipment $ 171,592,526 $ 29,430,588 $ 142,161,938 Furniture and equipment 322,328 150,124 172,204 ------------------------------------------------------------------------------------------------------------------- $ 171,914,854 $ 29,580,712 $ 142,334,142 -------------------------------------------------------------------------------------------------------------------
Costs for unproven properties of $41,427,431 at September 30, 2003 and $48,420,924 at December 31, 2002 have been excluded from the depletion calculation. During the nine month period ended September 30, 2003 and the year ended December 31, 2002, the Company capitalized no overhead costs related to exploration and development activities and capitalized $1,409,182 and $2,251,374 of interest expense respectively. Month-end prices of $33.51 (December 31, 2002 - $33.49/bbl) for oil and $5.69/mcf (December 31, 2002 - $5.66/mcf) for gas resulted in no ceiling test deficiency at September 30, 2003 or December 31, 2002. 4. LONG-TERM DEBT: On May, 24, 2002, the Company amended its credit agreement ("Canadian Credit Facility") with various financial institutions for an amount of US$35,000,000. This facility is a component of the overall debt facility of the parent company, MarkWest Hydrocarbons, Inc. ("Parent") of Denver, Colorado. The overall amount of the Parent's facility ("Credit Facility") is US$60,000,000. Available borrowings under the Credit Facility are determined by a borrowing base that is determined by the value of the proved reserves of oil and as owned by the Parent (directly or indirectly through subsidiaries, including MarkWest Resources Canada Corp.), and also on the working capital of the Parent, the level of which is determined by NGL product accounts receivable and inventory levels. The borrowing base on proved reserves is calculated semi-annually, while borrowing base on working capital is calculated monthly. Actual borrowing limits for the Credit Facility may be less than US$60,000,000, depending on proved reserves, working capital levels, and financial covenants. The Company had outstanding borrowings of C$21,000,000, or approximately US$15,551,000, at September 30, 2003 and C$53,000,000, or approximately US$33,758,000, at December 31, 2002 of the US$35,000,000 available. MARKWEST RESOURCES CANADA CORP. Notes to Financial Statements Nine months ended September 30, 2003 -------------------------------------------------------------------------------- 4. LONG-TERM DEBT (CONTINUED): The Canadian Credit Facility permits MarkWest Resources Canada Corp. to borrow money at a rate equal to the London Interbank Offered Rate ("LIBOR") plus an applicable margin of between 1.75% and 2.75% based on a certain leverage ratio, which is determined as the ratio of total funded debt to EBITDA. Funds can also be borrowed at the Canadian Prime Rate plus an applicable margin of between 0.375% and 1.375%, based on the leverage ratio. There is a fee on the unused portion of the Canadian Credit Facility of between 0.25% and 0.50% based on the leverage ratio. The weighted average interest rate was 5.64% for the period ended September 30, 2003 and 5.02% for the year ended December 31, 2002. The Credit Facility is a revolving facility, with a maturity and expiry date of August 9, 2004. The entire outstanding principal balance is due in full on this date. The Credit Facility is collateralized by a first lien on substantially all the Company's assets. 5. CAPITAL LEASE OBLIGATIONS: Future minimum annual lease payments at September 30, 2003 (December 31, 2002 - $nil) consists of the following: --------------------------------------------------------------------------- September 30, 2003 --------------------------------------------------------------------------- 2004 $ 443,220 2005 443,220 2006 443,220 2007 and thereafter 1,474,395 --------------------------------------------------------------------------- 2,804,055 Less amounts representing interest at 5.5% 362,013 --------------------------------------------------------------------------- 2,442,042 Current portion 312,499 --------------------------------------------------------------------------- $ 2,129,543 --------------------------------------------------------------------------- Interest of $69,603 relating to capital lease obligations is included in interest expense for the period ended September 30, 2003. 6. ADVANCES FROM PARENT: The advances from parent bear interest at 7% per annum, are due on demand and are unsecured. C-10 MARKWEST RESOURCES CANADA CORP. Notes to Financial Statements Nine months ended September 30, 2003 -------------------------------------------------------------------------------- 7. PROVISION FOR FUTURE SITE RESTORATION: -------------------------------------------------------------------------- September 30, December 31, 2003 2002 -------------------------------------------------------------------------- Balance, beginning of period $ 1,159,212 $ 222,958 Current period provisions 529,174 941,405 Current period expenditures (103,183) (5,151) -------------------------------------------------------------------------- $ 1,585,203 $ 1,159,212 -------------------------------------------------------------------------- The provision for future site restoration costs is recorded in the statement of income as component of depletion, depreciation and amortization expense and on the balance sheet as a long-term liability. The total estimated liability is $5,000,000 at September 30, 2003 (December 31, 2002 - $3,960,000).
8. SHARE CAPITAL: (a) Authorized: Unlimited number of common shares without nominal or par value (b) Issued: -------------------------------------------------------------------------------------------------------- Number of As at September 30, 2003 and December 31, 2002 shares Amount -------------------------------------------------------------------------------------------------------- Class A common shares 26,933,363 $ 28,542,263 ---------------------------------------------------------------------------------------------------------
9. COMMITMENTS: The Company has committed to certain payments for office space over the next four years as follows: ------------------------------------------------------------------------- September 30, 2003 ------------------------------------------------------------------------- 2004 $ 188,352 2005 188,352 2006 188,352 2007 125,568 ------------------------------------------------------------------------- C-11 MARKWEST RESOURCES CANADA CORP. Notes to Financial Statements Nine months ended September 30, 2003 -------------------------------------------------------------------------------- 10. COMMODITY INSTRUMENTS: Derivative commodity instruments may be used from time to time by the Company to manage its exposure to price risks relating to natural gas prices. The Company's policy is to not utilize derivative commodity instruments for trading or speculative purposes. Realized gains and losses on derivative instruments used as hedges are recognized in income in the period that the hedge is settled. The Company had the following natural gas hedge agreements outstanding at September 30, 2003 and December 31, 2002:
----------------------------------------------------------------------------------------------------------- Volume Price Type (gj/day) ($/gj) Term ----------------------------------------------------------------------------------------------------------- Fixed price 2,462 4.62 January 1 2003 to December 31, 2003 Fixed price 2,462 4.82 January 1, 2003 to December 31, 2003 Fixed price 1,758 4.65 January 1, 2004 to December 31, 2004 Fixed price 1,758 4.87 January 1, 2004 to December 31, 2004 Costless collar 2,462 4.09 - 5.24 January 1, 2003 to December 31, 2003 Costless collar 1,758 4.10 - 5.25 January 1, 2004 to December 31, 2004 Basis swap 6,330 Nymex/AECO April 1, 2003 to October 31, 2003 Basis swap 5,275 Nymex/AECO April 1, 2003 to October 31, 2003 -----------------------------------------------------------------------------------------------------------
The unrealized loss on these contracts was $3,271,534 as at September 30, 2003 and $4,117,199 as at December 31, 2002. Subsequent to September 30, 2003, the Company entered into one natural gas hedge for the period November 1, 2003 to March 31, 2004 totalling 2,109 gj/day with a price based on Nymex/AECO. 11. SUBSEQUENT EVENTS: Effective October 1, 2003, all of the shares of the Company were purchased by Advantage Energy Income Fund for total consideration of $102.5 million. D-1 CERTIFICATE OF THE TRUST Dated: September 3, 2004 This short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this short form prospectus as required by the securities legislation of each of the Provinces of Canada. For the purpose of the Province of Quebec, this simplified prospectus, as supplemented by the permanent information record, contains no misrepresentation that is likely to affect the value or the market price of the securities to be distributed.
ADVANTAGE ENERGY INCOME FUND BY: ADVANTAGE OIL & GAS LTD. (signed) Kelly I. Drader (signed) Peter A. Hanrahan President and Chief Executive Officer Vice President, Finance and Chief Financial Officer ON BEHALF OF THE BOARD OF DIRECTORS (signed) Ronald A. McIntosh (signed) Rodger A. Tourigny Director Director
D-2 CERTIFICATE OF THE UNDERWRITERS Dated: September 3, 2004 To the best of our knowledge, information and belief, this short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this short form prospectus as required by the securities legislation of each of the Provinces of Canada. For the purpose of the Province of Quebec, to our knowledge, this simplified prospectus, as supplemented by the permanent information record, contains no misrepresentation that is likely to affect the value or the market price of the securities to be distributed.
SCOTIA CAPITAL INC. By: (signed) Steven Kroeker BMO NESBITT BURNS INC. NATIONAL BANK FINANCIAL INC. By: (signed) Jason J. Zabinsky By: (signed) David M. Vetters RBC DOMINION SECURITIES INC. By: (signed) Craig E. Kelly CIBC WORLD MARKETS INC. By: (signed) Arthur N. Korpach FIRSTENERGY CAPITAL CORP. RAYMOND JAMES LTD. By: (signed) Nicholas J. Johnson By: (signed) Edward J. Bereznicki