Exhibit 99.1

ANNUAL INFORMATION FORM

YEAR ENDED DECEMBER 31, 2008

March 18, 2009

TABLE OF CONTENTS

 Page

GLOSSARY OF TERMS 1

ABBREVIATIONS 4

CONVERSION 4

ADVANTAGE ENERGY INCOME FUND 7

GENERAL DEVELOPMENT OF THE BUSINESS 8

DESCRIPTION OF OUR BUSINESS AND OPERATIONS 12

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION 13

ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND 36

ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD. 43

MARKET FOR SECURITIES 52

ESCROWED SECURITIES 55

LEGAL PROCEEDINGS 56

REGULATORY ACTIONS 56

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS 56

MATERIAL CONTRACTS 56

INTEREST OF EXPERTS 56

AUDITORS, TRANSFER AGENT AND REGISTRAR 56

AUDIT COMMITTEE INFORMATION 56

AUDIT COMMITTEE CHARTER 57

AUDIT SERVICE FEES 62

INDUSTRY CONDITIONS 63

RISK FACTORS 71

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE 85

ADDITIONAL INFORMATION 85

SCHEDULES

“A” – REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

“B” – REPORT ON RESERVES DATA

GLOSSARY OF TERMS

“6.50% Debentures” means 6.50% convertible unsecured subordinated debentures of the Trust due June 30, 2010;

“7.50% Debentures”means 7.50% convertible unsecured subordinated debentures of the Trust due October 1, 2009;

“7.75% Debentures” means 7.75% convertible unsecured subordinated debentures of the Trust due December 1, 2011;

“8.00% Debentures” means 8.00% convertible unsecured subordinated debentures of the Trust due December 31, 2011;

“8.75% Debentures” means 8.75% convertible unsecured subordinated debentures of the Trust due June 30, 2009;

“Administration Agreement” means the agreement entered into between the Trustee and AOG dated as of June 23, 2006 and providing for the administration of the Trust;

“Administrator” means AOG;

“Advantage” or the“Trust” means Advantage Energy Income Fund, an unincorporated trust formed under the laws of the Province of Alberta pursuant to the Trust Indenture. All references to “Advantage” or the“Trust”, unless the context otherwise requires, are references to Advantage and its predecessors and subsidiaries;

“AIM” means Advantage Investment Management Ltd., a corporation incorporated under the ABCA and which amalgamated with AOG effective June 23, 2006;

“AOG” or the “Corporation” means Advantage Oil & Gas Ltd., a corporation incorporated under the ABCA and a wholly-owned subsidiary of the Trust. All references to “AOG”, unless the context otherwise requires, are references to Advantage Oil & Gas Ltd. and its predecessors;

“AOG Board of Directors” or “Board of Directors” means the board of directors of Advantage Oil & Gas Ltd.;

“Arrangement” means the plan of arrangement involving Advantage, AOG, Ketch, Ketch Resources Ltd., Advantage ExchangeCo II Ltd., AIM, 1231801 Alberta Ltd., Advantage Unitholders and unitholders of Ketch completed on June 23, 2006 whereby each trust unit of Ketch was exchanged for 0.565 of a Trust Unit on a tax-deferred basis in Canada;

“Common Shares” means the common shares of AOG;

“Debentures” means, collectively, the 6.50% Debentures, 7.50% Debentures, 7.75% Debentures, 8.00% Debentures and 8.75% Debentures;

“Distribution Record Date” means, until otherwise determined by the Trustee, the last day of each month of each year, provided that if the last day of the month is not a Business Day, then the Distribution Record Date for such month will be the first Business Day following the last day of each month of the year or such other dates in any year determined from time to time by the Trustee, but December 31 in each year shall be a Distribution Record Date;

“Escrow Agreement” means the agreement entered into among the Trustee, the Trust and various securityholders dated as of April 24, 2006;

“Initial Permitted Securities” means any equity or debt securities, or rights thereto, authorized or issued from time to time by AOG including, without limitation, the Common Shares, Preferred Shares and Notes;

“Ketch” means Ketch Resources Trust;

“Long TermNote Indenture” means the master note indenture dated September 30, 2004 between AOG and the Trustee providing for the issuance of the Long Term Notes;

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“Long Term Notes” means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Long Term Note Indenture;

“Medium Term Note Indenture” means the master note indenture dated September 30, 2004 between AOG and the Trustee providing for the issue of Medium Term Notes;

“Medium Term Notes” means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Medium Term Note Indenture;

“Note Indentures” means, collectively, the Long Term Note Indenture and the Medium Term Note Indenture;

“Note Trustee” means Computershare Trust Company of Canada, or its successor as trustee under the Note Indentures;

“Notes” means the unsecured subordinated promissory notes of AOG issued to us from time to time under the Note Indentures;

“NYSE” means the New York Stock Exchange;

“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 our total assets, (unless otherwise approved by the AOG Board of Directors from time to time): (i) obligations issued or guaranteed by the government of Canada or any province of Canada or any agency or instrumentality thereof; (ii) term deposits, guaranteed investment certificates, certificates of deposit or bankers’ acceptances of or guaranteed by any Canadian chartered bank or other financial institutions (including the Trustee and any affiliate of the Trustee) the short-term debt or deposits of which have been rated at least A or the equivalent by Standard & Poor’s Corporation, Moody’s Investors Service, Inc. or Dominion Bond Rating Service Limited; (iii) commercial paper rated at least A or the equivalent by Dominion Bond Rating Service Limited, in each case maturing within 180 days after the date of acquisition; and (iv) trust units and limited partnership units in trusts and limited partnerships which invest in energy related assets including all types of petroleum and natural gas and energy related assets, and including, without limitation, facilities of any kind, oil sands interests, coal, electricity or power generating assets, and pipeline, gathering, processing and transportation assets;

“Petroleum Substances” means petroleum, natural gas and related hydrocarbons (except coal) including, without limitation, all liquid hydrocarbons, and all other substances, including sulphur, whether gaseous, liquid or solid and whether hydrocarbon or not, produced in association with such petroleum, natural gas or related hydrocarbons;

“Resource Properties” means Canadian resource properties as defined in the Tax Act;

“Royalty” means the 99% interest in AOG ‘s Petroleum Substances within, upon or under certain of its Oil and Natural Gas Properties granted pursuant to the Royalty Agreement;

“Royalty Agreement” means the royalty agreement entered into between AOG and us dated as of June 24, 2006 and providing for the creation of the Royalty;

“SET” means SET Resources Inc.;

“Settled Amount” means the amount of one hundred dollars in lawful money of Canada paid by our settlor to the Trustee for the purpose of settling the Trust;

“Sound” means Sound Resources Trust;

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“Sound Arrangement” means the plan of arrangement involving Advantage, AOG, Sound and SET, various subsidiaries of Advantage, AOG, Sound and SET, holders of trust units of Sound and holders of exchangeable shares of SET, completed on September 5, 2007;

“Subsequent Investment” means those investments which we are permitted to make pursuant to the Trust Indenture, namely royalties in respect of properties and securities of AOG or any other subsidiary of the Trust to fund the acquisition, development, exploitation and disposition of all types of petroleum and natural gas and energy related assets, including without limitation, facilities of any kind, oil sands interests, coal, electricity or power generating assets, and pipeline, gathering, processing and transportation assets and whether effected through an acquisition of assets or an acquisition of shares or other form of ownership interest in any entity the substantial majority of the assets of which are comprised of like assets;

“Tax Act” means the Income Tax Act (Canada), R.S.C. 1985, c.1 (5th Supp), as amended, including the regulations thereunder;

“Trust Fund”, at any time, shall mean such of the following monies, properties and assets that are at such time held by the Trustee for the purposes of the Trust under the Trust Indenture: (i) the Settled Amount; (ii) the Initial Permitted Securities; (iii) the Royalty; (iv) all funds realized from the sale of, or Permitted Investments obtained in exchange for, Trust Units from time to time; (v) any Permitted Investments in which funds may from time to time be invested; (vi) any Subsequent Investments; (vii) any proceeds of disposition of any of the foregoing property including, without limitation, the Royalty but not Trust Units in the case of a redemption thereof to which Section 9.5 of the Trust Indenture applies; and (viii) all income, interest, dividends, return of capital, profit, gains and accretions and additional assets, rights and benefits of any kind or nature whatsoever arising directly or indirectly from or in connection with or accretions to or accruals in respect of any of the foregoing property or such proceeds of disposition from time to time;

“Trust Indenture” means the trust indenture between Computershare Trust Company of Canada and AOG made effective as of April 17, 2001, supplemented as of May 22, 2002 and amended and restated as of June 25, 2002, May 28, 2002, May 26, 2004, April 27, 2005, December 13, 2005, June 23, 2006 and December 31, 2007, pursuant to which Advantage was formed, as the same may be further amended, restated or replaced from time to time;

“Trust Unit” or “Unit” means a unit of the Trust, each unit representing an equal undivided beneficial interest therein;

“Trustee” means Computershare Trust Company of Canada or its successor or successors as trustee under the Trust Indenture;

“TSX” means the Toronto Stock Exchange;

“Unitholders” means the holders from time to time of one or more Trust Units, as shown on the register of such holders maintained by the Trust or by the Trustee, as transfer agent of the Trust Units, on behalf of the Trust; and

“U.S.” means the United States of America.

Words importing the singular number only include the plural, and vice versa, and words importing any gender include all genders. All dollar amounts set forth in this annual information form are in Canadian dollars, except where otherwise indicated.

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ABBREVIATIONS

Oil and Natural Gas Liquids			Natural Gas
bbls	barrels		Mcf	thousand cubic feet
Mbbls	thousand barrels		MMcf	million cubic feet
MMbbls	million barrels		bcf	billion cubic feet
NGLs	natural gas liquids		Mcf/d	thousand cubic feet per day
stb	stock tank barrels of oil		MMcf/d	million cubic feet per day
Mstb	thousand stock tank barrels of oil		m3	cubic metres
MMboe	million barrels of oil equivalent		MMbtu	million British Thermal Units
boe/d	barrels of oil equivalent per day		GJ	Gigajoule
bbls/d	barrels of oil per day
Other
BOE or boe		means barrel of oil equivalent, using the conversion factor of 6 Mcf of natural gas being equivalent to one bbl of oil. The conversion factor used to convert natural gas to oil equivalent is not necessarily based upon either energy or price equivalents at this time.
WTI		means West Texas Intermediate.
API		means the measure of the density or gravity of liquid petroleum products derived from a specific gravity.
psi		means pounds per square inch.

CONVERSION

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By
Mcf	cubic metres	28.174
cubic metres	cubic feet	35.494
bbls	cubic metres	0.159
cubic metres	bbls	6.293
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
gigajoules	MMbtu	0.950

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YOU SHOULD NOT RELY ON FORWARD-LOOKING STATEMENTS

BECAUSE THEY ARE INHERENTLY UNCERTAIN

Certain statements contained in this annual information form, and in certain documents incorporated by reference into this annual information form, constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We and AOG believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this annual information form should not be unduly relied upon. These statements speak only as of the date of this annual information form or as of the date specified in the documents incorporated by reference into this annual information form, as the case may be.

In particular, this annual information form, and the documents incorporated by reference, contain forward-looking statements pertaining to the following:

• the performance characteristics of our assets;

• oil and natural gas production levels;

• the size of the oil and natural gas reserves;

• projections of market prices and costs and the related sensitivities of distributions;

• supply and demand for oil and natural gas;

• expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development;

• drilling plans;

• tax horizons;

• timing of development of undeveloped reserves;

• completion of the Trust Conversion (as defined herein) and the Disopsition of Assets (as defined herein). See “General Development of the Business — Recent Developments”;

• timing of the meeting of Unitholders to approve the Trust Conversion. See “General Development of the Business — Recent Developments”;

• treatment under governmental regulatory regimes and tax laws; and

• capital expenditures programs.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this annual information form:

• volatility in market prices for oil and natural gas;

• liabilities inherent in oil and natural gas operations;

• uncertainties associated with estimating oil and natural gas reserves;

• competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

• incorrect assessments of the value of acquisitions;

• fluctuation in foreign exchange or interest rates;

• stock market volatility and market valuations;

• changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry and income trusts;

• geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and

• the other factors discussed under “Risk Factors”.

Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward looking statements contained in this annual information form and the documents incorporated by reference herein are expressly qualified by this cautionary statement.

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Although the forward-looking statements contained in this Annual Information Form are based upon assumptions which the Trust and AOG believe to be reasonable, the Trust and AOG cannot assure Unitholders that actual results will be consistent with these forward-looking statements. With respect to forward-looking statements contained in this Annual Information Form, the Trust and AOG has made assumptions regarding: current commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the price of oil and natural gas; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; royalty rates and future operating costs.

The Trust and AOG have included the above summary of assumptions and risks related to forward-looking information provided in this Annual Information Form in order to provide Unitholders with a more complete perspective on the Trust’s current and future operations and such information may not be appropriate for other purposes. The Trust’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Trust will derive therefrom. These forward-looking statements are made as of the date of this Annual Information Form and the Trust and AOG disclaim any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

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ADVANTAGE ENERGY INCOME FUND

General

Advantage Energy Income Fund (“Advantage”, the “Trust”, the “Fund”, “us”, “we”, or “our” and, where the context requires, also includes the Trust’s subsidiaries) is an entity that has provided monthly cash distributions to its holders (“Unitholders”) of trust units (“Trust Units”) of the Trust. See “General Development of the Business - Recent Developments – Suspension of Distributions”. 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. See “Additional Information Respecting Advantage Energy Income Fund”.

Advantage Oil & Gas Ltd. (“AOG”) is our wholly-owned oil and natural gas exploitation and development company. It was originally incorporated in 1979 as Westrex Energy Corp. (“Westrex”). Through a plan of arrangement under the Business Corporations Act (Alberta) (“ABCA”), Westrex merged with Search Energy Inc. on December 31, 1996, and changed its name to Search Energy Corp. (“Search”) on January 2, 1997.

Effective May 24, 2001, all of the issued and outstanding common shares of Search were acquired by 925212 Alberta Ltd. (“AcquisitionCo”), a company wholly-owned by us. Search and AcquisitionCo amalgamated and continued as “Search Energy Corp.”. On July 26, 2001, Search acquired all of the issued and outstanding shares of Due West Resources Inc. (“Due West”). Effective August 1, 2001, Search and Due West amalgamated and continued as “Search Energy Corp.”. Effective January 1, 2002, Search acquired a number of natural gas properties located primarily in southern Alberta formerly administered by Gascan Resources Ltd. On June 26, 2002, Search changed its name to Advantage Oil & Gas Ltd. On November 18, 2002, AOG acquired all of the issued and outstanding shares of Best Pacific Resources Ltd. (“Best Pacific”), after which Best Pacific assigned all of its assets to AOG and dissolved. On December 2, 2003, AOG acquired all of the issued and outstanding shares of MarkWest Resources Canada Corp. (“MarkWest”). MarkWest amalgamated with AOG effective January 1, 2004. On September 15, 2004, we indirectly acquired certain petroleum and natural gas properties and related assets from Anadarko Canada Corporation (“Anadarko”) for approximately $186,000,000 before closing adjustments. On December 21, 2004, we indirectly acquired Defiant Energy Corporation (“Defiant”) by way of a plan of arrangement involving a combination of cash consideration, Trust Units and Exchangeable Shares of AOG. Effective January 1, 2005, Defiant amalgamated with AOG. Effective February 1, 2006, Advantage ExchangeCo Ltd. amalgamated with AOG. Effective June 23, 2006, Advantage and Ketch completed the Arrangement with the combined entity continuing under the name Advantage Energy Income Fund. See “General Development of the Business”.

Prior to completion of the Arrangement, Advantage Investment Management Ltd. (“AIM”) acted as manager of the Trust and of AOG. As part of the Arrangement, Advantage internalized its external management structure and eliminated all related fees by acquiring all of the outstanding shares of AIM for total original consideration of 1,933,208 Trust Units which have been placed in escrow and are releasable as to one-third on each of the first three anniversaries of the Arrangement.

Effective September 5, 2007, Advantage and Sound completed the Sound Arrangement whereby Advantage acquired all of the issued and outstanding trust units of Sound and exchangeable shares of SET for consideration of either (i) 0.30 of a Unit; or (ii) $0.66 in cash and 0.2557 of a Unit, for each Sound trust unit or SET exchangeable share held. In connection with the Sound Arrangement, SET, AOG and various other subsidiaries of Advantage, AOG, SET and Sound amalgamated to form “Advantage Oil & Gas Ltd.” See “General Development of the Business”.

Our head office, the head office of AOG and the registered office of AOG is located at Suite 700, 400 – 3rd Avenue S.W., Calgary, Alberta T2P 4H2.

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Our Organizational Structure

The following diagram sets forth the organizational structure of our material subsidiaries as at the date hereof.

Notes:

(1)	The Unitholders own 100% of the Trust.
(2)	All our operations and management are conducted through AOG.
(3)	Advantage receives regular monthly payments in accordance with the Royalty Agreement as well as principal and interest payments from the Advantage Notes and dividends from the Common Shares.

In accordance with the terms of the Trust Indenture, holders of Trust Units are entitled to direct us as to how to vote in respect of all matters to be placed before us, including the selection of directors of AOG, approving AOG’s financial statements, and appointing the auditors of AOG, who shall be the same as our auditors.

GENERAL DEVELOPMENT OF THE BUSINESS

2006

On March 8, 2006, AOG elected to exercise its redemption right to redeem all of its outstanding exchangeable shares. The redemption price per exchangeable share was satisfied by delivering that number of Trust Units equal to the exchange ratio of 1.22138 in effect on May 9, 2006. During 2006, we issued 127,014 Trust Units for the remaining AOG exchangeable shares.

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On June 23, 2006, we completed the merger of Advantage and Ketch under the terms of the Arrangement. The merger was accomplished through the exchange of each trust unit of Ketch for 0.565 of a Trust Unit of Advantage and upon completion, Advantage Unitholders owned approximately 65% of the combined trust and Ketch unitholders owed approximately 35%.

On July 24, 2006, we announced that we adopted a Premium Distribution™, Distribution Reinvestment and Optional Trust Unit Purchase Plan (the “Plan”). The Plan commenced with the monthly cash distribution payable on August 15, 2006 to Unitholders who elected to participate and have their monthly distribution obligation settled through the issuance of additional Trust Units at 95% of the average market price (as defined in the Plan).

On August 1, 2006, we issued 7,500,000 Trust Units under a short-form prospectus offering at $17.30 per Trust Unit. An additional 1,125,000 Trust Units were issued on August 4, 2006 at $17.30 per Trust Unit upon full exercise of the over-allotment option provided to the underwriters. The net proceeds of the offering of approximately $141.4 million were used to pay down bank indebtedness and to subsequently fund capital and general corporate expenditures.

2007

On January 19, 2007, we announced that the cash distribution to be paid on February 15, 2007 to Unitholders of record on January 31, 2007 would be adjusted to $0.15 per Trust Unit from the then current distribution rate of $0.18 per Trust Unit and that the reduction in the monthly distribution rate arose as a result of recent weakness in crude oil and natural gas prices which have been driven by an abnormally mild winter heating season.

On January 19, 2007, we also announced that the Board of Directors of AOG approved our 2007 capital expenditure budget at between $120 and $145 million.

On February 14, 2007, we issued 7,800,000 Trust Units under a short-form prospectus offering at $12.80 per Trust Unit. An additional 800,000 Trust Units were issued on March 7, 2007 at $12.80 per Trust Unit upon exercise of the over-allotment option provided to the underwriters. The net proceeds of the offering of approximately $104.1 million were used to pay down bank indebtedness and to fund capital and general corporate expenditures.

On June 22, 2007, new legislation was passed pursuant to which, commencing January 1, 2011 (provided that we only experience “normal growth” and no “undue expansion” before then) certain distributions will be subject to a trust-level tax, and will be characterized as dividends to the unitholders. See “Risk Factors – Changes in Legislation – SIFT Tax”.

On July 9, 2007, Advantage and Sound jointly announced that their respective boards of directors had approved the Sound Arrangement. On September 5, 2007, the Sound Arrangement was approved by the holders of trust units of Sound (“Sound Units”) and holders of exchangeable shares of SET (“Sound Exchangeable Shares”) and Advantage completed the acquisition of all of the outstanding Sound Units and Sound Exchangeable Shares. Pursuant to the Sound Arrangement, holders of Sound Units received 0.30 of a Unit for each Sound Unit held or, at the election of the holder of Sound Units (“Sound Unitholders”), $0.66 in cash and 0.2557 of a Unit. In addition, all Sound Exchangeable Shares were exchanged for Units or Units and cash at the election of the holders of Sound Exchangeable Shares on the same terms as those offered to Sound Unitholders based on the exchange ratio in effect at the effective date of the Sound Arrangement. In total 16,977,184 Units and $21.4 million in cash was issued to holders of Sound Units and Sound Exchangeable Shares. In addition, Advantage also assumed approximately $108.0 million of bank indebtedness upon closing of the Sound Arrangement.

On August 16, 2007, we announced that Stephen Balog had been appointed to the Board of Directors of AOG.

We negotiated an increase to our credit facilities in September of 2007 and currently have a $710 million credit facility agreement consisting of a $690 million extendible revolving loan facility and a $20 million operating loan facility. The credit facilities are collateralized by a $1 billion floating charge demand debenture, a general security agreement and a subordination agreement covering all assets and cash flows.

On September 18, 2007, our former auditors KPMG LLP resigned as auditors of the Trust and PricewaterhouseCoopers LLP were appointed the auditors of the Trust.

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On December 14, 2007, Advantage announced that in light of the recent strength of the Canadian dollar combined with the continuing weakness in crude oil and natural gas prices, the Board of Directors of Advantage felt it is prudent to adjust the cash distribution beginning with the month of December to $0.12 per Unit from $0.15 per Unit.

On December 14, 2007, we also announced that the Board of Directors of AOG approved our 2008 capital expenditure budget of between $130 and $145 million.

2008

On June 27, 2008, we announced that the Board of Directors had approved a $55 million increase to the 2008 capital expenditure budget to $200 million.

In June 2008, the Trust renewed its credit facilities for a further year with the next annual review scheduled to occur in June 2009.

On October 6, 2008, we announced that the Board of Directors had approved an additional $50 million increase to the 2008 capital expenditure budget to $250 million. The increased capital was directed towards additional activity at our Montney natural gas resource play in our Glacier property.

On November 7, 2008, we announced the appointment of Mr. Paul Haggis to the Board of Directors.

On December 18, 2008, we announced a reserve and operational update for our Montney natural gas play at Glacier where the Trust incurred approximately $92 million of capital expenditures in 2008 evaluating the resource potential in this area. The reserve and operational update included highlights of the Glacier property and a hedging update. In addition, as a result of continuing weakness in the commodity price environment, the Board of Directors determined that the cash distribution level would be adjusted from the current $0.12 per Trust Unit per month to $0.08 per Trust Unit per month beginning with the December 2008 distribution.

Recent Developments

Unitholder Rights Plan

On January 20, 2009, we announced that the Board of Directors of AOG adopted a Unitholder Rights Plan (the “Rights Plan”) for which Unitholder approval will be sought at the Trust’s annual meeting of Unitholders to be held in late May, 2009. The Rights Plan is designed to provide Unitholders and the Board of Directors with adequate time to consider and evaluate any unsolicited bid made for the Trust, to provide the Board of Directors with adequate time to indentify, develop and negotiate value-enhancing alternatives, if considered appropriate, to any such unsolicited bid, to encourage the fair treatment of Unitholders in connection with any take-over bid for the Trust and to ensure that any proposed transaction is in the best interests of the Unitholders of the Trust.

Appointment of Executive Officers

On January 27, 2009, we announced the following appointments to the executive officer team of AOG: (i) Mr. Andy Mah, the former President and Chief Operating Officer, was appointed to the position of Chief Executive Officer; (ii) Mr. Kelly Drader, the former Chief Executive Officer, was appointed as President and Chief Financial Officer; (iii) Mr. Craig Blackwood, the former Director of Finance, was appointed as Vice-President, Finance; and (iv) Mr. Peter Hanrahan, the former Vice-President of Finance and Chief Financial Officer, elected to resign from such positions.

Reduction of Distributions

On February 13, 2009, we announced a reduction in the cash distribution from $0.08 per Trust Unit per month to $0.04 per Trust Unit per month, in order to ensure the strength of our balance sheet through the current economic climate.

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Trust Conversion

On March 18, 2009, we announced that the Board of Directors of AOG had unanimously approved a conversion (the “Trust Conversion”) of the Fund to a growth-oriented corporation (“New Advantage”), which, subject to approval of Unitholders as well as customary court and regulatory approvals, is anticipated to be completed on or about June 30, 2009. The Board of Directors believes that Trust Conversion combined with the asset disposition program described below and debt reduction initiative will position New Advantage to pursue the significant development potential at Glacier and to continue development of our conventional assets. The Trust Conversion will have the added benefit of removing the uncertainty surrounding the upcoming changes in Canadian tax law whereby the government will begin imposing taxes on income trusts on January 1, 2011. See “Risk Factors – Changes in Legislation – SIFT Tax”.

Under the Trust Conversion, Unitholders will receive one share in New Advantage for each Trust Unit they hold. Following the completion of the Trust Conversion, New Advantage will assume all the obligations of the Fund in respect of the Fund’s outstanding Debentures such that, following completion of the Trust Conversion and upon maturity of the Debentures or such other date as communicated by Advantage, the Debentures will be satisfied with cash or the shares of New Advantage in lieu of Trust Units, at the option of New Advantage. The Trust Conversion will be accomplished by way of a plan of arrangement and requires the approval of Unitholders, as well as customary court and regulatory approvals. A management information circular and proxy statement outlining the details of the conversion will be mailed to Unitholders in connection with a meeting of Unitholders, which is expected to be scheduled on or about June 29, 2009. To be implemented, the Trust Conversion must be approved by not less than two-thirds of the votes cast by Unitholders voting at such meeting. Closing of the conversion is anticipated to be on June 30, 2009.

Disposition of Assets

On March 18, 2009, we also announced that we had retained Tristone Capital Inc. to assist with the disposition of up to 11,300 boe/d of light oil and liquids rich natural gas properties (the "Disposition of Assets"). The net proceeds from these sales will initially be used to reduce outstanding bank debt to improve Advantage’s financial flexibility. Advantage may also draw down its credit facilities in the future to redeem certain of the Fund’s Debentures. The Trust Conversion will not be contingent on the magnitude of asset sales completed.

Suspension of Distributions

On March 18, 2009, we further announced that as another step to increase Advantage’s financial flexibility and to focus on development and growth at our Glacier property, Advantage would be discontinuing the payment of cash distributions with the final cash distribution paid to Unitholders on March 16, 2009 to Unitholders of record as of February 27, 2009. New Advantage will not pay dividends in the immediate future and will instead, redirect cash flow to future capital expenditures and debt repayment.

Anticipated Changes in the Business

As at the date hereof, other than the Trust Conversion and the Disposition of Assets, we do not anticipate that any material change in our business shall occur during the balance of the 2009 financial year.

Significant Acquisitions

Advantage did not complete any significant acquisitions in the year ended December 31, 2008 for which disclosure is required under Part 8 of National Instrument 51-102.

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DESCRIPTION OF OUR BUSINESS AND OPERATIONS

Advantage Energy Income Fund

We are a limited purpose trust and are restricted to:

1.	investing in the Initial Permitted Securities, the Permitted Investments, Subsequent Investments and such other securities and investments as AOG may determine, provided that under no circumstances shall the Trustee or AOG purchase or authorize the purchase of any security, asset or investment (collectively a “Prohibited Investment”) on our behalf or using any of our assets or property which are a “small business security” as that expression is used in Part LI of the Regulations to the Tax Act or would result in us not being considered either a “unit trust” or a “mutual fund trust” for purposes of the Tax Act at the time such investment was made;
2.	disposing of any part of the Trust Fund, including, without limitation, any Permitted Investments;
3.	acquiring the Royalty and other royalties in respect of Resource Properties;
4.	temporarily holding cash, and Permitted Investments (including investments in AOG) for the purposes of paying Trust expenses and Trust liabilities, paying amounts payable by us in connection with the redemption of any Trust Units, and making distributions to Unitholders;
5.	acquiring or investing in securities of AOG or any other subsidiary of ours to fund the acquisition, development, exploitation and disposition of all types of petroleum and natural gas related assets, including, without limitation, facilities of any kind and whether effected through the acquisition of assets or the acquisition of shares or other form of ownership interest in any entity, the substantial majority of the assets of which are comprised of like assets;
6.	undertaking such other business and activities including investing in securities as shall be approved by AOG from time to time provided that we shall not undertake any business or activity which is a Prohibited Investment (as defined in the Trust Indenture);

and to pay the costs, fees and expenses associated therewith or incidental thereto.

In accordance with the terms of the Trust Indenture, we may make cash distributions to our Unitholders of the interest income earned from the Long Term Notes and Medium Terms Notes and principal repayments, royalty income earned on the Royalty, dividends (if any) received on, and amounts, if any, received on redemption of, Common Shares and Preferred Shares, and income and distributions received from any Permitted Investments after expenses and capital expenditures, any cash redemptions of Trust Units, and other expenditures. See “Additional Information Respecting Advantage Energy Income Fund– Cash Distributions”.

Advantage Oil & Gas Ltd.

AOG is actively engaged in the business of oil and gas exploration, development, acquisition and production in the provinces of Alberta, British Columbia and Saskatchewan.

We employ a strategy to maintain production from AOG’s existing production base while focusing capital expenditures on low-risk development opportunities. As current and future practice, Advantage has established a financial hedging strategy and may manage the risk associated with changes in commodity prices by entering into derivatives. See “Risk Factors”. AOG generally sells or farms out higher risk projects while actively pursuing growth opportunities through oil and gas property acquisitions, as well as through corporate acquisitions. AOG targets acquisitions that are accretive to net asset value and that increase our reserve and production base per Trust Unit outstanding. Acquisitions must also meet reserve life index criteria and exhibit low risk opportunities to increase reserves and production. It is currently intended that AOG will finance acquisitions and investments through bank financing, the issuance of additional Trust Units from treasury and the issuance of subordinated convertible debentures, maintaining prudent leverage.

Reorganizations

Other than the Arrangement, the Sound Arrangement and the proposed Trust Conversion, there have been no material reorganizations of Advantage or AOG and or any of our subsidiaries within the three most recently completed financial years or proposed for the current financial year. See “General Development of the Business”.

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STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The report of management and directors on oil and gas disclosure in Form 51-101F3 and the report on reserves data by Sproule Associates Limited (“Sproule”) in Form 51-101F2 are attached as Schedules “A” and “B” to this annual information form, which forms are incorporated herein by reference.

The statement of reserves data and other oil and gas information set forth below (the “Statement”) is dated December 31, 2008. The effective date of the Statement is December 31, 2008 and the preparation date of the Statement is February 25, 2009.

Disclosure of Reserves Data

The reserves data set forth below (the “Reserves Data”) is based upon an evaluation by Sproule with an effective date of December 31, 2008 contained in a report of Sproule dated February 25, 2009 (the “Sproule Report”). The Reserves Data summarizes our oil, natural gas liquids and natural gas reserves and the net present values of future net revenue for these reserves using forecast prices and costs. The Reserves Data conforms with the requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional information not required by NI 51-101 has been presented to provide continuity and additional information which we believe is important to the readers of this information. We engaged Sproule to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

All of our reserves are in Canada and, specifically, in the provinces of Alberta, British Columbia and Saskatchewan.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of our crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. In certain of the tables set forth below, the columns may not add due to rounding.

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SUMMARY OF OIL AND GAS RESERVES

as of December 31, 2008

FORECAST PRICES AND COSTS

	RESERVES
	LIGHT AND MEDIUM OIL		HEAVY OIL
RESERVES CATEGORY	Gross (Mbbl)	Net (Mbbl)	Gross (Mbbl)	Net (Mbbl)
PROVED
Developed Producing	19,560	16,748	2,329	2,114
Developed Non-Producing	254	235	204	180
Undeveloped	3,730	2,926	312	274
TOTAL PROVED	23,544	19,908	2,845	2,568
PROBABLE	15,928	12,400	3,697	2,958
TOTAL PROVED PLUS PROBABLE	39,473	32,308	6,542	5,526

	RESERVES
	NATURAL GAS		NATURAL GAS LIQUIDS
RESERVES CATEGORY	Gross (MMcf)	Net (MMcf)	Gross (Mbbl)	Net (Mbbl)
PROVED
Developed Producing	264,009	221,693	5,407	4,006
Developed Non-Producing	28,484	24,063	245	177
Undeveloped	116,503	96,217	1,143	848
TOTAL PROVED	409,087	341,972	6,795	5,032
PROBABLE	290,738	230,742	3,970	2,888
TOTAL PROVED PLUS PROBABLE	699,824	572,714	10,765	7,920

	RESERVES
	TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross (Mboe)	Net (Mboe)
PROVED
Developed Producing	71,313	59,817
Developed Non-Producing	5,451	4,602
Undeveloped	24,602	20,084
TOTAL PROVED	101,366	84,503
PROBABLE	72,052	56,703
TOTAL PROVED PLUS PROBABLE	173,418	141,206

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SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE

as at December 31, 2008

FORECAST PRICES AND COSTS

	Before Income Tax Discounted at (%/year)					After Income Taxes Discounted at (%/year)					Unit Value Before Income Tax Discounted at 10%/ year(1)
RESERVES CATEGORY	0% ($000’s)	5% ($000’s)	10% ($000’s)	15% ($000’s)	20% ($000’s)	0% ($000’s)	5% ($000’s)	10% ($000’s)	15% ($000’s)	20% ($000’s)	($/boe)
PROVED
Developed       Producing	2,586,932	1,781,161	1,394,029	1,161,777	1,004,478	2,529,353	1,770,177	1,391,569	1,161,153	1,004,303	23.30
Developed     Non-Producing	164,372	122,933	97,495	80,198	67,663	132,839	112,459	93,797	78,822	67,126	21.19
Undeveloped	627,257	361,683	223,136	140,860	87,921	488,759	297,988	191,437	124,146	78,698	11.11
TOTAL PROVED	3,378,561	2,265,777	1,714,660	1,382,835	1,160,062	3,150,950	2,180,624	1,676,803	1,364,120	1,150,127	20.29
PROBABLE	3,026,305	1,534,620	948,777	653,250	480,504	2,286,388	1,184,119	750,589	530,187	399,617	16.73
TOTAL PROVED     PLUS     PROBABLE	6,404,866	3,800,397	2,663,437	2,036,085	1,640,566	5,437,338	3,364,743	2,427,393	1,894,308	1,549,744	18.86

Note:

(1) The unit values are based on net reserve volumes.

RESERVES CATEGORY	REVENUE ($000’s)	ROYALTIES ($000’s)	OPERATING COSTS ($000’s)	DEVELOP-MENT COSTS ($000’s)	ABANDONMENT COSTS ($000’s)	FUTURE NET REVENUE BEFORE INCOME TAXES ($000’s)	FUTURE INCOME TAXES ($000’s)	FUTURE NET REVENUE AFTER INCOME TAXES ($000’s)
Proved Reserves	7,190,465	1,152,423	2,175,271	378,242	105,955	3,378,561	227,611	3,150,950
Proved Plus Probable Reserves	13,238,460	2,342,783	3,653,87	695,526	141,389	6,404,866	967,527	5,437,338

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FUTURE NET REVENUE

BY PRODUCTION GROUP

as of December 31, 2008

FORECAST PRICES AND COSTS

RESERVES CATEGORY	PRODUCTION GROUP	FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year) ($000’s)	UNIT VALUE ($/boe)
Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	631,400	24.76
	Heavy Oil (including solution gas and other by-products)	69,750	23.75
	Natural Gas (including by-products but excluding solution gas and by-products from oil wells)	952,854	18.03
	Non-Conventional Oil and Gas Activities	60,656	18.97
	TOTAL	1,714,660	20.29
Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	978,564	23.56
	Heavy Oil (including solution gas and other by-products)	130,803	21.63
	Natural Gas (including by-products but excluding solution gas and by-products from oil wells)	1,464,487	16.50
	Non-Conventional Oil and Gas Activities	89,583	18.48
	TOTAL	2,663,437	18.86

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2008, reflected in the Reserves Data. These price assumptions were provided to us by Sproule and were Sproule’s then current forecasts at the date of the Sproule Report.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS⁽¹⁾

as of December 31, 2008

FORECAST PRICES AND COSTS

Year	WTI Cushing Oklahoma ($US/bbl)	Light Sweet Crude Oil at Edmonton 40o API ($Cdn/bbl)	Medium Crude Oil 29o API ($Cdn/bbl)	Hardisty Heavy 12o API ($Cdn/bbl)	NATURAL GAS AECO-C Spot ($Cdn/ MMBtu)	NATURAL GAS LIQUIDS Edmonton Pentanes Plus ($Cdn/bbl)	NATURAL GAS LIQUIDS Edmonton Butanes ($Cdn/bbl)	INFLA-TION RATES %/Year	EXCHANGE RATE (2) ($US/$Cdn)
Forecast(3)
2009	53.73	65.35	58.16	47.05	6.82	66.93	51.15	2.0	0.800
2010	63.41	72.78	66.23	54.58	7.56	74.54	54.25	2.0	0.850
2011	69.53	79.95	72.76	59.96	7.84	81.88	59.59	2.0	0.850
2012	79.59	86.57	79.65	67.53	8.38	88.66	64.53	2.0	0.900
2013	92.01	94.97	87.38	74.08	9.20	97.27	70.79	2.0	0.950
2014	93.85	96.89	89.14	75.58	9.41	99.23	72.22	2.0	0.950
2015	95.72	98.85	90.94	77.10	9.62	101.23	73.68	2.0	0.950
2016	97.64	100.84	92.78	78.66	9.83	103.28	75.16	2.0	0.950
2017	99.59	102.88	94.65	80.25	10.05	105.36	76.68	2.0	0.950
2018	101.58	104.96	96.56	81.87	10.27	107.49	78.23	2.0	0.950
2019	103.61	107.08	98.51	83.52	10.50	109.66	79.81	2.0	0.950
Thereafter	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	+2%/year	2.0	0.950

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Notes:

(1)	This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer.
(2)	The exchange rate used to generate the benchmark reference prices in this table.
(3)	As at December 31.

Weighted average historical prices, including hedging, realized by us for the year ended December 31, 2008, were $8.14/Mcf for natural gas, $89.71/bbl for crude oil, and $75.93/bbl for natural gas liquids.

Reconciliations of Changes in Reserves

RECONCILIATION OF

COMPANY GROSS RESERVES

BY PRODUCT TYPE

FORECAST PRICES AND COSTS

	Light And Medium Oil						Heavy Oil						Natural Gas Liquids
FACTORS	WI Proved (Mbbl)		WI Probable (Mbbl)		WI Proved Plus Probable (Mbbl)		WI Proved (Mbbl)		WI Probable (Mbbl)		WI Proved Plus Probable (Mbbl)		WI Proved (Mbbl)		WI Probable (Mbbl)		WI Proved Plus Probable (Mbbl)
December 31, 2007	26,154		17,476		43,630		2,237		3,271		5,508		7,840		3,773		11,613
Extensions	496		245		741		0		0		0		254		188		442
Improved Recovery	318		249		567		0		0		0		324		511		835
Technical Revisions	(492	)	(2,048	)	(2,540	)	532		(226	)	306		(1,170	)	(618	)	(1,788	)
Discoveries	240		96		336		0		0		0		56		11		67
Acquisitions	0		0		0		0		0		0		1		1		2
Dispositions	0		0		0		0		0		0		0		0		0
Economic Factors	(49	)	(89	)	(138	)	446		652		1,098		314		104		418
Production	(3,123	)	0		(3,123	)	(370	)	0		(370	)	(824	)	0		(824	)
December 31, 2008	23,544		15,929		39,473		2,845		3,697		6,542		6,795		3,970		10,765

	Associated and Non-Associated Gas						Natural Gas - Solution
FACTORS	WI Proved (MMcf)		WI Probable (MMcf)		WI Proved Plus Probable (MMcf)		WI Proved (MMcf)		WI Probable (MMcf)	WI Proved Plus Probable (MMcf)
December 31, 2007	298,959		162,487		461,446		33,982		19,681	53,663
Extensions	17,292		19,499		36,7411		1,190		588	1,778
Improved Recovery	37,263		74,443		11,706		763		598	1,361
Technical Revisions	21,329		(6,973	)	14,356		3,101		2,124	5,225
Discoveries	940		231		1,171		180		72	252
Acquisitions	97		198		295		0		0	0
Dispositions	0		0		0		0		0	0
Economic Factors	13,987		6,158		20,145		170		98	268
Production	(37,143	)	0		(37,143	)	(5,037	)	0	(5,037	)
December 31, 2008	352,674		256,043		608,717		34,349		23,161	57,510

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	Coalbed Methane						Oil Equivalent
FACTORS	WI Proved (MMcf)		WI Probable (MMcf)		WI Proved Plus Probable (MMcf)		WI Proved (MBoe)		WI Probable (MBoe)		WI Proved Plus Probable (MBoe)
December 31, 2007	17,992		8,445		26,437		94,720		56,289		151,009
Extensions	1,133		589		1,722		4,011		3,879		7,890
Improved Recovery	3,883		3,504		7,387		7,627		13,851		21,478
Technical Revisions	(669	)	(2,235	)	(2,904	)	2,831		(4,074	)	(1,243	)
Discoveries	0		0		0		483		158		641
Acquisitions	2,425		692		3,117		420		150		570
Dispositions	0		0		0		0		0		0
Economic Factors	93		538		631		3,086		1,799		4,885
Production	(2,793	)	0		(2,793	)	(11,812	)	0		(11,812	)
December 31, 2008	22,064		11,533		33,597		101,366		72,052		173,418

Notes:

(1) Volumes related to infill drilling are included in the Improved Recovery category, noted above.

Additional Information Relating to Reserves Data

Undeveloped Reserves

Undeveloped reserves are attributed by Sproule in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Proved and probable undeveloped reserves have been assigned in accordance with engineering and geological practices as defined under NI 51-101. In general, undeveloped reserves are planned to be developed over the next two years.

In some cases, it will take longer than two years to develop these reserves. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). For more information, see “Risk Factors”.

The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each by product type, first attributed to us in each of the following financial years.

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Proved Undeveloped Reserves

	Light and Medium Oil (Mbbl)		Heavy Oil (Mbbl)		Natural Gas (MMcf)		NGLs (Mbbl)
Year	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
Prior thereto	1,372	1,372	0	0	4,262	4,262	211	211
2006	1,047	2,419	0	0	10,547	14,809	576	787
2007	1,371	3,790	297	297	30,056	44,865	308	1,095
2008	299	4,089	0	297	44,311	89,176	334	1,429

Sproule has assigned 24.6 MMboe of proven undeveloped reserves in the Sproule Report under forecast prices and costs, together with $359.7 million of associated undiscounted future capital expenditures. Proven undeveloped capital spending in the first two forecast years of the Sproule Report accounts for $164.7 million, or 46 percent, of the total forecast. These figures increase to $314 million or 87 percent, during the first five years of the Sproule Report.

Probable Undeveloped Reserves

	Light and Medium Oil (Mbbl)		Heavy Oil (Mbbl)		Natural Gas (MMcf)		NGLs (Mbbl)
Year	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
Prior thereto	1,029	1,029	0	0	13,054	13,054	446	446
2006	748	1,777	0	0	18,049	31,103	572	1,018
2007	2,410	4,187	2,312	2,312	40,261	71,364	528	1,546
2008	150	4,337	0	2,312	69,509	140,873	441	1,987

Sproule has assigned 39.9 MMboe of probable undeveloped reserves and has allocated future development capital of $313.3 million to all probable undeveloped reserves with $170 million scheduled for the first five years.

Significant Factors or Uncertainties

High operating costs substantially reduce our netback, which in turn reduces the amount of cash available for reinvestment in drilling opportunities. This becomes most relevant during periods of low commodity prices when profits are more significantly impacted by high costs.

Future Development Costs

The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserve categories noted below.

	Forecast Prices and Costs
Year	Proved Reserves (MM$)	Proved Plus Probable  Reserves (MM$)
2009	124,795	174,806
2010	56,079	98,709
2011	74,574	96,144
2012	62,377	107,279
2013	13,911	28,740
Total: Undiscounted for all years	378,242	695,526

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To fund our capital program, including future development costs, we have many financing alternatives available including partial retention of cash flow from operations, bank debt financing, issuance of additional Units, and issuance of convertible debentures. We evaluate the appropriate financing alternatives closely and have made use of all these options dependent on the given investment situation and the capital markets. We maintain a capital structure that is similar to our industry peer group and that will maximize the investment return to Unitholders as compared to the cost of financing. We expect to continue using all financing alternatives available to continue pursuing our oil and gas development strategy. The assorted financing instruments have certain inherent costs which we consider in the economic evaluation of pursuing any development opportunity.

There can be no guarantee that funds will be available or that we will allocate funding to develop all of the reserves attributed in the Sproule Report. Failure to develop those reserves would have a negative impact on future production and cash flow and could result in negative revisions to our reserves.

Other Oil and Gas Information

Our properties are spread geographically throughout the Western Canadian Sedimentary Basin. This sedimentary basin covers a large portion of the four western Canadian provinces, with the majority of our properties concentrated in Alberta, north eastern British Columbia and in southeast Saskatchewan. These properties produce from a variety of various aged geological formations and reservoirs. We operate over 85% of our properties. This allows us to control the nature and timing of the capital investments necessary to maximize the potential in developing these assets.

Our properties can be divided on the broad basis of commodity and of production type. Light or medium gravity oil accounts for 30% of our production and 23% of our reserves. A further 63% of production and 67% of reserves are natural gas.

Rates referenced in the following property descriptions are as of February 28, 2009 unless otherwise noted and reserves quoted are as reported in the Sproule Report to December 31, 2008.

Glacier, Alberta

The Glacier property lies along the Alberta side of the border with British Columbia between Grande Prairie and Dawson Creek. The primary zone of interest is the tight gas resource play in the Triassic Montney Formation siltstones. The property consists of 88 gross (79 net) sections with Montney interests with an average working interest of 90%. An additional 6 sections of land have shallow rights with production from various Cretaceous aged reservoirs.

In the first three months of 2008, Advantage drilled and completed various intervals within the Montney in 5 vertical wells (4.33 net) on the Glacier property. In addition to continuing expiring land, these wells delineated and established the presence of commercial gas reservoir in both the Upper Montney shore face portion as well as in the Lower Montney shelf /turbidite portion of the formation. The Glacier property has compelling analogy with the immediately adjacent Swan/Tupper field where in excess of 150 horizontal wells produce over 275 MMcf/d across two competitor’s properties.

Advantage drilled 6 horizontals and an additional 2 verticals in the remainder of 2008. Four additional verticals, used for delineation and land continuance and 5 additional horizontals were added during the first quarter of 2009. Advantage has now completed 9 of the 11 horizontal wells with multi-stage frac completions with an average of 7 fracture stimulations per well using, on average, an 80 tonne CO2 frac per stimulation. The average of these 9 wells test rates is 3.6 MMcf/d. As of March 2009, two of these wells came onstream at slightly better than the average test rate. Total production from our existing compression is above 8 MMcf/d; however, by early April 2009 it is anticipated that our expansion of compression and pipeline looping will be complete to allow for production levels to increase to between 25 and 30 MMcf/d. Advantage has constructed a 22 kilometer sales line which carries our gas to the Wembley gas plant for processing and sale. Advantage has in its 2009 budget

21

an additional 3 horizontal wells remaining, which will be used to keep the facility volumes at capacity. Planning to expand capacity and allow for additional drilling will commence in the second quarter. Reserves have been assigned to 32 of the 88 sections of land on the basis of just over two wells per section. Our land is currently spaced to allow for 8 wells per section (4 in each of the upper and lower Montney formation); however, offsetting competitor’s are already developing with as many as 16 wells per section. On the basis of 8 wells per section, there are 704 locations on the 88 Advantage sections. Numerous other shallow producing horizons contribute comparatively minor volumes to the overall production; however, there are identified several uphole zones with great potential as resource style horizons for future delineation.

Sproule evaluated our proved reserves in the area and assigned 96.3 bcf of natural gas and 565 Mbbls of crude oil and NGLs on 32 sections of land. In addition, 127 bcf of probable natural gas reserves and 748 Mbbls of probable crude oil and NGLs reserves have been assigned to this property.

Nevis, Alberta

The Nevis property is situated 60 kilometres east of Red Deer. Nevis is an operated property consisting of approximately 90 sections of land with an average working interest of 76%. This property produces natural gas from numerous shallow depth horizons (400 to 800 metres) including the Horseshoe Canyon, Edmonton, and Belly River formations. Nevis is Advantage’s largest producing property with current production from all zones at Nevis of 4,900 boe/d representing in excess of 15% of total corporate volumes.

The main producing zone is a Devonian aged, Wabamun Formation, oil and gas reservoir which occurs at 1,600 metres of depth. Because this reservoir is a low permeability carbonate with characteristically low inflow in vertical wells, the pool is being developed with horizontal wells (4 per section) each with an average horizontal length of 1,200 metres. Crude oil quality ranges between 35^o and 42^o API. Drilling for the Wabamun in 2008 focused on the west side of the property with 11 gross (10.6% net) new horizontal wells drilled. Facilities and compression were expanded to accommodate the additional volumes established from the 2007 and 2008 drilling programs. Up to 10 horizontal Wabamun locations remain under current spacing approvals. Three wells are included in the 2009 budget. With the construction of the west side facilities, now all the oil on the property areas is processed at Advantage central facilities, with sales oil trucked to market. Natural gas is gathered through company owned pipelines and delivered to third party midstream for final processing and sale.

In 2008, 35 wells were drilled for Horseshoe Canyon coal bed methane (“CBM”) with an average working interest of 78%. These wells were brought onstream at an initial average rate of 120 mcf/d. In addition the main gathering system was expanded and compression was added at two central sites and field compression was optimized to handle the additional volumes and ensure the wells are operating against minimal line pressure. Advantage acquired an additional 4,445 net acres in 2008 which will provide about half of the approximately 40 remaining CBM drilling. There are 17 CBM locations in the current 2009 budget. The CBM is currently developed on the basis of 4 wells per section of land.

The Sproule Report assigns 46.5 bcf of proven natural gas reserves and 4,789 Mbbls of proven crude oil and NGL reserves to this property. In addition, 23 bcf of probable natural gas reserves and 2,408 Mbbls of probable crude oil and NGL reserves have been assigned to this property.

Martin Creek, Black and Conroy, British Columbia

The Martin Creek, Black and Conroy properties are located approximately 100 kilometres northwest of Fort St. John, British Columbia. The property is operated with an average 76% overall working interest. This property is in the winter drilling area which requires all drilling, completion and tie in activities to occur essentially between January 1 and the end of March each season. In the latest winter program beginning in January 2009, 4 wells averaging 90% working interest were drilled in the Conroy/Black area. These wells were successful in multiple zones including the Cretaceous Bluesky Formation as well as reservoirs within the Triassic Charlie Lake and Baldonnel Formations. These zones occur at moderate depths between 800 to 1,300 metres. All 4 wells in the 2009 program were cased and completed with three being tied in this season. Ten wells were drilled a year ago in the January 2008 program of which 8 have been on production since March 2008 and one will be tied in with the 2009 program. Total production prior to this winter’s drilling program from the greater Martin Creek, including the Black - Conroy areas is currently 17 MMcf/d with 350 bbl/d of oil and NGL averaging 3,250 boe/d. In 2008, Advantage constructed a 26 kilometre all year access road to our major compression sites that will also allow us

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access to this portion of the property outside of the winter operating season. We own a 60% to 100% working interest in key facilities, including five compressor stations, one gas plant with 24 MMcf/d current throughput and over 290 kilometres of pipelines, which gives us a dominant infrastructure position in this portion of British Columbia.

Sproule evaluated our proved reserves in the area and assigned 36 bcf of natural gas and 559 Mbbls of crude oil and NGLs. In addition, 22 bcf of probable natural gas reserves and 316 Mbbls of probable crude oil and NGLs reserves have been assigned to this property.

Shallow Gas Properties

A significant portion of our production comes from shallow gas properties at Medicine Hat, Bantry, and Shouldice. Production from these three properties is 2,210 boe/d. These projects are all located in southern Alberta and occur between 500 and 1,200 metres of depth. Typical of shallow gas, these properties are resource plays which require a large number of wells to extract the very large in place reserves at relatively low per well production rates. As a result, they have a long production life (long reserve life index or “RLI”). These reservoirs consist of low permeability strata, requiring fracture stimulation to enhance and induce productivity. The wells are gathered by an extensive network of low pressure pipelines which feed into large central gas compression facilities. All of these properties have been downspaced to allow for multiple gas wells per section.

MEDICINE HAT - The Medicine Hat property is located 20 kilometres northeast of the City of Medicine Hat in the heart of the south-eastern shallow gas area. We have a 100% working interest in 24 sections of land from where production is taken from all of the main shallow gas producing formations including the Medicine Hat “A”, “C” and “D” sands, as well as both the Upper and Lower Milk River sands. When the property was acquired in January 2002 there were 115 wells producing approximately 5.2 MMcf/d of natural gas. From January 2002 to December 2005, 320 new wells were added. There has been no drilling since; however, a regular program of well clean outs keeps these wells optimized. Production from this property is currently 7.8 MMcf/d or 1,296 boe/d.

Sproule evaluated our reserves in the Medicine Hat property and assigned 33 bcf of proved natural gas reserves and 10 bcf of probable reserves.

BANTRY – This property is located immediately east of the town of Brooks straddling the TransCanada Highway. The property consists of 84 sections of land ranging between 50% and 100% working interest. Production occurs primarily from Basal Colorado Formation channel sandstones and various sandstones within the Bow Island Formation. Drilling depth is shallow with average wells less than 1,000 metres. No new wells were added in 2008. Natural gas is gathered into our operated compression and dehydration facilities. Current production from this area is 544 boe/d.

The Sproule Report assigns 8.3 bcf of proven natural gas reserves and 3.4 bcf of probable natural gas reserves to this property.

SHOULDICE - The Shouldice area of southern Alberta is located approximately 50 kilometres southeast of the City of Calgary. We have an average working interest of more than 85% in 33 sections of land and operate in excess of 90% of our production in the area. Much of this acreage is downspaced to accommodate additional drilling. No new wells were added in 2008. Both natural gas and crude oil are produced and gathered through our facilities of varying working interests. Current natural gas production of 363 boe/d is produced on a co-mingled basis from the Medicine Hat Formation sands with various Belly River Formation sands.

The Sproule Report assigns 5.8 bcf of proven natural gas reserves and 4.2 bcf of probable natural gas reserves to this property.

Southeast Saskatchewan

This area consists of a host of individual properties within the Williston Sedimentary Basin in the southeast corner of Saskatchewan. Production at the major properties comes principally from the Ordovician Red River Formation at Midale and Froude, Devonian Winnipegosis Formation at Steelman and from Mississippian Midale/Frobisher Formations at Steelman, Weyburn and Workman, McCoun and Crystal Hills  and Pinto. In 

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2008, we drilled 4 gross (3.2 net) wells. Advantage has no drilling program anticipated in southeast Saskatchewan in 2009. Also during 2008, resulting from three separate farmouts to three industry partners in the Midale, Froude and Viewfield areas, 23 Bakken horizontal wells with an average 10% overriding royalty to Advantage were drilled. Combined production from all the properties in southeast Saskatchewan (excluding the Wapella area) is 1,486 boe/d.

Sproule evaluated our proved reserves in southeast Saskatchewan and assigned 5,180 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 3,047 Mbbls of crude oil and NGLs.

WAPELLA/RED JACKET - Our Wapella property is located 200 kilometres east of Regina and produces medium-gravity (25° API) oil from Cretaceous and Jurassic-aged sandstone reservoirs. It is characterized by its relatively high reserve life index, high working interest and substantial undeveloped acreage. There is a significant inventory of drilling locations. The pool is being developed with a staged waterflood program to enhance reserves and productivity. Future plans call for continued delineation and development of the pool as well as expansion of the waterflood scheme. No wells were drilled in 2008 or are anticipated in 2009. Production from the Wapella area is currently 703 boe/d. There are over two townships of undeveloped land in the Red Jacket portion of this property, many of which are fee title lands which have excellent future exploration potential.

Sproule evaluated our proved reserves in Wapella/Red Jacket and assigned 2,637 Mbbls of crude oil. Probable reserves in this area were evaluated by Sproule at 1,121 Mbbls of crude oil.

Willesden Green (Open Lake), Alberta

The Willesden Green property is located approximately 35 kilometres north of the Town of Rocky Mountain House. We operate and have in excess of 90% working interest. In 2008 we successfully drilled and completed five 2,400 metre deep wells targeting two distinct plays. Two were drilled on seismic anomalies targeting Jurassic Rock Creek gas play on the east side of the property and the remaining three targeted Cretaceous Ostracode/Glauconite oil on the north side of the property. Two of the oil wells are capable of over 400 bbl/d but produce their assigned production allowables in 6 days each month. Good production practise (GPP) has been applied for and is expected in mid year 2009. Current production from all zones at Willesden Green is 1,310 boe/d.

Sproule evaluated our proved reserves in the Willesden Green area and assigned 6 bcf of natural gas and 884 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 3 bcf of natural gas and 408 Mbbls of crude oil and NGLs.

Lookout Butte, Alberta

The Lookout Butte property is located approximately 90 kilometres southwest of Lethbridge, Alberta. Production occurs primarily from the Mississippian Rundle Formation where natural gas has been trapped in a foothills overthrust structure in front of Waterton Park. We have a 100% working interest in the Rundle gas production. Production began in 1963 and production decline is low at approximately 12% per year. A well drilled in 2004 in the southern portion of the pool when shut in exhibits significant pressure recharge from undrained reserves beneath adjacent Waterton and Glacier National parks. An additional location targeting the Rundle carbonates is being considered to assist in accessing these undrained reserves for possible drilling in 2010. The property includes a 100% operated working interest plant and associated gas gathering system which dehydrates the gas before final processing at Shell’s Waterton gas plant. The Waterton gas plant has been down for significant overhaul and reconfiguration of it’s sour operating trains since the third quarter of 2008 and is not expected to be back up operating until mid second quarter 2009. Our production from this field of approximately 1,150 boe/d has been completely shut in during the Waterton plant overhaul.

Sproule evaluated our proved reserves at Lookout Butte and assigned 29 bcf of natural gas and 1,493 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 11 bcf of natural gas and 583 Mbbls of crude oil and NGLs.

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Sunset/Valleyview, Alberta

This area is located approximately 100 kilometres east of the City of Grande Prairie, just north of the town of Valleyview. Currently production from the Sunset/Valleyview area is approximately 1,066 boe/d.

SUNSET “A” – Production is from the Triassic Montney Formation, which in this area is a conventional sandstone reservoir (unlike the tight siltstone resource reservoir at Glacier) with an active water leg that provides partial pressure support. We have a 70% working interest and operate the Sunset Triassic “A” Unit. Production from the unit is predominantly oil (32^o API). The unit has a forty year production history with a very stable performance and very low decline, indicating that there is a lot more oil to be recovered. Advantage commenced infill development of the pool in 2005 where two wells were drilled to evaluate the viability of infill drilling. These wells came on-stream at an average rate of 75 bbls/d per well, similar to that of the original wells. An additional 19 oil wells and an injector were added in 2006 and 2007. No new wells were drilled in 2008. Significant upgrading to oil production and handling facilities and gathering systems as well as water injection capacity has been ongoing from 2006 and continuing into 2009 to handle increased oil production and provide additional water injection for pressure maintenance. Three wells have been budgeted for drilling in 2009.

SUNSET “B” – Production from this Montney reservoir is predominantly natural gas although there is a thin oil (32^o API) column. We have a 100% interest in this pool. We own 100% of a sour gas processing plant and gathering system with throughput capacity of 12 MMcf/d. Associated gas from Sunset “A” and from Valleyview is gathered and streams through this facility. No wells were drilled in 2008 at Sunset ”B”.

VALLEYVIEW – This Montney gas pool is connected to the Sunset “B” gas processing plant by a twelve kilometre pipeline. We have a 93% average working interest in the pool. There was no new drilling in this pool in 2008.

For the three properties, Sunset “A”, Sunset “B” and Valleyview, the Sproule Report assigns 11 bcf of proven natural gas reserves and 1,903 Mbbls of proven crude oil and NGL reserves. In addition, 18 bcf of probable natural gas reserves and 2,703 Mbbls of probable crude oil and NGL reserves have been assigned to these properties.

Zama Lake (Sousa), Alberta

The Zama Lake property lies 150 kilometres south/southeast of the Northwest Territories/British Columbia/Alberta border adjacent to the Hay Zama Lake Complex. Productive zones on this property are primarily oil and gas from the Devonian Keg River, Sulphur Point and Slave Point formations as well as gas in the shallow Cretaceous Bluesky formation. Regionally, Keg River oil wells are characterized by prolific carbonate reefs. Bluesky sandstone reservoirs tend to provide lower deliverability, but longer-life sweet-natural-gas production. In February 2008 we drilled and completed two Keg River reefs as well as two shallow Bluesky. Neither of the Keg River wells is tied in; however both Bluesky wells are on production. We own and operate a sour oil battery, complete with treaters, tanks, oil-pumping station and solution gas compression. The area also has an existing gas-gathering system comprised of three owned and operated compressors complete with a small refrigeration package, dehydration, and sales point. Additional capacity is available for further development of our lands. Production from the Zama Lake/Sousa property is currently 1,040 boe/d.

The Sproule Report assigns 6 bcf of proven natural gas reserves and 549 Mbbls of proven NGL reserves to this property. In addition, 1 bcf of probable natural gas reserves and 184 Mbbls of probable NGL reserves have been assigned to this property.

Westerose, Alberta

The Westerose property is approximately 60 kilometres southwest of Edmonton, Alberta. Westerose is an oil and gas property with production from various Cretaceous reservoirs but produces principally from several pools associated with the erosional subcrop edge of the Mississippian Banff Formation. Current production from all zones at the greater Westerose area, including the Banff “C” Oil Unit is 1,030 boe/d.

The primary pool is the Banff “C” Oil Unit in which we hold a 52% interest and operate. The reservoir in the Banff Formation is a dolomitized carbonate that is conducive to secondary recovery through waterflooding. The

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reservoir is currently under active waterflood pressure maintenance since 2003 and one new injection well was added to the injection scheme in 2007 along with two new additional oil producers. We also operate five compressor stations and 80 kilometres of pipeline gathering facilities that are connected to the Rimbey gas plant. One gas well was drilled in 2008 which was completed in the Cretaceous Glauconite interval and was tied in. No additional wells are planned in 2009.

Sproule evaluated our proved reserves and assigned 8 bcf of natural gas and 1,464 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 3 bcf of natural gas and 1,106 Mbbls of crude oil and NGLs.

Rainbow, Alberta

The Rainbow property lies 175 kilometres south/southeast of the Northwest Territories/British Columbia/Alberta border in northwest Alberta. The major focus of production on this property is the Cretaceous Bluesky formation, a shallow sandstone reservoir that covers an extensive area and offers low-risk development. No new wells were drilled in the Bluesky in 2008 and we are planning to optimize facilities and review opportunities for improving operations prior to commencing a new round of drilling, possibly in 2010. Upwards of 50 infill and/or step out locations remain available for development on this property. Shallow natural gas production at Black is compressed and dehydrated in an owned and operated facility before it is further compressed and processed by a third-party processor in the area. Current production from the Rainbow property is 983 boe/d.

The Sproule Report assigns 13 bcf of proven natural gas reserves and 576 Mbbls of proven NGL reserves to this property. In addition, 3 bcf of probable natural gas reserves and 619 Mbbls of probable NGL reserves have been assigned to this property.

Fontas, Alberta

The Fontas property is situated about 80 kilometres south of the Rainbow Zama oilfields and about 20 kilometres east of the British Columbia/Alberta border. Fontas is a natural gas property which produces primarily from Mississippian aged reservoirs in the Debolt, Shunda and Elkton Formations. Gas is trapped as these reservoirs are truncated beneath Cretaceous strata and is also trapped in Cretaceous channels which down cut into the older Mississippian rock. We operate this winter only access property at a 65% working interest. We operate six strategically located gas processing/compression facilities and over 200 kilometres of gas gathering pipelines. A winter road is built annually into the property for well servicing and replenishment of perishables, but no drilling program was undertaken in 2008 or 2009. Production from the Fontas property is currently 923 boe/d.

The Sproule Report assigns 11 bcf of proven natural gas reserves to this property. In addition, 5 bcf of probable natural gas reserves have been assigned to this property.

Stoddart (North Pine), British Columbia

The Stoddart/North Pine area lies just 8 kilometres west of the Town of Fort St. John in northeast British Columbia. This area is within the agricultural area and is accessible year round. The property produces from multiple horizons, predominantly natural gas from the Permian Belloy Formation and oil from the Triassic, Charlie Lake Formation. Historically, production from this area has very low decline, is low operating cost and requires minimal capital expenditures. Current production from the Stoddart area is 526 boe/d.

We own an interest in 30 producing wells (22 net) in the area. We operate approximately 80% of the natural gas production and have a 40% working interest in the North Pine Charlie Lake oil pool. Recently this area of British Columbia has become the focus of exploration and development interest for the Triassic Montney tight gas play which is being explored on adjacent lands and developed further along trend. Advantage is evaluating the Montney gas resource potential on our lands which include 16,800 gross (11,800 net) acres of undeveloped land with rights to this interval and we are planning for possible future drilling locations.

Sproule evaluated our proved reserves in the area and assigned 11 bcf of natural gas and 690 Mbbls of crude oil and NGLs. In addition, 3 bcf of probable natural gas reserves and 158 Mbbls of probable crude oil and NGL reserves have been assigned to this property.

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Heavy Oil Properties (Western Saskatchewan – Lloydminster area)

The east Lloydminster (Lashburn and West Hazel) and Eyehill properties lie on the Saskatchewan side of the Saskatchewan/Alberta border in the heart of the Lloydminster heavy oil producing area. These properties produce primarily from the Cretaceous Sparky and Waseca Formations and also from the Rex, Cummings and Dina Formations. Crude gravities are all less than 19° API but are conventionally produced with some pools under water flood pressure maintenance schemes. Two wells were drilled and completed on the West Hazel property during the first quarter 2009 and encountered thick oil bearing channel sands in the Waseca formation. These wells were drilled to relieve land expiry and offset royalty compensation issues. Both wells are currently on production at about 50 bbl/d each. Currently production from all these heavy oil properties is 468 boe/d.

Sproule evaluated our proved reserves in the Heavy Oil Properties of western Saskatchewan and assigned 947 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 2,730 Mbbls of crude oil and NGLs.

Brazeau River, Alberta

The Brazeau River property is located approximately 50 kilometres west of the town of Drayton Valley. The property produces sour light oil and natural gas primarily from Devonian aged Nisku pinnacle reefs. The majority of the production is from a non-operated 50% working interest in the Nisku C, D and E pools and a 17% working interest in the Nisku A unit. Major facility interests include a 25.7% working interest in the West Pembina Sour Gas Plant and a 31.6% working interest in the Brazeau River Gas Plant.

In 2008 we completed and tied in one existing well in the south portion of this area in the shallower Cretaceous Belly River Formation. Four sections of land were acquired at crown landsales and a second follow up well has been drilled and placed on production. Production from these wells is 1.2 MMcf/d. Additional locations have been identified but none are budgeted in 2009.

Current production is 410 boe/d comprised of 210 boe/d from the Nisku pinnacles and 200 boe/d from the Belly River wells.

Sproule evaluated our proved reserves in the Brazeau River area and assigned 5 bcf of natural gas and 492 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 3 bcf of natural gas and 283 Mbbls of crude oil and NGLs.

Northville, Alberta

This area is located 110 kilometres west of the City of Edmonton. Oil and gas production occurs from a series of sandstone reservoirs within the Lower Mannville Formation, primarily the Glauconite. In 2009 Advantage drilled 3 gross (1.6 net) 2,100 meter deep wells. The 3 wells drilled at Northville are on production at 760 mcf/d average per well. Up to 6 additional locations remain available for drilling as economic conditions allow. Currently there are no wells budgeted for 2009. Current production from this property is 282 boe/d.

Sproule evaluated our proved reserves in the Northville area and assigned 3.4 bcf of natural gas and 151 Mbbls of crude oil and NGLs. Probable reserves in this area were evaluated by Sproule at 9.5 bcf of natural gas and 357 Mbbls of crude oil and NGLs.

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Oil and Gas Wells

The following table sets forth the number and status of wells as at December 31, 2008 in which we have a working interest.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	1,005.0	602.6	501.0	270.0	2,160.0	1,588.6	569.0	284.7
British Columbia	8.0	6.4	14.0	8.3	151.0	106.0	74.0	52.2
Saskatchewan	465.0	338.3	162.0	112.2	1.0	1.0	8.0	0.1
Manitoba	85.0	5.1	—	—	—	—	1.0	0.4
Total	1,563.0	952.4	677.0	390.7	2,312.0	1,695.6	652.0	337.4

Note:

(1) Excluding minor interest in the following units (less than 5% working interest): Steelman Unit No. 3, Pine Creek Second White Specks Pool, Carrot Creek Cardium K Unit No. 1, Delburne Gas Unit, Nevis Unit No. 1, Bonnie Glen D-3A Gas Cap Unit, Bellis Gas Unit No. 2, Turner Valley Unit No. 5, Sunchild Gas Unit No. 1, North Pembina Cardium Unit, Kakwa Cardium A Unit, Bonanza Boundary A Pool Unit No. 1, and Boundary Lake Units No. 1 and No. 2. Injection Wells are categorized as Non-Producing Oil Wells.

Properties with no Attributed Reserves

The following table sets out our developed and undeveloped land holdings as at December 31, 2008.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Alberta	1,236,336	624,329	710,804	366,775	1,947,140	991,104
British Columbia	163,315	78,114	104,586	64,409	267,901	142,523
Saskatchewan	53,680	36,372	152,268	116,728	205,948	153,100
Total	1,453,331	738,815	967,658	547,912	2,420,989	1,286,727

In the year ended December 31, 2008, rights to explore, develop and exploit 161,095 net acres of undeveloped land expired. We expect that rights to explore, develop and exploit 185,500 net acres of our undeveloped land holdings will expire by December 31, 2009. The land expirations do not consider our 2009 exploitation and development program that may result in extending or eliminating such potential expirations. We closely monitor land expirations as compared to our development program with the strategy of minimizing undeveloped land expirations relating to significant identified opportunities.

Forward Contracts

Our operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely in recent years. Such prices are primarily determined by economic, and in the case of oil prices, political factors. Supply and demand factors, as well as weather, general economic conditions, and conditions in other oil and natural gas regions of the world also impact prices. Any upward or downward movement in oil and natural gas prices could have an effect on our financial condition, thus impacting the distributions made to Unitholders.

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We have implemented a hedging policy to use costless collars and fixed price swaps to hedge up to 60% of our gross production for a maximum period of 2 years. These hedging activities could expose us to losses or gains. To the extent that we engage in risk management activities related to commodity prices, we will be subject to credit risk associated with the parties with which we contract. This credit risk will be mitigated by entering into contracts with only stable and creditworthy parties and through the frequent review of our exposure to these entities.

Overall, approximately 56% of our gas is now hedged for the 2009 calendar year at a floor of $8.09/mcf. For the first quarter of 2009, we have secured approximately 62% of our net gas production at a floor of $7.87/mcf. For the first quarter of 2010, approximately 62% of our net gas production is hedged at a floor of $7.64/mcf. We have also hedged approximately 46% of our 2009 net crude production at an average floor price of Cdn$69.38/bbl and an average ceiling price of Cdn$74.92/bbl. For the first quarter of 2010, we have secured approximately 26% of our net oil production at a floor of Cdn$62.80/bbl.

Advantage has the following derivatives in place:

Description of Derivative	Term	Volume	Average Price
Natural gas - AECO
Fixed price	April 2008 to March 2009	14,217 mcf/d	Cdn$7.10/mcf
Fixed price	April 2008 to March 2009	14,217 mcf/d	Cdn$7.06/mcf
Fixed price	November 2008 to March 2009	14,217 mcf/d	Cdn$7.77/mcf
Fixed price	November 2008 to March 2009	4,739 mcf/d	Cdn$8.10/mcf
Fixed price	November 2008 to March 2009	14,217 mcf/d	Cdn$9.45/mcf
Fixed price	April 2009 to December 2009	9,478 mcf/d	Cdn$8.66/mcf
Fixed price	April 2009 to December 2009	9,478 mcf/d	Cdn$8.67/mcf
Fixed price	April 2009 to December 2009	9,478 mcf/d	Cdn$8.94/mcf
Fixed price	April 2009 to March 2010	14,217 mcf/d	Cdn$7.59/mcf
Fixed price	April 2009 to March 2010	14,217 mcf/d	Cdn$7.56/mcf
Fixed price	January 2010 to June 2010	14,217 mcf/d	Cdn$8.23/mcf
Fixed price	January 2010 to December 2010	18,956 mcf/d	Cdn$7.29/mcf
Fixed price	April 2010 to January 2011	18,956 mcf/d	Cdn$7.25/mcf
Crude oil – WTI
Fixed price	February 2008 to January 2009	2,000 bbls/d	Cdn$90.93/bbl
Collar	February 2008 to January 2009	2,000 bbls/d	Sold put Cdn$70.00/bbl
			Purchase call Cdn$105.00/bbl
			Cost Cdn$1.52/bbl
Fixed price	April 2008 to March 2009	2,500 bbls/d	Cdn$97.15/bbl
Collar	April 2009 to December 2009	2,000 bbls/d	Bought put Cdn$62.00/bbl
			Sold call Cdn$76.00/bbl
Fixed price	April 2009 to March 2010	2,000 bbls/d	Cdn$62.80/bbl
Fixed price	April 2010 to January 2011	2,000 bbls/d	Cdn$69.50/bbl

Additional Information Concerning Abandonment and Reclamation Costs

We estimate the costs to abandon and reclaim all our shut-in and producing wells, facilities, gas plants, pipelines, batteries and satellites. No estimate of salvage value is netted against the estimated cost. Our model for estimating the amount and timing of future abandonment and reclamation expenditures was done on an operating area level. Estimated expenditures for each operating area are initially based upon Sproule’s methodology, which details the cost of abandonment for the major properties that we hold. Our initial estimated expenditures are then further adjusted for non-producing wells, pipelines and facilities, and surface reclamation costs. Each property was assigned an average cost per well to abandon and reclaim the wells in an area and abandonment and reclamation costs have been estimated over a 50 year period.

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We estimate that we will incur reclamation and abandonment costs on 5,452(gross) producing and non-producing wells. Costs to abandon and reclaim the producing wells, discounted at 10%, totals $20 million ($106million undiscounted) and are included in the estimate of future net revenue. The additional liability associated with non-producing wells, pipelines and facilities, and surface reclamation costs, discounted at 10%, was estimated to be $22 million ($114million undiscounted), and was not deducted in estimating future net revenue. Facility reclamation costs are generally scheduled to be incurred following the end of the reserve life of our associated reserves under the assumption that decommissioning of plant/facilities are mobile assets with a long useful life.

Abandonment and reclamation costs undiscounted and included in the estimate of future net revenue for the next three years are $0.8 million in 2009, $0.9 million in 2010 and $1.0million in 2011.

Tax Horizon

In 2008, we did not pay any income related taxes.

In our structure, the operating company utilizes available tax pools to significantly reduce taxable income and makes other required payments to the Trust transferring both income and associated tax liability to the Unitholders. Therefore, it is expected, based on current legislation that no cash income taxes are to be paid by the operating company prior to 2011 and it is our intent to continue with the current arrangement. For the 2008 distributions, 100% were taxable to Canadian and U.S. Unitholders.

The Trust does not expect to pay income taxes until the earlier of January 1, 2011 or if and when it ceases to be a trust. New legislation passed in June 2007 will impose a tax on distributions from entities, such as the Trust, beginning generally on January 1, 2011. Commencing in January 2011 (provided that the Trust experiences only “normal growth” and no “undue expansion” before then) the Trust will be liable for tax at the federal general corporate income tax rate (which is anticipated to be 16.5% in 2011) plus the provincial SIFT tax rate on all income payable to Unitholders, which the Trust will not be able to deduct in computing its taxable income. See “Risk Factors– Changes in Legislation– SIFT Tax”.

Capital Expenditures

The following tables summarize capital expenditures (including capitalized general and administrative expenses) relat ed to our activities for the year ended December 31, 2008:

Capital Expenditures ($ thousands)	2008
Land and seismic	$	22,532
Drilling, completions and workovers		140,019
Well equipping and facilities		92,016
Other		1,024
		255,591
Property acquisitions
Proved properties		7,621
Unproved properties		—
Property dispositions		(941	)
Total capital expenditures	$	262,271

The total capital expenditures for the year ended December 31, 2008 include approximately $80.6 million related to exploration activities.

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Exploration and Development Activities

The following table sets forth the gross and net wells in which we participated during the year ended December 31, 2008:

	Exploratory		Development		Total
	Gross	Net	Gross	Net	Gross	Net
Oil wells	2	2.0	24	20.0	26	22.0
Gas wells	20	17.5	76	45.1	96	62.6
Dry holes	1	0.5	1	1.0	2	1.5
Total	23	20.0	101	66.1	124	86.1

Subject to, among other things, the availability of drilling rigs and weather that permits access to drill sites, in 2009, we plan to drill, complete and tie-in 35 net wells.

We estimate capital expenditures of between $100 million and $135 million in 2009 to execute our capital programs. The primary components of our programs are described under the heading “Other Oil and Gas information – Oil and Natural Gas Properties”.

Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2009 reflected in the estimate of future net revenue disclosed in the tables contained under “Disclosure of Reserves Data”.

	Light and Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total
	(bbl/d)		(bbl/d)		(Mcf/d)		(bbl/d)		(Boe/d)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Proved Producing	7,146	5,958	993	895	112,142	91,200	2,137	1,565	28,967	23,618
Proved Developed Non-Producing	60	60	28	23	10,375	7,477	84	59	1,900	1,388
Proved Undeveloped	312	218	58	48	3,808	2,874	45	37	1,050	783
Total Proved	7,518	6,236	1,079	966	126,326	101,551	2,266	1,661	31,917	25,788
Total Probable	706	535	138	111	14,921	10,099	210	150	3,541	2,479
Total Proved Plus Probable	8,224	6,771	1,216	1,077	141,247	111,649	2,476	1,811	35,458	28,268

Production History

The following tables summarize certain information in respect of production, prices received, royalties paid, operating expenses and resulting netback for the periods indicated below:

	Quarter Ended 2008				Year Ended
	Mar. 31	June 30	Sept. 30	Dec. 31	Dec. 31, 2008
Average Daily Production(1)
Crude Oil (bbl/d)	9,851	9,311	9,566	9,443	9,543
Gas (MMcf/d)	125,113	123,104	122,627	120,694	122,878
NGLs (bbl/d)	2,430	2,187	2,414	1,970	2,250
Combined (boe/d)	33,133	32,015	32,418	31,529	32,273
Average Net Production Prices Received(2)
Crude Oil ($/bbl)	88.15	113.71	112.35	57.46	92.81
Gas ($/Mcf)	7.90	10.33	8.65	7.15	8.51

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	Quarter Ended 2008							Year Ended
	Mar. 31		June 30		Sept. 30		Dec. 31	Dec. 31, 2008
NGLs ($/bbl)	77.25		95.02		90.60		35.38	75.93
Combined ($/boe)	61.72		79.27		72.63		46.79	65.14
Gain/(Loss) on Derivatives
Crude Oil ($/bbl)	(1.46	)	(10.88	)	(9.95	)	9.70	(3.10	)
Gas ($/Mcf)	0.33		(1.15	)	(1.10	)	0.46	(0.37	)
Combined ($/boe)	0.80		(7.58	)	(7.12	)	4.64	(2.32	)
Royalties Paid
Crude Oil ($/bbl)	14.53		19.90		19.67		9.32	15.83
Gas ($/Mcf)	1.46		2.15		1.80		1.18	1.65
NGLs ($/bbl)	19.31		26.13		23.90		12.07	20.60
Combined ($/boe)	11.24		15.85		14.40		8.05	12.39
Operating Expenses(3)(4)
Crude oil ($/bbl)	17.27		18.31		18.59		18.43	18.14
Natural gas ($/Mcf)	1.98		1.97		1.97		2.17	2.02
NGLs ($/bbl)	10.30		11.65		11.66		14.42	11.90
Combined ($/boe)	13.36		13.70		13.82		14.71	13.89
Netback Received(5)
Crude Oil ($/bbl)	54.89		64.62		64.14		39.41	55.74
Gas ($/Mcf)	4.79		5.06		3.78		4.26	4.47
NGLs ($/bbl)	47.64		57.24		55.04		8.89	43.43
Combined ($/boe)	37.92		42.14		37.29		28.67	36.54

Notes:

(1)	Before deduction of royalties.
(2)	Production prices are net of costs to transport the product to market.
(3)	This figure includes all field operating expenses.
(4)	We do not record operating expenses on a commodity basis. Information in respect of operating expenses for crude oil and NGLs ($/bbl) and natural gas ($/Mcf) has been determined by allocating expenses on an area by area basis based upon the relative volume of production of crude oil and NGLs and natural gas in those areas.
(5)	Information in respect of netbacks received for crude oil & NGLs ($/bbl) and natural gas ($/Mcf) is calculated using operating expense figures for crude oil and NGLs ($/bbl) and natural gas ($/Mcf), which figures have been estimated. See note (4) above.

The following table indicates our approximate average daily production from our important fields for the quarter ended December 31, 2008:

	Natural Gas	Crude Oil & NGLs	Total
Properties	(Mcf/d)	(bbls/d)	(boe/d)
Nevis	19,186	2,342	5,539
Martin Creek	17,957	314	3,307
Saskatchewan	312	2,704	2,757
Willesden Green/Westerose	7,979	1,056	2,386
Medicine Hat	8,724	—	1,454

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	Natural Gas	Crude Oil & NGLs	Total
Properties	(Mcf/d)	(bbls/d)	(boe/d)
Chip Lake	4,631	543	1,315
Peace River Arch	5,477	246	1,159
Brazeau/Ferrier	5,144	298	1,155
Sunset	3,171	597	1,125
Boundary Lake/Cecil	3,159	583	1,109
Major Properties	75,740	8,683	21,306
Other	44,954	2,730	10,223
Total	120,694	11,413	31,529

Future Commitments

We have committed to certain payments over the next five years, in addition to regular payments under our credit facilities, as follows:

($ millions)	2009		2010		2011		2012
Building leases	$	3.8	$	3.9	$	1.5	$	1.1
Capital leases		2.1		2.2		1.9		—
Pipeline/transportation		3.2		1.4		0.3		—
Convertible debentures(1)		87.0		69.9		62.3		—

Note:

(1) As at December 31, 2008, Advantage had $219.2 million Debentures outstanding. Each series of Debentures are convertible to Trust Units based on an established conversion price. All remaining obligations related to Debentures can be settled through the payment of cash or issuance of Trust Units at Advantage’s option.

Definitions and Other Notes

1. Columns set forth above may not add due to rounding.

2. The crude oil, natural gas liquids and natural gas reserve estimates presented in the Sproule Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.  

“COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;

“Development costs” means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly;

(b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

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(c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

(d) provide improved recovery systems.

“Exploration costs” means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;

(b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

(c) dry hole contributions and bottom hole contributions;

(d) costs of drilling and equipping exploratory wells; and

(e) costs of drilling exploratory type stratigraphic test wells.

“Gross” means:

(a) in relation to our interest in production and reserves, our “Trust gross reserves”, which are our interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Trust;

(b) in relation to wells, the total number of wells in which we have an interest; and

(c) in relation to properties, the total area of properties in which we have an interest.

“Net” means:

(a) in relation to our interest in production and reserves, our interest (operating and non-operating) share after deduction of royalties obligations, plus our royalty interest in production or reserves;

(b) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

(c) in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest owned by us.

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:

• analysis of drilling, geological, geophysical and engineering data;

• the use of established technology; and

• specified economic conditions.

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Reserves are classified according to the degree of certainty associated with the estimates.

(a) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

(a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainly.

(ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a) at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

(b) at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

Marketing

Our crude oil and natural gas production is primarily sold through marketing companies at current market prices. Crude oil contracts are generally for less than a year and are cancellable on 30 days notice and natural gas contracts are generally for one year and are cancellable on 60 days notice. Approximately 5% of our natural gas production is sold to aggregators who accumulate production from various producers and market the gas on behalf of the group. Such contracts are reserve specific and continue for the life of production from the specified reserves.

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Cyclical and Seasonal Impact of Industry

Our operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse effect on our financial condition. We mitigate such price risk through closely monitoring the various commodity markets and establishing hedging programs, as deemed necessary, to provide stability to Unitholders’ distributions and lock-in high netbacks on production volumes. See “Other Oil and Gas Information – Forward Contracts” for our current hedging program.

Renegotiation or Termination of Contracts

As at the date hereof, we do not anticipate that any aspect of our business will be materially affected in the remainder of 2009 by the renegotiation or termination of contracts or subcontracts.

Environmental Considerations

We are pro-active in our approach to environmental concerns. Procedures are in place to ensure that the utmost care is taken in the day-to-day management of our oil and gas properties. All government regulations and procedures are followed in strict adherence to the law. We believe in well abandonment and site restoration in a timely manner to ensure minimal damage to the environment and lower overall costs to us.

Health, Safety and Environmental

AOG is committed to a comprehensive and effective health, safety and environmental program that meets or exceeds regulatory and corporate requirements.

Management, employees and all contractors are responsible and accountable for the overall health, safety and environmental program. AOG will operate in compliance with all applicable regulations and will ensure all staff and contractors employ sound practices to protect the environment and to ensure employee and public health and safety.

We will maintain a safe and environmentally responsible work place and provide training, equipment and procedures to all individuals in adhering to our policies. We will also solicit and take into consideration input from our neighbours, communities and other stakeholders in regard to protecting people and the environment.

AOG participates in the Environment, Health and Safety Stewardship Program developed by the Canadian Association of Petroleum Producers. Participation requires commitment to continuous improvement in the environment, health and safety management practices including sound planning and implementation, open communication and measured performance against our peers.

Competitive Conditions

We are a member of the petroleum industry, which is highly competitive at all levels. We compete with other companies for all of our business inputs, including exploitation and development prospects, access to commodity markets, acquisition opportunities, available capital and staffing.

We strive to be competitive by maintaining a strong financial condition and by utilizing current technologies to enhance exploitation, development and operational activities.

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Human Resources

As at December 31, 2008, we employed 176 full-time employees, 136 of which are located in the head office and 40 of which are located in the field. We also employed 32 consultants in the head office.

ADDITIONAL INFORMATION RESPECTING ADVANTAGE ENERGY INCOME FUND

Trust Units

An unlimited number of Trust Units may be created and issued pursuant to the Trust Indenture. As at December 31, 2008, 142,824,854 Trust Units were issued and outstanding. Each Trust Unit represents an equal fractional undivided beneficial interest in any distributions from, and in any net assets of, the Trust in the event of termination or winding up of the Trust. The beneficial interests in the Trust are divided into three classes, as follows: (i) “ordinary trust units”, which are entitled to the rights, subject to limitations, restrictions and conditions set out in the Trust Indenture, as summarized herein; (ii) ”special voting units”, which shall be issued to a trustee and which are entitled to such number of votes at meetings of Unitholders as is equal to the number of Trust Units reserved for issuance that such special voting units represent, such number of votes and any other rights or limitations to be prescribed by the AOG Board of Directors; and (iii) “special trust units”, which shall be entitled to the rights and subject to the limitations, restrictions and conditions set out in the Trust Indenture, as summarized herein. As at the date hereof there are no special voting units and no special trust units outstanding. The special voting unit gives AOG the flexibility to acquire the securities of another issuer in consideration for securities which are ultimately exchangeable for Trust Units. All Trust Units (including ordinary trust units and special trust units) are of the same class with equal rights and privileges. Each Trust Unit is transferable, entitles the holder thereof to participate equally in distributions, including the distributions of net income and net realized capital gains of the Trust, and distributions on liquidation, is fully paid and non assessable. Each special trust unit entitles the holder or holders thereof to one-half of one vote at any meeting of the Unitholders and each ordinary trust unit entitles the holder or holders thereof to one vote at any meeting of the Unitholders.

The Trust Units do not represent a traditional investment and should not be viewed by investors as “shares” in either AOG or the Trust. Corporate law does not govern the Trust and the rights of Unitholders. As holders of Trust Units in the Trust, the Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. The rights of Unitholders are specifically set forth in the Trust Indenture. In addition, trusts are not defined as recognized entities within the definitions of legislation such as the Bankruptcy and Insolvency Act (Canada) and the Companies’ Creditors Arrangement Act (Canada). As a result, in the event of an insolvency or restructuring, a Unitholder’s position as such may be quite different than that of a shareholder of a corporation.

The price per Trust Unit is a function of anticipated distributable income from AOG and the ability of the AOG Board of Directors to effect long term growth in the value of the Trust. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates, commodity prices and our ability to acquire additional assets. Changes in market conditions may adversely affect the trading price of the Trust Units.

A return on an investment in the Trust is not comparable to the return on an investment in a fixed-income security. The recovery of an initial investment in the Trust is at risk, and the anticipated return on such investment is based on many performance assumptions. The actual amount distributed will depend on numerous factors including: the financial performance of AOG, debt obligations, working capital requirements and future capital requirements. In addition, the market value of the Trust Units may decline if the Trust’s cash distributions decline in the future, and that market value decline may be material. On March 18, 2009 we announced that monthly distributions have been suspended with the final cash distribution paid to Unitholders on March 16, 2009 to Unitholders of record as of February 27, 2009. See “General Development of the Business - Recent Developments – Suspension of Distributions”.

It is important for an investor to consider the particular risk factors that may affect the industry in which it is investing, and therefore the stability of the distributions that it receives. See “Risk Factors”.

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The after-tax return from an investment in Trust Units to Unitholders subject to Canadian income tax can be made up of both a return on capital and a return of capital. That composition may change over time, thus affecting an investor’s after-tax return. Returns on capital will generally continue to be taxed as ordinary income in the hands of a Unitholder until January 2011 (provided we do not exceed “normal growth” or experience “undue expansion”), and will be treated as dividends after such time. Returns of capital are generally tax-deferred (and reduce the Unitholder’s cost base in the Trust Unit for tax purposes). Legislation affecting the tax treatment of an investment in Trust Units can change at any time. See “Risk Factors”.

Trust Unitholder Limited Liability

The Trust Indenture provides that no Unitholder will be subject to any liability in connection with the Trust or its obligations and affairs and, in the event that a court determines our Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of the Unitholder’s share of our assets. Pursuant to the Trust Indenture, we will indemnify and hold harmless each Unitholder from any cost, damages, liabilities, expenses, charges and losses suffered by a Unitholder resulting from or arising out of such Unitholder not having such limited liability.

The Trust Indenture provides that all written instruments signed by or on behalf of us must contain a provision to the effect that such obligation will not be binding upon our Unitholders personally. Notwithstanding the terms of the Trust Indenture, Unitholders may not be protected from our liabilities to the same extent as a shareholder is protected from the liabilities of a corporation. Personal liability may also arise in respect of claims against the Trust (to the extent that claims are not satisfied by the Trust Fund) that do not arise under contracts, including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability to Unitholders of this nature arising is considered unlikely in view of the fact that our sole business activity is to hold securities, and all of the business operations currently carried on by AOG will be carried on by a corporate entity, directly or indirectly.

Our business and that of our wholly-owned subsidiary, AOG, is conducted, upon the advice of counsel, in such a way and in such jurisdictions as to avoid as far as possible any material risk of liability to our Unitholders for claims against us, including obtaining appropriate insurance, where available, for the operations of AOG and having written agreements, signed by or on our behalf, include a provision that such obligations are not binding upon our Unitholders personally.

Issuance of Trust Units

The Trust Indenture provides that Trust Units or rights to acquire Trust Units may be issued at the times, to the persons, for the consideration, and on the terms and conditions that the AOG Board of Directors determines. The Trust Indenture also provides that immediately after any pro rata distribution of Trust Units to all Unitholders in satisfaction of any non-cash distribution, the number of outstanding Trust Units will be consolidated such that each Unitholder will hold, after the consolidation, the same number of Trust Units as the Unitholder held before the non-cash distribution. In this case, each certificate representing a number of Trust Units prior to the non-cash distribution is deemed to represent the same number of Trust Units after the non-cash distribution and the consolidation.

Cash Distributions

The amount of cash to be distributed annually per Trust Unit shall be equal to a pro rata share of interest on the Notes, royalty income from the Royalty, dividends on or in respect of shares of AOG received by us and income from the Permitted Investments; less: (i) our administrative expenses and other obligations; and (ii) amounts which may be paid by us in connection with any cash redemptions of Trust Units. AOG may apply some or all of its cash flow to capital expenditures to develop the Oil and Natural Gas Properties of AOG or to acquire additional Oil and Natural Gas Properties prior to making any distributions to us in the form of principal repayments on the Notes or dividends on the Common Shares, Non-Voting Shares or Preferred Shares. If, on any Distribution Record Date, the Trustee determines that we do not have cash in an amount sufficient to pay the full distribution to be made on such Distribution Record Date in cash or if any cash distribution should be contrary to any subordination agreement, the distribution payable to Unitholders on such Distribution Record Date may, at the option of the Trustee, include a distribution of additional Trust Units having an equal value to the cash shortfall. Trust Units will be issued pursuant to exemptions under applicable securities laws, discretionary exemptions granted by applicable securities regulatory authorities or a prospectus or similar filing.

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We derive interest income from our holdings of the Notes. It is expected that our income will generally be limited to: (i) the interest received on the principal amount of the Notes; (ii) royalty income received on the Royalty; and (iii) dividends (if any) received on shares of AOG. See “Additional Information Respecting Advantage Oil& Gas Ltd.– Notes”.

Cash distributions have been made monthly to the Unitholders of record on the last day of each month (unless such day is not a Business Day, in which case the date of record shall be the next following Business Day) and shall be payable on the 15th day of each month or, if such day is not a Business Day, the following Business Day or such other date as determined from time to time by the Trustee. On March 18, 2009 we announced that monthly distributions have been suspended with the final cash distribution paid to Unitholders on March 16, 2009 to Unitholders of record as of February 27, 2009. See “General Development of the Business - Recent Developments – Suspension of Distributions”.

Pursuant to the provisions of the Trust Indenture all income earned by the Trust in a fiscal year, not previously distributed in that fiscal year, must be distributed to Unitholders of record on December 31. This excess income, if any, will be allocated to Unitholders of record at December 31 but the right to receive this income, if the amount is not determined and declared payable at December 31, will trade with the Trust Units until determined and declared payable in accordance with the rules of the Toronto Stock Exchange. To the extent that a Unitholder trades Trust Units in this period they will be allocated such income but will dispose of their right to receive such distribution.

Redemption Right

Trust Units are redeemable at any time on demand by the holders thereof upon delivery to us of the certificate or certificates representing such Trust Units, accompanied by a duly completed and properly executed notice requesting redemption. Upon our receipt of the redemption request, all rights to and under the Trust Units tendered for redemption shall be surrendered and the holder thereof shall be entitled to receive a price per Trust Unit (the “Redemption Price”) equal to the lesser of: (i) 85% of the “market price” of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading-day period commencing immediately after the date on which the Trust Units are surrendered for redemption (the “Redemption Date”); and (ii) the “closing market price” on the principal market on which the Trust Units are quoted for trading on the Redemption Date.

For the purposes of this calculation, “market price” is an amount equal to the simple average of the closing price of the Trust Units for each of the trading days on which there was a closing price, provided that, if the applicable exchange or market does not provide a closing price but only provides the highest and lowest prices of the Trust Units traded on a particular day, the market price shall be an amount equal to the simple average of the highest and lowest prices for each of the trading days on which there was a trade, and provided further that if there was trading on the applicable exchange or market for fewer than five of the 10 trading days, the market price shall be the simple average of the following prices established for each of the 10 trading days: the average of the last bid and last ask prices for each day on which there was no trading; the closing price of the Trust Units for each day that there was trading if the exchange or market provides a closing price; and the average of the highest and lowest prices of the Trust Units for each day that there was trading, if the market provides only the highest and lowest prices of Trust Units traded on a particular day. The “closing market price” shall be: an amount equal to the closing price of the Trust Units if there was a trade on the date; an amount equal to the average of the highest and lowest prices of the Trust Units if there was trading and the exchange or other market provides only the highest and lowest prices of Trust Units traded on a particular day; and the average of the last bid and last ask prices if there was no trading on the date.

The aggregate Redemption Price payable by us in respect of any Trust Units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on or before the last day of the following month; provided that the entitlement of Unitholders to receive cash upon the redemption of their Trust Units is subject to the limitations that: (i) the total amount payable by us in respect of such Trust Units and all other Trust Units tendered for redemption in the same calendar month shall not exceed $100,000 (provided that the Trustee may, in its sole discretion, waive such limitation in respect of any calendar month); (ii) at the time such Trust Units are tendered for redemption the outstanding Trust Units shall be listed for trading on a stock exchange or traded or quoted on any other market which the Trustee considers, in its sole discretion, provides representative fair market value prices for the Trust Units; and (iii) the normal trading of Trust Units is not suspended or halted on any stock exchange on which the Trust Units are listed (or, if not listed on a stock exchange, on any market on which the Trust Units are quoted for trading) on the Redemption Date or for more than five trading days during the 10-day trading period commencing immediately after the Redemption Date.

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If a Unitholder is not entitled to receive cash upon the redemption of Trust Units as a result of the foregoing limitations, then the Redemption Price for such Trust Units shall be the Fair Market Value thereof (as defined in the Trust Indenture), as determined by the Trustee in the circumstances described in subparagraphs (ii) and (iii) above, and shall, subject to any applicable regulatory approvals, be paid and satisfied by way of distribution in specie of a pro rata number of Long Term Notes (in a minimum amount of $100.00 and integral multiples of $1.00), from time to time outstanding (i.e., in a principal amount equal to the Redemption Price). No fractional Long Term Notes will be distributed and where the number of Long Term Notes to be received by a Unitholder includes a fraction, such number shall be rounded to the next lowest whole number. We shall be entitled to all interest paid, or accrued and unpaid, on the Long Term Notes on or before the date of the distribution in specie. If we do not hold Long Term Notes having a sufficient principal amount outstanding to effect such payment, we will be entitled to create and, subject to any applicable regulatory approvals, issue in satisfaction of the Redemption Price our own debt securities (the “Redemption Notes”) having terms and conditions substantially the same as the Long Term Notes, and with recourse of the holder limited to our assets. Holders of such Long Term Notes and Redemption Notes will be required to acknowledge that they are subject to the subordination agreements described below under the heading “Additional Information Regarding Advantage Oil & Gas Ltd.– Notes”. Long Term Notes and Redemption Notes may not be qualified investments for trusts governed by registered retirement savings plans, registered retirement income funds and deferred profit sharing plans if the Trust ceases to qualify as a mutual fund trust.

It is anticipated that the redemption right will not be the primary mechanism for holders of Trust Units to dispose of their Trust Units. Long Term Notes or Redemption Notes which may be distributed in specie to Unitholders in connection with a redemption will not be listed on any stock exchange and no market is expected to develop in such Long Term Notes or Redemption Notes.

Meetings of Unitholders

The Trust Indenture provides that meetings of Unitholders must be called and held for, among other matters, the election or removal of the Trustee, the appointment or removal of our auditors, the approval of amendments to the Trust Indenture (except as described under “Additional Information Respecting Advantage Energy Income Fund– Amendments to the Trust Indenture”), the sale of our assets in their entirety or substantially in their entirety (other than as part of an internal reorganization), the termination of the Trust and the direction of the Trustee as to the selection of the directors of AOG. Meetings of Unitholders will be called and held annually for, among other things, the election of the Trustee, the appointment of our auditors, and the direction of the Trustee as to the selection of the directors of AOG. A resolution appointing or removing a Trustee, our auditors, or the direction of the Trustee as to the selection of the directors of AOG must be passed by a simple majority of the votes cast by Unitholders. The balance of the foregoing matters must be passed by at least 66-2/3% of the votes cast at a meeting of Unitholders called for such purpose.

A meeting of Unitholders may be convened at any time and for any purpose by the Trustee and must be convened if requisitioned by the holders of not less than 20% of the Trust Units then outstanding by a written requisition. A requisition must, among other things, state in reasonable detail the business proposed to be transacted at the meeting.

Unitholders may attend and vote at all meetings of Unitholders either in person or by proxy and a proxyholder need not be a Unitholder. Two persons present in person or represented by proxy and representing, in the aggregate, at least 10% of the votes attaching to all outstanding Trust Units shall constitute a quorum for the transaction of business at all such meetings.

The Trust Indenture contains provisions as to the notice required and other procedures with respect to the calling and holding of meetings of Unitholders. The next annual and special meeting of Unitholders is scheduled for June 29, 2009.

Information and Reports

We will furnish to Unitholders such financial statements (including quarterly and annual financial statements) and other reports as are, from time to time, required by applicable law, including prescribed forms needed for the completion of Unitholders’ tax returns under the Tax Act and equivalent provincial legislation.

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Prior to each meeting of Unitholders, the Trustee will provide the Unitholders (along with notice of such meeting) a proxy form and an information circular containing information similar to that required to be provided to shareholders of a Canadian public corporation.

The AOG Board of Directors will ensure that AOG provides us with proper disclosure as to its business and financial operations and sufficient information and materials on a timely basis to allow us to meet our public reporting requirements. With respect to material changes, the AOG Board of Directors will ensure that AOG provides timely disclosure to us as if AOG were a public corporation.

Takeover Bids

The Trust Indenture contains provisions to the effect that if a takeover bid is made for the Trust Units and not less than 90% of the Trust Units (other than Trust Units held at the date of the takeover bid by or on behalf of the offeror or associates or affiliates of the offeror) are taken up and paid for by the offeror, the offeror will be entitled to acquire the Trust Units held by Unitholders who did not accept the takeover bid on the terms offered by the offeror.

The Fund has also adopted a Rights Plan that, entitles the holder to purchase a Trust Unit from treasury at a specified exercise price in the event of an unsolicited take-over bid for the Fund. The Rights Plan is described above, under the heading “General Development of the Business”.

The Trustee

The Trust Indenture provides that the Trustee shall exercise its powers and carry out its functions thereunder as Trustee honestly, in good faith and in the best interests of the Trust and the Unitholders and, in connection therewith, shall exercise that degree of care, diligence and skill that a reasonably prudent trustee would exercise in comparable circumstances.

The initial term of the Trustee’s appointment was until the first annual meeting of Unitholders. The Trustee is reappointed or changed every year as may be determined by a majority of the votes cast at a meeting of our Unitholders. The Trustee may resign upon providing 60 days notice to us. The Trustee may also be removed by special resolution of our Unitholders. Such resignation or removal becomes effective upon the acceptance or appointment of a successor trustee.

Delegation of Authority, Administration and Trust Governance

AOG has generally been delegated our significant management decisions. In particular, pursuant to the Administration Agreement, the Trustee has delegated to AOG responsibility for the administration and management of all general and administrative affairs of Advantage, including, among other things:

• maintaining records and accounts;

• preparing all tax returns, filings and documents and monitor the tax status of the Trust and of the Trust Units;

• providing advice with respect to the Trust’s obligations as a reporting issuer and ensure compliance under applicable securities legislation;

• providing investor relations services to the Trust;

• calling and holding all meetings of the Unitholders;

• undertaking all matters relating to an offering including;

o compliance with all applicable laws;

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o all matters relating to the content of any offering documents, the accuracy of the disclosure and the certification thereof; and

o all matters concerning the entering into, terms of, and amendment from time to time of material contracts;

• retaining professional services and advisors;

• dealing with banks and other institutional lenders;

• taking all actions reasonably necessary in relation to the redemption of Trust Units;

• taking all actions reasonably necessary in relation to voting rights on any investments in the Trust Fund;

• taking all action reasonably necessary relating to the specific powers and authorities as set forth in the Trust Indenture;

• taking all actions reasonably necessary in relation to providing indemnities for the directors and officers of the Administrator and any affiliates of the Trust or the Administrator;

• providing or causing to be provided to the Trustee any services reasonably necessary for the Trustee to be able to consider any future acquisitions or divestitures by the Trustee of any portion of the Trust Fund;

• providing advice and, at the request and under the direction of the Trustee, direction to the transfer agent;

• determining and arranging for distributions to Unitholders;

• providing advice and assistance to the Trustee with respect to the performance of the obligations of the Trust and the enforcement of the rights of the Trust under all agreements entered into by the Trust;

• withholding the withholding taxes required and promptly remit such taxes to the appropriate taxing authority;

• providing such additional administrative and support services pertaining to the Trust, the Trust Fund and the Trust Units and matters incidental thereto as may be reasonably requested by the Trustee from time to time;

• reporting to Unitholders;

• providing management services, for the economic and efficient exploration, exploitation and development of assets of the Trust;

• recommending, carrying out and monitoring property acquisitions and dispositions and exploitation and development programs for the Trust; and

• doing all such things regarding the use of commodity price swaps, hedges or other such instruments or agreements on behalf of the Trust in respect of commodity prices or rates of exchange of currencies or interest rates, the purpose of which is to mitigate or eliminate exposure to the fluctuations and prices of commodities or rates of exchange of one currency for another or interest rates.

For more information as to the AOG Board of Directors, see “Additional Information Respecting Advantage Oil& Gas Ltd. – Management of AOG”.

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Liability of the Trustee

The Trustee, its directors, officers, employees, shareholders and agents shall not be liable to any Unitholder or any other person, in tort, contract or otherwise, in connection with any matter pertaining to the Trust or the Trust Fund, arising from the exercise by the Trustee of any powers, authorities or discretion conferred under the Trust Indenture, including, without limitation, any action taken or not taken in good faith in reliance upon any documents that are, prima facie, properly executed, any depreciation of, or loss to, the Trust Fund incurred by reason of the sale of any asset, any inaccuracy in any evaluation provided by AOG or any other appropriately qualified person, any reliance upon any such evaluation, any action or failure to act of the AOG, or any other person to whom the Trustee has, with the consent of AOG, delegated any of its duties hereunder, or any other action or failure to act (including failure to compel in any way any former trustee to redress any breach of trust or any failure by AOG to perform its duties under or delegated to it under the Trust Indenture or any material contract), unless such liabilities arise out of the gross negligence, wilful default or fraud of the Trustee or any of its directors, officers, employees, shareholders or agents. If the Trustee has retained an appropriate expert, adviser or legal counsel with respect to any matter connected with its duties under the Trust Indenture or any material contract, the Trustee may act or refuse to act based upon the advice of such expert, adviser or legal counsel, and the Trustee shall not be liable for and shall be fully protected from any loss or liability occasioned by any action or refusal to act based upon the advice of any such expert, adviser or legal counsel. In the exercise of the powers, authorities or discretion conferred upon the Trustee under the Trust Indenture, the Trustee is and shall be conclusively deemed to be acting as Trustee of the assets of the Trust and shall not be subject to any personal liability for any debts, liabilities, obligations, claims, demands, judgments, costs, charges or expenses against or with respect to the Trust or the Trust Fund. In addition, the Trust Indenture contains other customary provisions limiting the liability of the Trustee.

Amendments to the Trust Indenture

The Trust Indenture may be amended or altered, from time to time, by at least 66-2/3% of the votes cast at a meeting of our Unitholders called for such purpose.

The Trustee may, without the approval of the Unitholders, make certain amendments to the Trust Indenture, including amendments:

• for the purpose of ensuring continuing compliance with applicable laws (including the Tax Act), regulations, requirements or policies of any governmental or other authority having jurisdiction over the Trustee or over the Trust;

• ensuring that we will satisfy the provisions of each of Sections 108(2)(a) and 132(6) of the Tax Act, as from time to time amended or replaced;

• which, in the opinion of the Trustee, provide additional protection for or benefit to the Unitholders;

• to remove any conflicts or inconsistencies in the Trust Indenture or making corrections, including the correction or rectification of any ambiguities, defective provisions, errors, mistakes or omissions, which are, in the opinion of the Trustee, necessary or desirable and not prejudicial to the Unitholders;

• which, in the opinion of the Trustee, are necessary or desirable as a result of changes in taxation laws; and

• removing or curing inconsistencies between the Trust Indenture and the Material Contracts (as such term is defined in the Trust Indenture) which are, in the opinion of the Trustee, necessary or desirable and not prejudicial to the Unitholders.

In December 2007, the Trust Indenture was amended to allow the Trust to participate in the DRS. Effective January 1, 2008, all issuers whose securities are listed on the New York Stock Exchange are required to ensure that their listed securities are eligible for participation in the DRS. DRS eligible issuers must provide an investor with the ability to have their securities registered in the investors’ name directly on the issuer’s books (through its transfer agent) or through the investors’ brokerage dealer, thereby eliminating the need for physical certificates to evidence ownership of securities. As a result of the implementation of the need to be DRS eligible, certain amendments were required to be made to the Trust Indenture of the Trust.

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Term of the Trust and Sale of Substantially All Assets

The Trust has been established for a term ending December 31, 2095. Pursuant to the Trust Indenture, termination of the Trust or the sale or transfer of our assets in their entirety or substantially in their entirety, except as part of an internal reorganization of the our assets as approved by the AOG Board of Directors, requires approval by at least 66-2/3% of the votes cast at a meeting of the Unitholders.

Exercise of Voting Rights Attached to Common Shares

The Trust Indenture provides that the Trustee may vote securities of AOG held by it at any meeting of shareholders of AOG as well as any Permitted Investments held, from time to time, as part of the Trust Fund which carry voting rights. However, the Trustee may not, under any circumstances whatsoever, vote any AOG securities or any other Permitted Investments which carry voting rights to authorize the sale, lease or exchange of all or substantially all of the property of AOG or any other entity owned directly or indirectly by us which represents more than 51% of the Trust Fund, except as part of a reorganization of AOG and any one or more of our directly or indirectly owned subsidiaries without the approval of at least 66-2/3% of the votes cast at a meeting of the Unitholders called for such purpose.

ADDITIONAL INFORMATION RESPECTING ADVANTAGE OIL & GAS LTD.

Directors and Officers of AOG as at March18, 2009

Name, Province and Country of Residence	Position Held and Period Served as a Director or Officer(4)(5)	Principal Occupations During Past Five Years
Gary F. Bourgeois Ontario, Canada	Vice President, Corporate Development and Director since May 24, 2001	Vice President, Corporate Development of AOG since May 24, 2001. Vice President of AIM from March 2001 to June 2006. Prior thereto, Managing Director of the EnerPlus Group of Companies, which companies specialize in management of oil and gas income funds and royalty trusts (1998-2000). In addition, President of Queen-Yonge Investments Limited (since 1985), a private family-owned investment holding company with holdings in oil and gas royalty trusts, real estate income funds, direct oil and gas properties, private and public exploration and production companies, and direct commercial real estate holdings.
Kelly I. Drader(9) Alberta, Canada	President and Chief Financial Officer since January 27, 2009 and Director since May 24, 2001	President and Chief Financial Officer of AOG since January 27, 2009. Chief Executive Officer of AOG from May 24, 2001 to January 27, 2009. President of AIM from March 2001 to June 2006. Prior thereto, Senior Vice President (1997-2001) and Vice President, Finance and Chief Financial Officer (1990-1997) of EnerPlus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts.
John A. Howard (2)(3)(8) Alberta, Canada	Director since June 23, 2006	President of Lunar Enterprises Corp., a private holding company.
Andy J. Mah Alberta, Canada	Chief Executive Officer since January 27, 2009 and a Director since June 23, 2006	Chief Executive Officer since January 27, 2009. President and Chief Operating Officer from June 23, 2006 to January 27, 2009. Prior thereto, President of Ketch Resources Ltd. since October 2005. Chief Operating Officer of Ketch Resources Ltd. from January 2005 to September 2005. Prior thereto, Executive Officer and Vice President, Engineering and Operations of Northrock Resources Ltd. from August 1998 to January 2005.
Ronald A. McIntosh(1)(3) Alberta, Canada	Director since September 25, 1998(6)	Chairman of North American Energy Partners Inc., a publicly traded corporation.
Stephen E. Balog(1)(3) Alberta, Canada	Director since August 16, 2007	President, West Butte Management Inc., a private oil and gas consulting company. Prior thereto, President & Chief Operating Officer and a Director of Tasman Exploration Ltd. from 2001 to June, 2007.

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Name, Province and Country of Residence Position Held and Period Served as a Director or Officer⁽⁴⁾⁽⁵⁾ Principal Occupations During Past Five Years

Carol D. Pennycook(1)(2) Ontario, Canada	Director since May 26, 2004	Partner at the Toronto office of Davies Ward Phillips & Vineberg, LLP, a national law firm.
Steven Sharpe Ontario, Canada	Director since May 24, 2001 and Non-Executive Chairman since May 26, 2004	Since, July, 2008, Senior Advisor to Blair Franklin Capital Partners, Inc., a Toronto-based investment bank which he co-founded in May, 2003. Prior to that, Mr. Sharpe was Managing Partner of Blair Franklin, from its inception. Before then, he was Managing Director of The EBS Corporation, a management and strategic consulting firm.
Rodger A. Tourigny(1)(2)(7) Alberta, Canada	Director since December 31, 1996(6)	President of Tourigny Management Ltd., a private oil and gas consulting company.
Sheila O’Brien(2) Alberta, Canada	Director since March 21, 2007	From April 2004, President of Belvedere Investments and Corporate Director; from July 1998 to April 2004, Senior Vice President, Human Resources, Public Affairs, Investor and Government Relations with Nova Chemicals Corporation. Among her other accomplishments, Ms. O’Brien was designated as Member, Order of Canada in 1999.
Paul Haggis (1) Ontario, Canada	Director since November 7, 2008	Mr. Haggis’ was President and Chief Executive Officer of Ontario Municipal Employees Retirement System (OMERS) from September 2003 to March 2007, Interim Chief Executive Officer of the Public Sector Pension Investment Board (PSPIB) during 2003 and Executive Vice-President, Development and Chief Credit Officer of Manulife Financial in 2002. Mr. Haggis has extensive financial markets and public board experience and currently serves on the Board of Directors of Canadian Tire Bank and as a director and Chair of the Investment Committee of the Insurance Corporation of British Columbia.
Patrick J. Cairns Alberta, Canada	Senior Vice President	Senior Vice President of AOG since June 2001. Vice President of the Manager since May 2001. Prior thereto, Mr. Cairns was Vice President, Evaluations with the Enerplus Group of Companies, which companies specialize in the management of oil and gas income funds and royalty trusts.
Craig Blackwood(9) Alberta, Canada	Vice President, Finance	Vice President, Finance of AOG since January 2009. Mr. Blackwood is a Chartered Accountant and was the Director of Finance of AOG from November 2004 to January 2009. Prior thereto, Mr. Blackwood was Controller from October 2003 to November 2004 and Manager, Financial Reporting from March 2002 to October 2003 with Calpine Canada Natural Gas Company and Calpine Power Income Fund.  Prior thereto, Mr. Blackwood has worked in various financial roles and has diverse experience throughout the resource sector.
Neil Bokenfohr Alberta, Canada	Vice President, Exploitation	Vice-President, Exploitation since June 23, 2006. Prior thereto, Vice President Exploitation and Operations of Ketch Resources Ltd. since January 2005; Vice President, Engineering of Bear Creek Energy Ltd. (and Crossfield Gas Corp. prior thereto) from March 2002 to January 2005. Prior thereto, Director of Exploitation for Calpine Canada Natural Gas Company from December 2000 to March 2002.
Weldon M. Kary Alberta, Canada	Vice President, Geosciences and Land	Vice President, Exploitation since February 14, 2005. Prior thereto, with AOG since May 23, 2001, most recently as Manager, Geology and Geophysics. Prior thereto, Exploration Manager at Palliser Energy Corp. when Palliser was purchased by Search Energy Corp, the predecessor entity of AOG.
Anthony Coombs Alberta, Canada	Controller	Controller since September 1, 2004. Prior thereto with AOG since May 23, 2001, most recently as Chief Accountant. Prior thereto, Chief Accountant for Search Energy Corp., the predecessor entity of Advantage.
Jay P. Reid Alberta, Canada	Corporate Secretary	Partner, Burnet, Duckworth & Palmer LLP, a Calgary-based law firm.

Notes:

(1)	Member of the Audit Committee.
(2)	Member of the Human Resources, Compensation and Corporate Governance Committee.
(3)	Member of the Independent Reserve Evaluation Committee.
(4)	AOG does not have an executive committee of the Board.

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(5)	AOG’s directors shall hold office until the next annual general meeting of Unitholders or until each director’s successor is appointed or elected pursuant to the ABCA, the Shareholder Agreement and the Management Agreement.
(6)	The period of time served as a director of AOG includes the period of time served as a director of Search prior to the Amalgamation, where applicable. Each of these directors were appointed directors of post-Reorganization Search on May 24, 2001.
(7)	Mr. Tourigny was a director of Shenandoah Resources Ltd. (“Shenandoah”) prior to it being placed into receivership on September 17, 2002 and prior to the issuance of cease trade orders in respect of Shenandoah’s securities by the Alberta Securities Commission and the British Columbia Securities Commission on November 8, 2002 and October 23, 2002, respectively. Cease trade orders were issued because Shenandoah failed to file certain required financial statements. As of the date hereof, the cease trade orders remain outstanding. Shenandoah’s common shares were suspended from trading on the TSX Venture Exchange on April 24, 2002. Mr. Tourigny resigned his directorship with Shenandoah effective September 17, 2002. Mr. Tourigny was also a director of Probe Exploration Inc. (“Probe”) prior to its receivership and prior to the issuance of cease trade orders in respect of Probe’s securities by the Alberta Securities Commission and the Ontario Securities Commission on July 7, 2000 and July 17, 2000, respectively. The cease trade orders were issued because Probe failed to file certain required financial statements. As at the date hereof, the cease trade orders remain outstanding. Probe’s common shares were suspended from trading on the TSX on March 17, 2000, and were subsequently delisted from the TSX at the close of business on March 16, 2001. Mr. Tourigny resigned his directorship with Probe effective April 14, 2000.
(8)	Mr. Howard was the President, Chief Executive Officer and Director of Sunoma Energy Corp. Immediately upon his resignation from the executive and board of directors, Sunoma Energy Corp. filed for Court protection.
(9)	Mr. Peter Hanrahan, the former Vice President, Finance and Chief Financial Officer resigned from such positions on January 27, 2009.

As at March 11, 2009 the directors and executive officers of AOG, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 1,831,400 Trust Units, or approximately 1.3% of the issued and outstanding Trust Units.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Other than as disclosed above, no current director or officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG has, within the last ten years prior to the date of this document, been a director, chief executive officer or chief financial officer of any issuer (including AOG) that, (i) while the person was acting in the capacity as director, chief executive officer or chief financial officer, was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, that was in effect for a period of more than thirty (30) consecutive days; or (ii) was subject to an order that resulted, after the director, executive officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG ceased to be a director, chief executive officer or chief financial officer of an issuer, in the issuer being the subject of a cease trade or similar order or an order that denied the relevant issuer access to any exemption under securities legislation, for a period of more than thirty (30) consecutive days, which resulted from an event that occurred while that person was acting as a director, chief executive officer or chief financial officer of the issuer.

No current director or officer or security holder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG has, within the last ten years prior to the date of this document, been a director or executive officer of any company (including AOG) that, while such person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement for compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

In addition, no current director or officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG has, within the last ten years prior to the date of this document, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, officer or securityholder.

No current director or officer or securityholder holding a sufficient number of securities of the Trust or AOG to affect materially the control of the Trust or AOG has been subject to: (i) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or (ii) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

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Conflicts of Interest

The directors and officers of AOG may, from time to time, be involved in the business and operations of other issuers, in which case a conflict may arise. The ABCA provides that in the event a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interests arise, such conflicts will be resolved in accordance with the provisions of the ABCA.

Distribution Policy

It is anticipated that income received will be from: (i) the interest received on the principal amount of the Notes; (ii) royalty income from the Royalty; and (iii) the dividends, if any, received from the shares of AOG. The Trustee will make monthly cash distributions to Unitholders of the interest income earned from the Notes, royalty income from the Royalty and dividends, if any, received on Common Shares, after expenses, if any, and any cash redemptions of Trust Units. See “Risk Factors – Oil and Natural Gas Prices/Delay in Cash Distributions/Dependence on AOG”. On March 18, 2009 we announced that monthly distributions have been suspended with the final cash distribution paid to Unitholders on March 16, 2009 to Unitholders of record as of February 27, 2009. See “General Development of the Business - Recent Developments – Suspension of Distributions”.

Share Capital

AOG is authorized to issue an unlimited number of Common Shares, non-voting shares, preferred shares and exchangeable shares. Advantage is the sole holder of the issued and outstanding Common Shares. There are no non-voting shares, preferred shares or exchangeable shares issued and outstanding. Advantage is also the sole holder of the outstanding Notes.

The following is a description of the rights attaching to the Common Shares, non-voting shares, preferred shares and Notes.

Common Shares

Each Common Share entitles its holder to receive notice of and to attend all meetings of the shareholders of AOG and to one vote at such meetings. The holders of Common Shares are, at the discretion of the AOG Board of Directors and subject to applicable legal restrictions, entitled to receive any dividends declared by the AOG Board of Directors on the Common Shares. The holders of Common Shares are entitled to share equally in any distribution of the assets of AOG upon the liquidation, dissolution, bankruptcy or winding-up of AOG or other distribution of its assets among its shareholders for the purpose of winding-up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to any instruments having priority over the Common Shares.

Non-Voting Shares

The non-voting shares have identical rights to the Common Shares except that holders of non-voting shares are not generally entitled to receive notice of or attend at meetings of shareholders of AOG or to vote their shares at such meetings.

Preferred Shares

The preferred shares may be issued, from time to time, in one or more series, each series consisting of such number of preferred shares as determined by the AOG Board of Directors, who may also fix the designations, rights, privileges, restrictions and conditions attached to the shares of each series of preferred shares. No preferred shares are presently issued and outstanding. The preferred shares of each series shall, with respect to payment of dividends and distributions of assets in the event of liquidation, dissolution or winding-up of AOG, whether voluntary or involuntary, or any other distribution of the assets of AOG among its shareholders for the purpose of winding-up its affairs, rank on a parity with the preferred shares of every other series and shall be entitled to preference over the Common Shares and the shares of any other class ranking junior to the preferred shares.

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Notes

The following is a summary of the material attributes and characteristics of the Notes. This summary does not purport to be complete and is qualified in its entirety by reference to the provisions of the Note Indentures, pursuant to which the Notes are issued.

Payment upon Maturity

On maturity and subject to any applicable subordination restrictions, AOG will repay the indebtedness represented by the Notes by paying to the Note Trustee, in lawful money of Canada, an amount equal to the principal amount of the outstanding Notes, together with accrued and unpaid interest thereon.

Ranking

Payment of the principal and interest (other than regularly scheduled interest and principal at maturity, provided no default on Senior Indebtedness (as hereinafter defined) has occurred and payment of such interest or principal is not otherwise required to be suspended in accordance with the terms of subordination agreements which may be entered into with the holders of Senior Indebtedness (as herein defined)) on the Notes will be subordinated in right of payment, as set forth in the Note Indentures, to the prior payment in full of the principal of and accrued and unpaid interest on, and all other amounts owing in respect of, all senior indebtedness (“Senior Indebtedness”) which is defined as: (a) all indebtedness, obligations and liabilities of AOG in respect of borrowed money (including the deferred purchase price of property), other than: (i) indebtedness evidenced by the Note Indentures; and (ii) indebtedness which, by the terms of the instrument creating or evidencing the same, is expressed to rank in right of payment equally with or subordinate to the indebtedness evidenced by the Note Indentures; and (b) from and after the commencement of, and during the continuance of, any creditor proceedings (including bankruptcy, liquidation, winding-up, dissolution, restructuring or arrangement proceedings), all indebtedness, obligations and liabilities of AOG, other than indebtedness, obligations and liabilities of AOG represented by the Notes. The Note Indentures provide that in the event of any creditor proceedings relative to AOG, the holders of all Senior Indebtedness, which would include bank debt and suppliers of AOG, will be entitled to receive payment in full before the holders of the Notes are entitled to receive any payment. Any amount of property received contrary to these provisions shall be held in trust for and paid over to the holders of Senior Indebtedness.

In the event of any creditor proceedings, the indebtedness represented by the Notes is not to be classified with any Senior Indebtedness for voting or distribution, which means that holders of Senior Indebtedness may vote separately from the holders of Notes in respect of any restructuring or arrangement proposal regarding AOG.

Default

The Note Indentures provides that any of the following shall constitute an “Event of Default”: (i) default in payment of the principal of the Notes when the same becomes due; (ii) the failure to pay the interest obligations of the Notes for a period of 12 months; (iii) default on any indebtedness exceeding $10,000,000; (iv) certain events of winding-up, liquidation, bankruptcy, insolvency or receivership; (v) the taking of possession by an encumbrancer of all or substantially all of the property of AOG; or (vi) default in the observance or performance of any other covenant or condition of the Note Indenture and the continuance of such default for a period of 30 days after notice in writing has been given by the Note Trustee to AOG specifying such default and requiring AOG to rectify the same.

Subordination Agreements

Pursuant to the terms of the Note Indentures, the Note Trustee may enter into subordination agreements with the holders of certain Senior Indebtedness under which the Note Trustee, on behalf of the holders of Notes, may agree directly with a holder of Senior Indebtedness in implementation of and/or in addition to the subordination terms described under “Ranking” directly above. The Note Trustee may give a holder of Senior Indebtedness a power of attorney to be exercised in any creditor proceedings to enforce the terms thereof. The Note Trustee may also agree to ensure that any transferee of Notes (or other securities of AOG) agrees to be bound by the provisions of the subordination agreements.

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Long Term Notes

The aggregate principal amount of Long Term Notes as at December 31, 2008 was approximately $1.179 billion. The Long Term Notes mature on December 31, 2031. The Long Term Notes consist of a series of notes, which as at the date hereof, includes Long Term Notes originally bearing interest at a rate of 14% and 12.5% per annum, payable monthly on the 15th day of the month (or, if such day is not a Business Day, the first Business Day thereafter) for interest earned during the preceding month. Effective February 18, 2009, the interest rates on the Long Term Notes were reduced to 1% per annum. The principal and interest on the Long Term Notes are payable in lawful money of Canada. The Long Term Notes are issuable only as fully-registered notes in minimum denominations of $100.00 and integral multiples of $1.00.

Redemption of Long Term Notes

The Long Term Notes will not be redeemable at the option of AOG or by the holders thereof prior to maturity except in the limited circumstances prescribed by Long Term Note Indenture, where the AOG Board of Directors believe the indebtedness represented by the Long Term Notes could not be refinanced on maturity, or where AOG is prevented by applicable law from paying dividends or making other distributions in respect of Common Shares.

Medium TermNotes

The original aggregate principal amount of Medium Term Notes was $344.8 million (“Original Principal Amount”) and the aggregate principal amount of the Medium Term Notes as at December 31, 2008 was approximately $146.7 million. The Medium Term Notes consist of a series of notes, which as of December 31, 2008, includes Medium Term Notes originally bearing interest at rates between 7.75% and 10.375% per annum, payable twice annually, and maturing between December 31, 2012 and December 21, 2015. Effective February 18, 2009, the interest rates on the Medium Term Notes were reduced to 1% per annum. The principal and interest on the Medium Term Notes are payable in lawful money of Canada. The Medium Term Notes are issuable only as fully-registered notes in minimum denominations of $100.00 and integral multiples of $1.00.

Principal Repayments and Redemption of Medium Term Notes

From time to time and in any event not less frequently than each anniversary of December 31, AOG shall make principal repayments on the Notes in an aggregate amount equal to not less than 5% of the Original Principal Amount (and, if applicable, the aggregate principal amount of any additional Notes issued under the Medium Term Note Indenture in excess of the Original Principal Amount (the “Supplemental Principal Amount”)), provided, however that during the period commencing on September 30, 2004 and ending on December 31 of the year ended five years before the Maturity Date, AOG shall make, in aggregate, principal payments on the Notes in an amount equal to not less than 50% of the Original Principal Amount. In the event that, at any time during the term of this Indenture, a Supplemental Principal Amount is outstanding, during the period commencing with the issue date of the Notes relating to the Supplemental Principal Amount and ending five years from such issue date, AOG shall make principal payments on the Notes relating to the Supplemental Principal Amount in an aggregate amount equal to not less than 50% of the Supplemental Principal Amount. In the event that AOG makes principal repayments on the Notes pursuant to this section of the Medium Note Indenture and there is more than one holder thereof, such principal prepayments shall be made as near as may be pro rata as between the holders and without discrimination or preference, based upon the aggregate principal amount of Notes held by them (rounded, if necessary, to the nearest One Dollar ($1.00)).

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Debentures

The Debentures pay interest semi-annually and are convertible at the option of the holder into Trust Units at the applicable conversion price per Trust Unit plus accrued and unpaid interest. The details of the Debentures including the balance outstanding as at the date hereof are as follows:

	8.75%	7.50%	6.50%
Trading symbol	AVN.DBF	AVN.DBC	AVN.DBE
Issue date	June 10, 2004	Sep. 15, 2004	May 18, 2005
Maturity date	June 30, 2009	Oct. 1, 2009	June 30, 2010
Conversion price	$34.67	$20.25	$24.96
Outstanding	$29,839,000	$52,268,000	$69,927,000

	7.75%	8.00%	Total
Trading symbol	AVN.DBD	AVN.DBG
Issue date	Sep. 15, 2004	Nov. 13, 2006
Maturity date	Dec. 1, 2011	Dec. 31, 2011
Conversion price	$21.00	$20.33
Outstanding	$46,766,000	$15,528,000	$214,328,000

The convertible debentures are redeemable prior to their maturity dates, at the option of the Fund, upon providing 30 to 60 days advance notification. The redemption prices for the various debentures, plus accrued and unpaid interest, is dependent on the redemption periods and are as follows:

Convertible Debenture	Redemption Periods	Price
8.75%	After June 30, 2008 and before June 30, 2009	$1,025
7.50%	After October 1, 2008 and before October 1, 2009	$1,025
6.50%	After June 30, 2008 and on or before June 30, 2009 After June 30, 2009 and before June 30, 2010	$1,050 $1,025
7.75%	After December 1, 2008 and on or before December 1, 2009 After December 1, 2009 and before December 1, 2011	$1,025 $1,000
8.00%	After December 31, 2009 and on or before December 31, 2010 After December 31, 2010 and before December 31, 2011	$1,050 $1,025

The Royalty Agreement

Pursuant to the Royalty Agreement, AOG has granted to us the Royalty on AOG’s interest in Petroleum Substances within, upon or under all of AOG’s developed and undeveloped Canadian Oil and Natural Gas Properties

The Royalty will consist of the right to receive a monthly payment from AOG equal to the “Royalty Production Income”, which in respect of any period for which Royalty is calculated, means 99% of the production revenues from the Properties less an equivalent portion of the amount of all deductions permitted under the Royalty Agreement. The Royalty does not constitute an interest in land and we are not entitled to take our share of production in kind or to separately sell or market our share of Petroleum Substances.

Pursuant to the Royalty Agreement approximately 99% of the economic benefit derived from the assets of AOG accrues to the benefit of the Fund and ultimately to us and our Unitholders. The term of the Royalty Agreement will be for so long as there are Properties to which the Royalty Agreement applies.

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If AOG wishes to acquire or dispose of any properties that will cost or result in proceeds in excess of $5 million, approval of the AOG Board of Directors is required to approve such acquisition or disposition, respectively.

Cash Distributions

The following is a summary of the distributions made by us for each of the three most recently completed financial years.

For the 2008 Period Ended	Distributions per Unit	Payment Date
January 31	$0.12	February 15, 2008
February 29	$0.12	March 17, 2008
March 31	$0.12	April 15, 2008
April 30	$0.12	May 15, 2008
May 30	$0.12	June 16, 2008
June 30	$0.12	July 15, 2008
July 31	$0.12	August 15, 2008
August 29	$0.12	September 15, 2008
September 30	$0.12	October 15, 2008
October 31	$0.12	November 17, 2008
November 28	$0.12	December 15, 2008
December 31	$0.08	January 15, 2009
Total:	$1.40

For the 2007 Period Ended	Distributions per Unit	Payment Date
January 31	$0.15	February 15, 2007
February 28	$0.15	March 15, 2007
March 31	$0.15	April 16, 2007
April 30	$0.15	May 15, 2007
May 31	$0.15	June 15, 2007
June 30	$0.15	July 16, 2007
July 31	$0.15	August 15, 2007
August 31	$0.15	September 17, 2007
September 30	$0.15	October 15, 2007
October 31	$0.15	November 15, 2007
November 30	$0.15	December 17, 2007
December 31	$0.12	January 15, 2008
Total:	$1.77

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For the 2006 Period Ended	Distributions per Unit	Payment Date
January 31	$0.25	February 15, 2006
February 28	$0.25	March 15, 2006
March 31	$0.25	April 17, 2006
April 30	$0.25	May 15, 2006
May 31	$0.25	June 15, 2006
June 30	$0.25	July 17, 2006
July 31	$0.20	August 15, 2006
August 31	$0.20	September 15, 2006
September 30	$0.20	October 16, 2006
October 31	$0.20	November 15, 2006
November 30	$0.18	December 15, 2006
December 31	$0.18	January 15, 2007
Total:	$2.66

Note:

(1)	On February 17, 2009, a distribution of $0.08 per Trust Unit was paid to Unitholders of Record on the close of business on January 30, 2009. On March 16, 2009, a distribution of $0.04 per Trust Unit was paid to Unitholders of Record on the close of business on February 27, 2009.
(2)	On March 18, 2009 we announced that monthly distributions have been suspended with the final cash distribution paid to Unitholders on March 16, 2009 to Unitholders of record as of February 27, 2009. See “General Development of the Business - Recent Developments – Suspension of Distributions”.

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MARKET FOR SECURITIES

Our Trust Units are listed for trading on the TSX under the symbol “AVN.UN” and, since December 9, 2005, on the NYSE under the symbol “AAV”. The following table sets forth the high and low closing trading prices and the aggregate trading volume of the Trust Units as reported by the TSX and NYSE for the periods indicated.

Period	High	Low	Volume
	($)	($)
TSX Trading
2008
January	9.92	8.65	5,340,085
February	11.06	9.23	4,168,544
March	11.81	10.35	4,621,912
April	12.88	11.27	5,313,283
May	13.50	11.62	8,101,668
June	13.75	12.50	5,829,922
July	13.29	10.93	6,962,143
August	12.13	10.31	6,275,835
September	11.89	8.91	8,540,477
October	9.86	5.31	11,164,655
November	7.54	5.30	6,005,793
December	6.21	4.63	7,160,256
2009
January	6.13	5.06	5,658,642
February	5.20	2.62	10,005,123
NYSE Trading ($US)
2008
January	9.84	8.45	4,006,900
February	11.16	9.12	3,789,300
March	11.55	10.35	3,677,200
April	12.70	11.16	3,993,500
May	13.53	11.40	5,553,100
June	13.48	12.32	4,005,300
July	13.00	10.67	7,443,280
August	11.37	9.65	4,409,818
September	11.04	8.69	6,020,983
October	9.19	4.47	12,897,932
November	6.49	4.10	5,654,946
December	4.96	3.85	6,701,178
2009
January	5.20	4.14	4,485,565
February	4.19	2.11	8,684,601

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Our 6.50% Debentures are listed for trading on the TSX under the symbol “AVN.DB.E”. The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 6.50% Debentures as reported by the TSX for the periods indicated.

Period	High	Low	Volume
	($)	($)
2008
January	95.75	93.01	21,780
February	96.99	93.25	41,540
March	99.00	96.00	26,070
April	99.49	97.00	15,010
May	99.50	97.75	14,680
June	100.75	98.50	31,883
July	100.50	99.25	13,390
August	101.00	100.05	9,690
September	100.84	94.00	14,860
October	98.95	85.00	8,630
November	91.25	83.00	6,640
December	88.00	78.00	9,990
2009
January	90.00	84.50	12,080
February	88.00	80.00	5,610

Our 7.5% Debentures are listed for trading on the TSX under the symbol “AVN.DB.C”. The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 7.5% Debentures as reported by the TSX for the periods indicated.

Period	High	Low	Volume
	($)	($)
2008
January	100.25	98.00	12,300
February	101.50	99.81	2,070
March	101.98	100.26	920
April	101.25	100.00	2,080
May	101.99	100.21	2,430
June	102.00	100.25	56,000
July	101.89	100.36	6,880
August	101.99	99.26	4,500
September	100.76	98.50	9,530
October	99.79	85.00	24,920
November	94.50	85.01	14,660
December	90.50	85.01	18,680
2009
January	98.50	89.03	95,290
February	96.00	90.00	57,280

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Our 7.75% Debentures are listed for trading on the TSX under the symbol “AVN.DB.D”. The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 7.75% Debentures as reported by the TSX for the periods indicated.

Period	High	Low	Volume
	(%)	(%)
2008
January	97.99	94.00	12,340
February	99.19	97.00	5,670
March	101.25	99.01	7,510
April	100.94	98.76	5,165
May	103.99	99.01	4,830
June	103.94	102.01	12,770
July	102.75	99.00	4,140
August	101.50	100.26	6,340
September	101.00	91.00	18,170
October	97.00	75.00	1,400
November	89.00	70.00	3,220
December	80.00	66.01	5,360
2009
January	85.00	77.00	3,660
February	79.68	60.00	3,330

Our 8.00% Debentures are listed for trading on the TSX under the symbol “AVN.DB.G”. The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 8.00% Debentures as reported by the TSX for the periods indicated.

Period	High	Low	Volume
	(%)	(%)
2008
January	99.00	93.00	4,170
February	99.00	98.00	2,370
March	101.00	98.51	1,880
April	101.98	99.00	1,410
May	101.25	95.00	5,990
June	103.00	101.50	1,810
July	102.50	101.50	1,130
August	103.00	100.50	780
September	102.99	100.10	860
October	80.00	80.00	100
November	80.25	80.00	710
December	95.00	85.00	130
2009
January	95.00	90.00	2050
February	—	—	—

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Our 8.75% Debentures are listed for trading on the TSX under the symbol “AVN.DB.F”. The following table sets forth the high and low closing trading prices and the aggregate trading volume of the 8.75% Debentures as reported by the TSX for the periods indicated.

Period	High	Low	Volume
	($)	($)
2008
January	101.00	100.00	9,870
February	101.68	99.70	3,890
March	102.44	100.01	1,480
April	102.00	100.11	2,177
May	102.00	100.50	2,160
June	102.68	100.70	2,570
July	102.50	101.51	3,120
August	102.99	102.00	5,480
September	102.99	100.03	6,330
October	101.06	90.00	5,310
November	98.24	92.03	6,710
December	95.74	93.00	3,370
2009
January	98.74	93.55	23,160
February	96.50	92.00	23,470

ESCROWED SECURITIES

As part of the Arrangement, shareholders of AIM received Trust Units in payment for the sale of their AIM shares to the Trust. All such shareholders were required to enter into an escrow agreement (the “Escrow Agreement”) providing for the release of Trust Units as to one-third on each anniversary date of the Arrangement for three years. All distributions paid on the Trust Units held in escrow are made directly to the holders of the escrowed Trust Units, notwithstanding that their Trust Units are in escrow.

All Trust Units will be released from escrow if a Change in Control (as defined in the Escrow Agreement) occurs. All Trust Units being held in escrow for a particular shareholder will be released upon that shareholder ceasing to be an employee for any reason other than termination for just cause or voluntary departure or resignation.

The Board may consent to the transfer within escrow or the release from escrow of Trust Units in such circumstances and on such terms and conditions as it shall determine in its sole discretion.

The Trust Units subject to escrow at December 31, 2008 are as follows:

Designation of Class	Number of Trust Units held in Escrow	Percentage of Class
Trust Units	564,612(1)	0.4%

Notes:

(1) All Trust Units are held by Computershare Trust Company of Canada as escrow agent.

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LEGAL PROCEEDINGS

There are no outstanding legal proceedings which are for claims in excess of 10% of our current asset value to which we are a party or in respect of which any of our properties are subject, nor are there any such proceedings known to be contemplated.

REGULATORY ACTIONS

During the year ended December 31, 2008 there were (i) no penalties or sanctions imposed against the Trust or AOG or by a court relating to securities legislation or by a securities regulatory authority; (ii) no other penalties or sanctions imposed by a court or regulatory body against the Trust or AOG that would likely be considered important to a reasonable investor in making an investment decision; and (iii) no settlement agreements the Trust or AOG entered into before a court relating to a securities legislation or with a securities regulatory authority.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of directors and executive officers of AOG or nominees for director of AOG, any Unitholder who beneficially owns or directs or controls more than 10% of the Trust Units or any known associate or affiliate of such persons in any transaction during 2008 or in any proposed transaction which has materially affected or would materially affect the Trust or AOG.

MATERIAL CONTRACTS

Except for contracts entered into by us in the ordinary course of business or otherwise disclosed herein, the only material contracts we entered into are the Trust Indenture described herein under the heading “Additional Information Respecting Advantage Energy Income Fund” and the Administrative Agreement described herein under the heading “Additional Information Respecting Advantage Energy Income Fund – Delegation of Authority, Administration and Trust Governance”. Copies of the Trust Indenture and Administration Agreement, in addition to Documents Affecting the Rights of Securityholders, are available on our SEDAR profile at www.sedar.com.

INTEREST OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by us during, or related to, our most recently completed financial year other than Sproule Associates Limited, our independent engineering evaluator and PricewaterhouseCoopers LLP, our current auditors. As at the date hereof, none of the principals of Sproule Associates Limited had any registered or beneficial interests, direct or indirect, in any securities or other property of Advantage or of our associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them. PricewaterhouseCoopers LLP have confirmed that they are independent in accordance with the relevant rules and related interpretation prescribed by the Institute of Chartered Accountants of Alberta and the rules of the United States Securities and Exchange Commission.

In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of the Trust or of any associate or affiliate of the Trust except for Mr. Jay Reid, the Corporate Secretary of AOG, who is a partner of Burnet, Duckworth & Palmer LLP, which law firm provides the Trust and AOG with legal services.

AUDITORS, TRANSFER AGENT AND REGISTRAR

Our auditors are PricewaterhouseCoopers LLP, Chartered Accountants, Calgary, Alberta.

Computershare Trust Company of Canada at its offices in Calgary, Alberta and Toronto, Ontario acts as the transfer agent and registrar for the Trust Units and Debentures.

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AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

The audit committee (the “Audit Committee”) is comprised of Messrs. Rodger Tourigny, Paul Haggis, Stephen Balog and Ronald McIntosh and Ms. Carol Pennycook. The following chart sets out the assessment of each Audit Committee member’s independence, financial literacy and relevant educational background and experience supporting such financial literacy.

Name, Province and Country of Residence	Independent	Financially Literate	Relevant Education and Experience
Rodger A. Tourigny Alberta, Canada	Yes	Yes	Mr. Tourigny has a Bachelor of Commerce and is a Chartered Accountant. He is a director and President of Tourigny Management Ltd., a private company through which he provides consulting services. Mr. Tourigny has recently served as a director and chairman of the audit committee of NAV Energy Income Fund and was a director and member of the audit committee of Burmis Energy Inc.
Ronald A. McIntosh Alberta, Canada	Yes	Yes	Mr. McIntosh is the Chairman and member of audit committee of North American Energy Partners Inc., a publicly traded corporation. Mr. McIntosh was also the Chairman and a member of the audit committee of Tasman Exploration Ltd., a private oil and gas company.
Paul Haggis Ontario, Canada	Yes	Yes	Mr. Haggis’ was President and Chief Executive Officer of Ontario Municipal Employees Retirement System (OMERS) from September 2003 to March 2007, Interim Chief Executive Officer of the Public Sector Pension Investment Board (PSPIB) during 2003 and Executive Vice-President, Development and Chief Credit Officer of Manulife Financial in 2002. Mr. Haggis has extensive financial markets and public board experience and currently serves on the Board of Directors of Canadian Tire Bank and as a director and Chair of the Investment Committee of the Insurance Corporation of British Columbia.  Mr. Haggis holds a Bachelor of Arts degree from the University of Western Ontario and is certified as a Chartered Director through the Directors College at McMaster University.
Stephen Balog Alberta, Canada	Yes	Yes	Mr. Balog is President of West Butte Management Inc., a private oil and gas consulting company. Prior thereto, Mr. Balog was President & Chief Operating Officer and a director of Tasman Exploration Ltd. from 2001 to June 2007 and was a director of BelAir Energy Corporation, a junior public company.  He accepted appointment to the Petroleum Advisory Committee, Alberta Securities Commission in 2009 and has a Bachelor of Science, Chemical Engineering.
Carol D. Pennycook Ontario, Canada	Yes	Yes	Ms. Pennycook is a partner at the Toronto offices of Davies Ward Phillips & Vineberg, LLP, a national law firm. Ms. Pennycook received her LLB in 1979 and has been a partner since 1986. A significant portion of Ms. Pennycook’s practice involves financing transactions.

Pre-Approval of Policies and Procedures

We have adopted polices and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by PricewaterhouseCoopers LLP as set forth in item 22 of the Audit Committee charter, which is reproduced below under the heading “Audit Committee Charter”. The Audit Committee has approved the provision of a specified list of audit and permitted non-audit services that the audit committee believes to be typical, reoccurring or otherwise likely to be provided by PricewaterhouseCoopers LLP during the current fiscal year. The list of services is sufficiently detailed as to the particular services to be provided to ensure that the audit committee knows precisely what services it is being asked to pre-approve and it is not necessary for any member of management to make a judgment as to whether a proposed service fits within pre-approved services.

AUDIT COMMITTEE CHARTER

The following is a summary of our Audit Committee Charter which was originally approved by the AOG Board of Directors on April 30, 2002 and amended in April 2003, April 2004, June 2005, August 2005, October 2005 and March 2006:

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Purpose

The primary function of the Audit Committee is to assist the Board of Directors of AOG in fulfilling its responsibilities by reviewing: the financial reports and other financial information provided by the Trust to any governmental body or the public; the Trust’s systems of internal controls regarding finance, accounting, legal compliance and ethics that management and the Board have established; and the Trust’s auditing, accounting and financial reporting processes generally. Consistent with this function, the Audit Committee should endeavour to encourage continuous improvement of, and should endeavour to foster adherence to, the Trust’s policies, procedures and practices at all levels. In performing its duties, the external auditor is to report directly to the Audit Committee. The Audit Committee’s primary objectives are:

1.	To assist directors meet their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of the Trust and related matters;
2.	To provide better communication between directors and external auditors;
3.	To assist the Board’s oversight of the auditor’s qualifications and independence;
4.	To assist the Board’s oversight of the credibility, integrity and objectivity of financial reports;
5.	To strengthen the role of the outside directors by facilitating discussions between directors on the Audit Committee, management and external auditors;
6.	To assist the Board’s oversight of the performance of the Corporation’s internal audit function and independent auditors; and
7.	To assist the Board’s oversight of the Corporation’s compliance with legal and regulatory requirements.

Composition

The Audit Committee shall be comprised of three or more directors as determined by the Board of Directors, none of whom are members of management of AOG, or the Trust and all of whom are “independent” (as such term is defined in (a) National Instrument 52-110 — Audit Committees (“NI 52-110”) and (b) Section 303A.02 of the Corporate Governance Rules of the New York Stock Exchange). All of the members of the Audit Committee shall be “financially literate”. The Board of Directors has adopted the definition for “financial literacy” used in NI 52-110. Audit Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Trust or an outside consultant. In addition, at least one member of the Audit Committee must have accounting or related financial management expertise, as the Corporation’s Board of Directors interprets such qualification in its business judgment.

The members of the Audit Committee shall be elected by the Board of Directors at the annual organizational meeting of the Board of Directors and remain as members of the Audit Committee until their successors shall be duly elected and qualified. Unless a Chair is elected by the full Board of Directors, the members of the Audit Committee may designate a Chair by majority vote of the full Audit Committee membership.

In connection with the election of the members of the Audit Committee, the Board will determine whether any proposed nominee for the Audit Committee serves on the Audit Committees of more than three public companies. To the extent that any proposed nominee of AOG serves on the Audit Committees of more than three public companies, the Board will make a determination as to whether such simultaneous services would impair the ability of such member to effectively serve on AOG’s Audit Committee and will disclose such determination in Advantage’s annual information circular and annual report on Form 40-F filed with the Securities and Exchange Commission.

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Meetings

The Audit Committee shall meet at least four times annually, or more frequently as circumstances dictate. As part of its job to foster open communication, the Audit Committee should meet at least annually with management, internal auditors and the independent auditors in separate executive sessions to discuss any matters that the Audit Committee or each of these groups believe should be discussed privately. In addition, the Audit Committee or at least its Chair should meet with the independent auditors and management quarterly to review the Trust’s financials consistent with Section IV.4 below. The Audit Committee should also meet with management and independent auditors on an annual basis to review and discuss annual financial statements and the management’s discussion and analysis of financial conditions and results of operations.

A quorum for meetings of the Audit Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Audit Committee shall be the same as those governing the Board.

Responsibilities and Duties

To fulfill its responsibilities and duties, the Audit Committee shall endeavour to:

Documents/Reports Review

1.	Review and update this Charter periodically, at least annually, as conditions dictate.
2.	Review the organization’s annual and interim financial statements, MD&A, earnings press releases and any reports or other financial information submitted to any governmental body or the public, including any certification, report, opinion or review rendered by the independent auditors.
3.	Review the reports to management prepared by the independent auditors and management’s responses.
4.	Review with financial management and the independent auditors the quarterly financial statements prior to their filing or prior to the release of earnings. The Chair of the Audit Committee may represent the entire Audit Committee for purposes of this review.
5.	Review significant findings during the year, including the status of previous significant audit recommendations.
6.	Periodically assess the adequacy of procedures for the review of corporate disclosure that is derived or extracted from the financial statements.
7.	Periodically discuss guidelines and policies to govern the processes by which the Chief Executive Officer and senior management assess and manage the Corporation’s exposure to risk.
8.	Report regularly to the Board any issues that arise with respect to the quality or integrity of the Corporation’s financial statements, compliance with legal or regulatory requirements, performance and independence of the Corporation’s auditors, or performance of the internal audit function.
9.	To prepare, if required, an Audit Committee report to be included in Advantage’s annual information circular and proxy statement.
10.	Preparing an annual performance evaluation of the Audit Committee.
11.	At least annually, obtaining and reviewing the report by the independent auditors describing the Trust’s internal quality control procedures, any material issues raised by the most recent interim quality-control review, or peer review, of the Trust or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps to deal with any such issues.

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Independent Auditors

12.	Recommend to the Board the external auditors to be nominated for appointment by the unitholders.
13.	Approve the compensation of the external auditors.
14.	On an annual basis, the Audit Committee should review and discuss with the auditors all significant relationships the auditors have with the Trust to determine the auditors’ independence. In addition, the Audit Committee will ensure the rotation of the lead audit partner every five years and, in order to ensure continuing auditor independence, consider the rotation of the audit firm itself.
15.	Review and, as appropriate, resolve any material disagreements between management and the independent auditors and review, consider and make a recommendation to the Board regarding any proposed discharge of the auditors when circumstances warrant.
16.	When there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change.
17.	Periodically consult with the independent auditors, without the presence of management, about internal controls and the fullness and accuracy of the organization’s financial statements.
18.	Oversee the establishment of an internal audit function.
19.	Periodically assess the Corporation’s internal audit function, including the Corporation’s risk management processes and system of internal controls.
20.	Review the audit scope and plan of the independent auditor.
21.	Oversee the work of the external auditors engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services for the Trust.
22.	Pre-approve the completion of any non-audit services by the external auditors and determine which non-audit services the external auditor is prohibited from providing. The Audit Committee may delegate to one or more members of the Audit Committee authority to pre-approve non-audit services in satisfaction of this requirement and if such delegation occurs, the pre-approval of non-audit services by the Audit Committee member to whom authority has been delegated must be presented to the Audit Committee at its first scheduled meeting following such pre-approval. The Audit Committee shall be entitled to adopt specific policies and procedures for the engagement of non-audit services if:
		(a)	the pre-approval policies and procedures are detailed as to the particular service;
		(b)	the Audit Committee is informed of each non-audit service; and
		(c)	the procedures do not include delegation of the Audit Committee’s responsibilities to management.
		The Audit Committee will satisfy the pre-approval requirement set forth in this paragraph 22 if:
		(d)	the aggregate amount of all non-audit services that were not pre-approved is reasonably expected to constitute no more than 5% of the total amount of fees paid by the Trust and its subsidiary entities to the auditors during the fiscal year in which the services are provided;
		(e)	the Trust or the subsidiary entity, as the case may be, did not recognize the services as non-audit services at the time of the engagement;

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	(f)	the services are promptly brought to the attention of the Audit Committee and approved, prior to completion of the audit, by the Audit Committee or by one or more of its members to whom authority to grant such approvals has been delegated by the Audit Committee; and
23.	Review, setand approve hiring policies relating to staff of current and former auditors.

Financial Reporting Processes

24.	In consultation with the independent auditors, annually review the integrity of the organization’s financial reporting processes, both internal and external.
25.	In consultation with the independent auditors, consider annually the quality and appropriateness of the Corporation’s accounting principles as applied in its financial reporting.
26.	Consider and approve, if appropriate, major changes to the Trust’s auditing and accounting principles and practices as suggested by the independent auditors or management.
27.	Review risk management policies and procedures of the Trust and AOG (i.e., litigation and insurance).

Process Improvement

28.	Request reporting to the Audit Committee by each of management and the independent auditors of any significant judgments made in the management’s preparation of the financial statements and the view of each group as to appropriateness of such judgments.
29.	Following completion of the annual audit, review separately with each of management and the independent auditors any significant difficulties encountered during the course of the audit, including any restrictions on the scope of work or access to required information.
30.	Review any significant disagreements among management and the independent auditors in connection with the preparation of the financial statements.
31.	Review with the independent auditors and management the extent to which changes or improvements in financial or accounting practices, as approved by the Audit Committee, have been implemented. (This review should be conducted at an appropriate time subsequent to implementation of changes or improvements, as decided by the Audit Committee.)
32.	Conduct and authorize investigations into any matters brought to the Audit Committee’s attention and within the Audit Committee’s scope of responsibilities. The Audit Committee shall be empowered to retain and to approve compensation for any independent counsel and other professionals to assist in the conduct of any investigation.
33.	Review the systems that identify and manage principal business risks.
34.	Establish a procedure for:
		(a)	the receipt, retention and treatment of complaints received by the Trust and AOG regarding accounting, internal accounting controls or auditing matters; and
		(b)	the confidential, anonymous submission by employees of the Trust and AOG of concerns regarding questionable accounting or auditing matters;
		which procedure shall be set forth in a “whistle blower program” to be adopted by the Audit Committee in connection with such matters.

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Ethical and Legal Compliance

35.	Establish, review and update periodically a Code of Ethical Conduct and ensure that management has established a system to enforce this code.
36.	Review management’s monitoring of the Trust’s compliance with the organization’s Ethical Code.
37.	In consultation with the auditors, consider the review system established by management regarding the Corporation’s financial statements, reports and other financial information disseminated to governmental organizations and the public in the context of the applicable legal requirements.
38.	On at least an annual basis, review with the Trust’s auditors or counsel, as appropriate, any legal matters that could have a significant impact on the organization’s financial statements, the Trust’s compliance with applicable laws and regulations and inquiries received from regulators or government agencies.
39.	Review with the organization’s counsel legal compliance matters including the trading policies of securities.

Other

40.	Perform any other activities consistent with this Charter, the Trust’s and AOG’s by-laws and governing law, as the Audit Committee or the Board of Directors deems necessary or appropriate.
41.	In connection with the performance of its responsibilities as set forth above, the Audit Committee shall have the authority to engage outside advisors and to pay outside auditors and advisors.

AUDIT SERVICE FEES

Auditor Services Fees

 The following table discloses fees billed to us by our former auditors, KPMG LLP in 2007.

Type of Service Provided	2007
Audit Fees (these services included prospectus work and audit or review of financials forming part of such prospectus, U.S. GAAP reconciliation, and work related to the Sound Acquisition)	$	203,089
Audit-Related Fees (these services included French translation in connection with prospectus offerings)	$	57,508
Tax Fees (these services included review/completion of tax returns and general tax consultations)	$	110,725

 The following table discloses fees billed to us by our current auditors, PricewaterhouseCoopers LLP.

Type of Service Provided	2007		2008
Audit Fees (these services included U.S. GAAP reconciliation and work related to the Sound Acquisition)	$	694,119	$	548,292
Audit-Related Fees		Nil	$	39,904
Tax Fees (these services included review/completion of tax returns and general tax consultations)	$	25,930	$	154,976

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INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia, and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas entities of similar size. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing - Oil and Natural Gas

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to the markets, the value of refined products, the supply/demand balance, and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval of the Governor in Council.

The price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval of the Governor in Council.

The governments of Alberta, British Columbia, and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations.

Pipeline Capacity

Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market natural gas production. In addition, the pro-rationing of capacity on the inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas.

The North American Free Trade Agreement

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, United States of America, and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada United States Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price subject to an exception with respect to certain voluntary measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

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NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector by 2010 and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.

Provincial Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur, and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner’s interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years has been for provincial governments to eliminate, amend or allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

The Canadian federal corporate income tax rate levied on taxable income is 19.5% effective January 1, 2008 for active business income including resource income. With the elimination of the corporate surtax effective January 1, 2008 and other rate reductions introduced in the October 2007 Economic Statement and Notice of Ways and Means Motion, the federal corporate income tax rate will decrease to 15% in four steps: 19% on January 1, 2009, 18% on January 1, 2010, 16.5% on January 1, 2011, and 15% on January 1, 2012.

Alberta

In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents. On October 25, 2007, the Government of Alberta released a report entitled “The New Royalty Framework” (the “NRF”) containing the Government’s proposals for Alberta’s new royalty regime, which was followed by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008, which was given Royal Assent on December 2, 2008. The NRF and the applicable new legislation became effective on January 1, 2009. Prior to the NRF, the amount of royalties that were payable was influenced by the oil production, density of the oil, and the vintage of the oil. Originally, the vintage classified oil was “new oil” and “old oil” depending on when the oil pools were discovered. If the pool was discovered prior to March 31, 1974 it was considered “old oil”, if it was discovered after March 31, 1974 and before September 1, 1992, it was considered “new oil”. The Alberta Government introduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 1, 1992. The new oil royalty reserved to the Crown had a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown had a base rate of 10% and a rate cap of 35%. The NRF eliminates this classification and establishes new royalty rates for conventional oil, natural gas and oil sands. The new royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and increases the old royalty from 30% to 35% applied to the old and new tiers, to up to 50% and with rate caps once the price of conventional oil reaches $120 per barrel. The sliding rate formula includes in its calculation the price of oil and well production.

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With respect to natural gas, and similar to the conventional oil framework, the royalties outlined in the NRF are set by a single sliding rate formula ranging from 5% to 50% with a rate cap once the price of natural gas reaches $16.59/GJ. Prior to the NRF, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, was between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. In response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced on November 19, 2008, the introduction of a five year program of transitional royalty rates with the intent of promoting new drilling. Under this new program companies drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500 metres) will be given a one-time option, on a well by well basis, to adopt either the new transitional royalty rates or those outlined in the NRF. In order to qualify for this program wells must be drilled during the period starting on November 19, 2008 and ending on December 31, 2013. Following this period all new wells drilled will automatically be subject to the NRF.

Oil sands projects are now subject to the NRF, and regulated, among others, by the Oil Sands Royalty Regulation, 2009 Oil Sands Allowed Costs (Ministerial) Regulation and the Bitumen Valuation Methodology (Ministerial) Regulation, 2009, all approvedby the Government of Alberta on December 10, 2008. The rates applicable to oil sands are between 1% and 9% and are calculated depending on the price of oil. The royalty payable is 1% when oil is priced below or at $55 per barrel and it increases for every dollar over and above that price, to a maximum of 9% when oil is priced at $120 or higher. The after payout net royalty starts at 25% and increases for every dollar when oil is priced above $55 up to 40% when oil is priced at $120 or higher.

On April 10, 2008, the Government of Alberta introduced two new royalty programs that will encourage the development of deep oil and gas reserves, and these are: (a) a five-year oil program for exploration wells over 2,000 metres that will provide royalty adjustments to offset higher drilling costs and provide a greater incentive for producers to continue to pursue new, deeper oil plays (these oil wells will qualify for up to a $1 million or 12 months of royalty offsets, whichever comes first); and (b) a five-year natural gas deep drilling program that will replace the existing program in order to encourage continued deep gas exploration for wells deeper than 2,500 metres (the program will create a sliding scale of royalty credit according to depth, of up to $3,750 per metre). These new programs are to be implemented along with the NRF.

Regulations made pursuant to the Mines and Minerals Act (Alberta) provided various incentives for exploring and developing oil reserves in Alberta. However, the Alberta Government announced in August of 2006 that four royalty programs were to be amended, a new program was to be introduced and the Alberta Royalty Tax Credit Program was to be eliminated, effective January 1, 2007. The programs affected by this announcement were: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re Entry Royalty Reduction. The program introduced was the Innovative Energy Technologies Program (the “IETP”) which has a stated objective of promoting the producers’ investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. The IETP provides royalty reductions which are presumed to reduce financial risk. Alberta Energy decides which projects qualify and the level of support that will be provided. The deadline for the IETP’s final round of applications was September 20, 2008. The successful applicants for the first two rounds have been announced, and those for the third round selection are scheduled to be announced in the first half of 2009. The technical information gathered from this program is to be made public once a two year confidentiality period expires.

The NRF includes a policy of “shallow rights reversion”. The Government of Alberta started to implement this policy on January 1, 2009, and its intent is to maximize the development of currently undeveloped resources that is consistent with the Government of Alberta’s objective of maximizing recovery of known gas resources, while increasing royalty revenues. The policy’s stated objective is for the mineral rights to shallow gas geological formations that are not being developed to revert back to the Government and be made available for resale, and in the event of non-productive shallow wells, to sever the rights from shallow zones and encourage increased production from up-hole zones. The shallow rights reversion policy affects all petroleum and natural gas agreements; however, the timing of the reversion will differ depending on whether the leases and licenses were acquired prior to January 1, 2009 or subsequent to January 1, 2009. Leases granted after January 1, 2009 will be subject to shallow rights reversion at the expiry of the primary term, and in the event of a licence the policy will apply at the expiry of the intermediate term. Holders of leases or licences that have been continued indefinitely

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prior to January 1, 2009 will receive a  notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice. The lease or licence holder can make a request to extend this period. The order in which these agreements will receive the reversion notice will depend on the vintage of their term, with the older leases and licenses receiving a reversion notice first. Leases or licences that were granted prior January 1, 2009 but have not yet been continued will have a grace period until they are continued under section 15 of the P&G Tenure Regulation and be subject to deeper rights reversion prior to receiving a shallow rights reversion notice.

On March 3, 2009, the Government of Alberta announced a three-point incentive program to stimulate new and continued economic activity in Alberta which included a drilling royalty credit for new conventional oil and natural gas wells and a new well royalty incentive program. Under the drilling royalty credit program a $200 per meter royalty credit will be available on new conventional oil and natural gas wells drilled between April 1, 2009 and March 31, 2010, subject to certain maximum amounts. The maximum credits available will be determined by the company’s production level in 2008 and its drilling activity between April 1, 2009 and March 31, 2010. The new well incentive program will apply to wells beginning production of conventional oil and natural gas between April 1, 2009 and March 31, 2010 and provides for a maximum 5% royalty rate for the first 12 months of production, up to a maximum of 50,000 barrels or 500 MMcf of natural gas.

The three-point incentive program also includes an investment of $30,000,000 by the Government of Alberta in abandonment and reclamation projects for orphan wells. The stated objective of this investment is to encourage the cleanup of inactive oil and gas wells and to stimulate new activity within the services sector.

British Columbia

Producers of oil and natural gas in British Columbia are required to pay annual rental payments with respect to the Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands. The amount payable as a royalty in respect of oil depends on the type of oil, the value of the oil, the quantity of oil produced in a month, and the vintage of the oil. Generally, the vintage of oil is based on the determination of whether the oil is produced from a pool discovered before October 31, 1975 (old oil), between October 31, 1975, and June 1, 1998 (new oil), or after June 1, 1998 (third-tier oil). The royalty rates are calculated in three stages, which take into account the vintage of the oil, if the oil produced has already been sold and any royalty exempt value applicable (exempt wells). Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production or 11,450m³ produced, whichever comes first; and the royalties for third-tier oil are the lowest reflecting the higher costs of exploration and extraction that the producers would incur. The royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the price obtained by the producer, and a prescribed minimum price. However, when the reference price is below the select price (a parameter used in the royalty rate formula), the royalty rate is fixed. As an incentive for the production and marketing of natural gas, which may have been flared, natural gas produced in association with oil has a lower royalty then the royalty payable on non-conservation gas.

On May 30, 2003, the Ministry of Energy and Mines of British Columbia announced an Oil and Gas Development Strategy for the Heartlands (“Strategy”). The Strategy is a comprehensive program to address road infrastructure, targeted royalties and regulatory reduction, and British Columbia service sector opportunities. In addition, the Strategy will result in economic and employment opportunities for communities in British Columbia’s heartlands.

Some of the financial incentives in the Strategy include:

• Royalty credits towards the construction, upgrading, and maintenance of road infrastructure in support of resource exploration and development. Funding will be contingent upon an equal contribution from industry. This program has evolved over past years as a result of the Province’s stated objective to increase competitiveness, and on March 2, 2009 the Government of British Columbia announced the 2009 Infrastructure Royalty Credit Program (“Program”) which allocates $120 million in royalty credits for oil and gas companies. The Program provides access to royalty credits to oil and gas companies with respect to certain approved road construction or pipeline infrastructure projects intended to improve, or make possible, the access to new and underdeveloped oil and gas areas. Companies must apply to the Ministry of Energy and Mines for British Columbia prior to 2:00 p.m. on April 30, 2009 to be considered for approval under the program.

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• Changes to provincial royalties: new royalty rates for low productivity natural gas to enhance marginally economic resources plays, royalty credits for deep gas exploration to locate new sources of natural gas, and royalty credits for summer drilling to expand the drilling season.

The British Columbia Energy Plan announced on February 27, 2007 outlines the requirements for the development of goals for conservation, energy efficiency and clean energy. In addition, its stated goal is to promote competitiveness through the implementation of a Net Profit Royalty Program (“NPRP”) among others, and facilitate the development of the oil and gas industry. The NPRP’s objective is to share the capital risk of successful developments. Pursuant to the Net Profit Royalty Regulation, the holder of a lease can apply to pay monthly net profit royalties on production of oil and for natural gas wells within a proposed project. The amount paid is calculated on the producer’s interest in the project, and it ranges from 2% to 5% of the gross revenue and 15% to 35% of the net revenues received. In addition, it depends at which stage the well is, which may be either pre-payout, after-payout or already producing marketable gas.

The Government of British Columbia has introduced a few more royalty programs, in addition to the ones previously mentioned, including a royalty program for deep discovery wells, royalty programs with a stated goal of attracting investment to less productive shallow gas wells (Ultra-Marginal Royalty Program), and the implementation of royalty credits to assist the development of the coalbed gas reserves found in the Province of British Columbia.

Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month, and the value of the oil. For Crown royalty and freehold production tax purposes, crude oil is considered “heavy oil”, “southwest designated oil”, or “non-heavy oil other than southwest designated oil”. The conventional royalty and production tax classifications (“fourth tier oil” introduced October 1, 2002, “third tier oil”, “new oil”, and “old oil”) of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all “fourth tier oil” to 20% for “old oil”. Marginal royalty rates are 30% for all “fourth tier oil” to 45% for “old oil”.

The amount payable as a royalty in respect of natural gas is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas, and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas. The royalty and production tax classifications of gas production are “fourth tier gas” introduced October 1, 2002, “third tier gas”, “new gas”, and “old gas”. The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for “fourth tier gas” and 20% for “old gas”. The marginal royalty rates are between 30% for “fourth tier gas” and 45% for “old gas”.

On October 1, 2002, the following changes were made to the royalty and tax regime in Saskatchewan:

• A new Crown royalty and freehold production tax regime applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale and is produced from: (a) oil wells with a finished drilling date on or after October 1, 2002, and (b) oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of more than 3,500 cubic metres of gas for every cubic metre of oil. The royalty/tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65,000 cubic metres in a month. The associated natural gas royalty/tax regime will apply to gas produced from oil wells affected by concurrent production approvals after October 1, 2002 if the oil wells meet (a) or (b) above.

• A modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from oil wells and gas wells with a finished drilling date on or after October 1, 2002, was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of zero per cent.

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• The elimination of the re-entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002, will receive the “fourth tier” royalty/ tax rates and new incentive volumes.

• A horizontal oil well, with a finished drilling date on or after October 1, 2002, that is a non-deep oil well qualifies for a 6,000 cubic metre incentive volume.

• A horizontal oil well, with a finished drilling date on or after October 1, 2002, that is a deep oil well qualifies for a 16,000 cubic metre incentive volume.

In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate (“RTR”) as a response to the Government of Canada disallowing crown royalties and similar taxes as a deductible business expense for income tax purposes. As of January 1, 2007, the remaining balance of any unused RTR will be limited in its carry forward to seven years since the Government of Canada’s initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income. Saskatchewan’s RTR will be wound down as a result of the Government if Canada’s plan to reintroduce full deductibility of provincial resource royalties for corporate income tax purposes.

On June 19, 2007, the Government of Saskatchewan introduced the Orphan Well and Facility Liability Management Program pursuant to the amendment of the Oil and Gas ConservationAct and the Oil and Gas Conservation Regulations, 1985. The program includes a security deposit, which has two purposes: (i) preventing any person with insufficient financial capability from acquiring oil and gas wells or facilities; and (ii) in the case of a bankrupt company, the funds cover the decommissioning and reclaiming of orphan properties. An additional change introduced is the mandatory licensing of all upstream oil and gas facilities in Saskatchewan.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms from two years, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

Environmental legislation in Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the “EPEA”), which came into force on September 1, 1993, and the Oil and Gas Conservation Act (Alberta) (the ”OGCA”). The EPEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations, and significantly increased penalties. In 2006, the Alberta Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide emissions from industrial operations including the oil and gas industry. In addition, the reduction emission guidelines outlined in the Climate Change and Emissions Management Amendment Act came into effect on July 1, 2007 (“CCEMAA”). Under this legislation, Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emissions intensity by 12%. Industries have three options to choose from in order to meet the reduction requirements outlined in this legislation, and these are: (i) by making improvement to operations that result in reductions; (ii) by purchasing emission credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emission; or (iii) by contributing to the Climate Change and Emissions Management Fund (the “Fund”). Industries can either

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choose one of these options or a combination thereof. Pursuant to CCEMAA and the Specified Gas Emitters Regulation, companies were obliged to reduce their emission intensity by 12% by March 31, 2008. Alberta industries have achieved 2.6 million tonnes of actual reduction, due to changes in operations and investing on verified offset projects. In addition, certain companies contributed $40 million to the Fund. It is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

On January 24, 2008, the Alberta Government announced a new climate change action plan that will cut Alberta’s projected 400 million tonnes of emissions in half by 2050. This plan is based on three areas: (i) carbon capture and storage, which will be mandatory for in situ oil sand facilities that use heavy fuels for steam generation; (ii) energy conservation and efficiency; and (iii) greening production through increased investment in clean energy technology, including supporting research on new oil sands extraction processes, as well as the funding of projects that reduce the cost of separating carbon dioxide from other emissions supporting carbon capture and storage. In addition to this action plan, the Provincial Energy Strategy unveiled on December 11, 2008 is expected to, among other things, support the upgrading, refining and petrochemical clusters existing in the Province, market Alberta’s energy internationally, review the emission targets and carbon charges applied to large facilities, and promote the innovation of energy technology by encouraging investment in research and development.

British Columbia’s Environmental Assessment Act became effective June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental review process. On February 27, 2007 the Government of British Columbia unveiled the Energy Plan outlining its strategy towards the environment and which includes targeting for zero net greenhouse gas emissions, promoting new investments in innovation, and becoming the world’s leader in sustainable environmental management. For this purpose, on December 18, 2007 proposals were sought for applications to the Innovative Clean Energy Fund, in order to attract new technologies that will help solve energy and environmental issues. With regards to the oil and natural gas industry the objective is to achieve clean energy through conservation and energy efficient practices, whilst competitiveness is advocated in order to attract investment for the development of the oil and natural gas sector. Among the changes to be implemented are: (i) a new of Net Profit Royalty Program; (ii) the creation of a Petroleum Registry; (iii) the establishment of an infrastructure royalty program (combining roads and pipelines); (iv) the elimination of routine flaring at producing wells; (v) the creation of policies and measures for the reduction of emissions; (vi) the development of unconventional resources such as tight gas and coalbed gas; and (vii) new the Oil and Gas Technology Transfer Incentive Program that encourages the research, development and use of innovative technologies to increase recoveries from existing reserves and promotes responsible development of new oil and gas reserves. Furthering these initiatives, the Government of British Columbia introduced on July 1, 2008, revenue-neutral carbon tax legislation that is applied to all fossil fuels used in the Province of British Columbia. The tax would be phased in, and the initial rate would be based on CO2e of $10 per tonne for the first six months of 2009 and $15 per tonne for the last six months of 2009, following $5 per tonne increases on July of every year until 2012. Tax credits and reductions will be used in order to offset the tax revenues that the Government of British Columbia would receive otherwise. On April 3, 2008, the Government of British Columbia introduced the Greenhouse Gas Reduction (Cap and Trade) Act which will allow participation in the Western Climate Initiative cap and trade systems being developed. The system establishes a limit on emissions, and allows regulated emitters to buy/sell emission allowances or offset emits. The emitter is obliged to obtain emission allowances (compliance units) equal to the amount of greenhouse gases emitted within a certain period of time, and that are supposed to be surrendered to the Government of British Columbia as compliance proof.

In December 2002, the Government of Canada ratified the Kyoto Protocol (“Kyoto Protocol”). The Kyoto Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 “business-as-usual” levels between 2008 and 2012. Given revised estimates of Canada’s normal emissions levels, this target translates into an approximately 40% gross reduction in Canada’s current emissions. It is questionable, based on the Updated Action Plan announced by the Federal Government (see below), that the Kyoto Protocol target of 6% below 1990 emission levels will be enforced in Canada. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007. On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the “Action Plan”) also known as ecoACTION which includes the regulatory framework for air emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy using products.

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The Government of Canada and the Province of Alberta released on January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends among others: (i) incorporating carbon capture and storage into Canada’s clean air regulations; (ii) allocating new funding into projects through competitive process; and (iii) targeting research to lower the cost of technology.

In order to strengthen the Action Plan, on March 10, 2008, the Government of Canada released “Turning the Corner – Taking Action to Fight Climate Change” (the “Updated Action Plan”) which provides some additional guidance with respect to the Government’s plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.

The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including the oil sands, oil and gas and refining. The Updated Action Plan is intended to create a carbon emissions trading market, including an offset system, to provide incentive to reduce greenhouse gas emission and establish a market price for carbon. There are mandatory reductions of 18% from the 2006 baseline starting in 2010 and an additional 2% in subsequent years for existing facilities. This target will be applied to regulated sectors on a facility-specific, sector-wide or corporate basis; in the case of oil sands production, petroleum refining, natural gas pipelines and upstream oil and gas the target will be considered facility-specific (sectors in which the facilities are complex and diverse, or where emissions are affected by factors beyond the control of the facility operator). Emissions from new facilities, which are those built between 2004 and 2011, will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time, and will be granted a 3-year grace period during which no emissions intensity targets will apply. Targets will begin to apply on the fourth year of commercial operation and the baseline will be the third year’s emissions intensity, with a 2% continuous annual emission intensity improvement required. The definition of new facility also includes greenfield facilities, major expansions constituting more than a 25% increase in a facility’s physical capacity, as well as transformations to a facility that involve significant changes to its processes. For upstream oil and gas and natural gas pipelines, it will be applied using a sector-specific approach. For the oil sands, its application will be process-specific, oil sands plants built in 2012 and later, those which use heavier hydrocarbons, up-graders and in-situ production will have mandatory standards in 2018 that will be based on carbon capture and storage.

In the following regulated sectors, the Updated Action Plan will apply only to facilities exceeding a minimum annual emissions threshold: (i) 50,000 tonnes of CO2 equivalent per year for natural gas pipelines; (ii) 3,000 tonnes of CO2 equivalent per upstream oil and gas facility; and (iii) 10,000 boe/d/company. These proposed thresholds are significantly stricter than the current Alberta regulatory threshold of 100,000 tonnes of CO2 equivalent per year per facility.

Four separate compliance mechanisms are provided in respect of the above targets: Technology Fund contributions, offset credits, clean development credits and credits for early action. The most significant of these compliance mechanisms, at least initially, will be the Technology Fund and for which regulated entities will be able to contribute in order to comply with emissions intensity reductions. The contribution rate will increase over time, beginning at $15 per tonne for the 2010-12 period, rising to $20 per tonne in 2013, and thereafter increasing at the nominal rate of GDP growth. Contribution limits will correspondingly decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as mentioned above.

The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing non-regulated entities to participate in and benefit from emissions reduction activities. In order to generate offset credits, project proponents must propose and receive approval for emissions reduction activities that will be verified before offset credits will be issued to the project proponent. Those credits can then be sold to regulated entities for use in compliance or non-regulated purchasers that wish to either cancel the offset credits or bank them for future use or sale.

Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Kyoto Protocol. The purchase of such Emissions Reduction Credits will be restricted to 10% of each firm’s regulatory obligation, with the added restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations.

Finally, a one-time credit of up to 15 million tonnes worth of emissions credits will be awarded to regulated entities for emissions reduction activities undertaken between 1992 and 2006. These credits will be both tradable and bankable.

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Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not currently possible to predict either the nature of those requirements or the impact on the Trust and its operations and financial condition at this time.

Trends

There are a number of trends that have been developing in the oil and gas industry during the past several years that appear to be shaping the near future of the business.

The first trend is the volatility of commodity prices. Natural gas is a commodity influenced by factors within North America. A tight supply-demand balance for natural gas causes significant elasticity in pricing, whereas higher than average storage levels tend to depress natural gas pricing. Drilling activity, weather, fuel switching and demand for electrical generation are all factors that affect the supply-demand balance. Changes to any of these or other factors create price volatility.

Crude oil is influenced by the world economy, Organization of the Petroleum Exporting Countries’ ability to adjust supply to world demand and weather. Crude oil prices have been kept high by political events causing disruptions in the supply of oil and concern over potential supply disruptions triggered by unrest in the Middle East and more recently have been impacted by weather and increased storage levels. Political events trigger large fluctuations in price levels.

The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. Purchasing land and properties similarly increase in price during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline.

A second trend within the Canadian oil and gas industry is the fairly consistent “renewal” of private and small junior oil and gas companies starting up business. These companies often have experienced management teams from previous industry organizations that have disappeared as a part of the ongoing industry consolidation. Many are able to raise capital and recruit well qualified personnel. We will have to compete with these companies and others to attract qualified personnel.

A third trend currently affecting the oil and gas industry is the impact on capital markets caused by investor uncertainty in the North American economy. The capital market volatility in Canada has also been affected by uncertainties surrounding the economic impact that the Protocol, and other environmental initiatives, will have on the sector and, in more recent times, by the enactment of the SIFT Tax legislation relating to trusts, pursuant to which trusts, such as the Trust, will be liable for tax at a rate consistent with the taxes currently imposed on corporations. The tax will not commence until January 2011, so long as the SIFT experiences only “normal growth” and no “undue expansion”. See “Risk Factors – Changes in Legislation – SIFT Tax”.

Generally during the past year, the economic recovery combined with increased commodity prices has caused an increase in new equity financings in the oil and gas industry, although the level of same was negatively impacted by enactment of the SIFT Tax. We will compete with numerous new companies and their new management teams and development plans in its access to capital. The competitive nature of the oil and gas industry will cause opportunities for equity financings to be selective. We may have to rely on internally generated funds to conduct our exploration and developmental programs.

RISK FACTORS

The following is a summary of certain risk factors relating to the business of AOG and the Trust. The following information is a summary only of certain risk factors and is qualified in its entirety by reference to, and must be read in conjunction with, the detailed information appearing elsewhere in this annual information form.

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Dependence on AOG

We are an open-ended, limited purpose trust which will be entirely dependent upon the operations and assets of AOG through our ownership of the Common Shares, the Notes and the Royalty. Accordingly, the cash distributions to our Unitholders will be dependent upon the ability of AOG to meet its interest and principal repayment obligations under the Notes, to declare and pay dividends on the Common Shares, and to pay the Royalty. AOG’s income will be received from the production of oil and natural gas from AOG’s existing Canadian resource properties and will be susceptible to the risks and uncertainties associated with the oil and natural gas industry generally. AOG is generally not involved in the exploration for oil and natural gas. As a result, if the oil and natural gas reserves associated with AOG’s Canadian resource properties are not supplemented through additional development or the acquisition of additional Oil and Natural Gas Properties, the ability of AOG to meet its obligations to us may be adversely affected.

Global Financial Crisis

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to commodity prices. These conditions worsened in 2008 and are continuing in 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. These factors have negatively impacted company valuations and will impact the performance of the global economy going forward.

Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing global credit and liquidity concerns.

Advantage May Not Realize the Anticipated Benefits of the Trust Conversion

Advantage is proposing to complete the Trust Conversion combined with the asset disposition program and the debt reduction initiative in order to pursue the significant development potential at Glacier, to continue development of its conventional assets and to remove the uncertainty surrounding the upcoming changes in Canadian tax law whereby the government will begin imposing taxes on income trusts on January 1, 2011.  Achieving the benefits of the Trust Conversion depends in part on the ability of New Advantage to realize the anticipated growth opportunities.  A variety of factors, including those risk factors set forth in this Annual Information Form, may affect the ability to achieve the anticipated benefits of the Trust Conversion.

Failure to Obtain Necessary Approvals for Completion of the Trust Conversion

The completion of the Trust Conversion is subject to a number of conditions precedent, certain of which are outside the control of Advantage, including receipt of the required Unitholder, court and regulatory approvals.  There can be no certainty, nor can Advantage provide any assurance, that these conditions will be satisfied or, if satisfied, when they will be satisfied.

Failure to Complete the Disposition of Assets

We have retained Tristone Capital Inc. to assist with the disposition of up to 11,300 boe/d of light oil and liquids rich natural gas properties.  There can be no certainty, nor can Advantage provide any assurance, that the Disposition of Assets will be completed or, if completed, when it will be completed.

Oil and Natural Gas Prices

AOG’s results of operations and financial condition and the monthly cash distributions we pay to Unitholders are highly dependent upon the prices received for AOG’s oil and natural gas production. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of us and AOG. These factors include, among others:

• global energy policy, including the ability of OPEC to set and maintain production levels and prices for oil;

• political conditions throughout the world, including the risk of hostilities in the Middle East and global terrorism;

• worldwide economic conditions;

• weather conditions;

• the supply and price of foreign oil and natural gas;

• the level of consumer demand;

• the price and availability of alternative fuels;

• the proximity to, and capacity of, transportation facilities;

• the effect of worldwide energy conservation measures; and

• government regulations.

Declines in oil or natural gas prices will have an adverse effect upon our operations, financial condition, reserves and ultimately on our ability to pay distributions to Unitholders.

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We may manage the risk associated with changes in commodity prices by entering into oil or natural gas price hedges. If we hedge our commodity price exposure, we will forego the benefits it would otherwise experience if commodity prices were to increase. In addition, commodity hedging activities could expose us to losses. To the extent that we engage in risk management activities related to commodity prices, we will be subject to credit risks associated with counterparties with which we contract.

Oil prices were relatively high throughout 2008 averaging US$99.65WTI as compared to an average of US$72.37 WTI in 2007, an increase of 38%.

AECO monthly index prices averaged $8.13/Mcf in 2008 as compared to $6.61/Mcf in 2007, an increase of23%. The price of oil and natural gas will fluctuate and price and demand are factors beyond our control. Such fluctuations will have a positive or negative effect upon the revenue to be received. Such fluctuations will also have an effect upon the acquisition costs of any future Oil and Natural Gas Properties that we may acquire. As well, cash distributions from us will be highly sensitive to the prevailing price of crude oil and natural gas.

Exploitation and Development

Exploitation and development risks are due to the uncertain results of searching for and producing oil and natural gas using imperfect scientific methods. These risks are mitigated by using highly skilled staff, focusing exploitation efforts in areas in which we have existing knowledge and expertise or access to such expertise, using up-to-date technology to enhance methods, and controlling costs to maximize returns. Advanced oil and natural gas related technologies such as three-dimensional seismography, reservoir simulation studies and horizontal drilling have been and will be used by us to improve our ability to find, develop and produce oil and natural gas.

Operating Costs and Production Declines

Higher operating costs for the underlying properties of AOG will directly decrease the amount of cash flow received by us and, therefore, may reduce distributions to our Unitholders. Electricity, chemicals, supplies, reclamation and abandonment and labour costs are a few of AOG’s operating costs that are susceptible to material fluctuation.

The level of production from AOG’s existing properties may decline at rates greater than anticipated due to unforeseen circumstances, many of which are beyond AOG’s control. A significant decline in production could result in materially lower revenues and cash flow and, therefore, could reduce the amount available for distributions to Unitholders.

Operations

AOG’s operations are subject to all of the risks normally incident to the operation and development of Oil and Natural Gas Properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, blow-outs, craterings and fires, all of which could result in personal injuries, loss of life and damage to the property of AOG and others. AOG has both safety and environmental policies in place to protect its operators and employees, as well as to meet the regulatory requirements in those areas where it operates. In addition, AOG has liability insurance policies in place, in such amounts as it considers adequate, however, it will not be fully insured against all of these risks, nor are all such risks insurable. Costs incurred to repair any of such damage or pay any of such liabilities will reduce Royalty Income.

Continuing production from a property, and, to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property. To the extent the operator fails to perform these functions properly, revenue may be reduced. Payments from production generally flow through the operator and there is a risk of delay and additional expense in receiving such revenues if the operator becomes insolvent. Although satisfactory title reviews are generally conducted in accordance with industry standards, such reviews do not guarantee or certify that a defect in the chain of title may not arise to defeat the claim of AOG to certain Properties. A reduction of the income from the Royalty could result in such circumstances.

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Prices, Markets and Marketing

The marketability and price of oil and natural gas that may be acquired or discovered by the Trust is and will continue to be affected by numerous factors beyond its control. The Trust’s ability to market its oil and natural gas may depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets. The Trust may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.

The prices of oil and natural gas prices may be volatile and subject to fluctuation. Any material decline in prices could result in a reduction of the Trust’s net production revenue. The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or gas and a reduction in the volumes of the Trust’s reserves. The Trust might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in the Trust’s expected net production revenue and a reduction in its oil and gas acquisition, development and exploration activities. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Trust. These factors include economic conditions, in the United States and Canada, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. Any substantial and extended decline in the price of oil and gas would have an adverse effect on the Trust’s carrying value of its proved reserves, borrowing capacity, revenues, profitability and cash flows from operations.

Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing credit and liquidity concerns. Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

In addition, bank borrowings available to the Trust may, in part, be determined by the Trust’s borrowing base. A sustained material decline in prices from historical average prices could reduce the Trust’s borrowing base, therefore reducing the bank credit available to the Trust which could require that a portion, or all, of the Trust’s bank debt be repaid.

Royalties

In Alberta, the Crown royalty rates on conventional oil and natural gas fluctuate, depending on when a well was drilled, well depth, well production volume and the price of oil and natural gas. On October 25, 2007, the Alberta provincial government introduced a new royalty regime, which became effective on January 1, 2009 and is applicable to all existing conventional oil and natural gas wells in Alberta. The new royalty regime assesses the applicable royalty rate on a well by well basis using a sliding scale which takes into account the price of oil and natural gas and well production volumes. On November 19, 2008 and November 24, 2008 the Alberta provincial government announced details of an optional five year transitional royalty program that applies to conventional oil and natural gas wells drilled to measured depths between 1,000 to 3,500 meters between November 19, 2008 and January 1, 2014. For each well, the Trust can make a one-time election to produce the well under the transitional royalty program or the new royalty regime. As of January 1, 2014, all production subject to the transitional program will revert to the new royalty regime. Subsequent to these changes to the royalty structure, the Alberta provincial government has launched a study of the competitiveness of Alberta’s conventional oil and gas business. Terms of reference have not been made public; however, it is possible that the royalty regime may be subject to further review.

These changes to the Alberta royalty regime, as well as the potential for changes in the royalty regimes applicable in other provinces have created uncertainty surrounding the ability to accurately estimate future royalties, resulting in additional volatility and uncertainty for producers.

Capital Investment

To the extent that AOG uses cash flow to finance acquisitions, development costs and other significant expenditures, the net cash flow of the Trust will be reduced. Hence, the timing and amount of capital expenditures may affect the amount of net cash flow available to us and, as a consequence, the amount of cash available to distribute to Unitholders.  Therefore, distributions may be reduced, or even eliminated, at times when significant capital or other expenditures are made.

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The AOG Board of Directors has the discretion to determine the extent to which cash flow will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including under the credit facility. As a consequence, the amount of funds retained by AOG to pay debt services charges or reduce debt will reduce the amount of cash distributed to Unitholders during those periods in which funds are so retained.

Assessments of Value of Acquisitions

Acquisitions of resource issuers and resource assets will be based in large part upon engineering and economic assessments made by independent engineers. These assessments will include a series of assumptions regarding such factors as recoverability and marketability of oil and gas, future prices of oil and gas and operating costs, future capital expenditures and royalties and other government levies which will be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our control. In particular, the prices of and markets for resource products may change from those anticipated at the time of making such assessment. In addition, all such assessments involve a measure of geologic and engineering uncertainty which could result in lower production and reserves than anticipated. Initial assessments of acquisitions may be based upon reports by a firm of independent engineers that are not the same as the firm that we use for our year end reserve evaluations. Because each of these firms may have different evaluation methods and approaches, these initial assessments may differ significantly from the assessments of the firm used by us. Any such instance may offset the return on and value of the Trust Units.

Debt Service

AOG has credit facilities in the amount of $710,000,000. Variations in interest rates and scheduled principal repayments could result in significant changes in the amount required to be applied to debt service before payment of any amounts to us. Although it is believed that the bank line of credit is sufficient, there can be no assurance that the amount will be adequate for the financial obligations of AOG or that additional funds can be obtained.

The lenders have been provided with security over substantially all of the assets of AOG. If AOG becomes unable to pay its debt service charges or otherwise commits an event of default such as bankruptcy, the lenders may foreclose on or sell the Properties free from or together with the Royalty. The payment of interest and principal on debt may also result in us or our subsidiaries having taxable income and cash taxes payable as taxable income would no longer be reduced by royalty payments at the time debt repayment occurs.

Prior Ranking Indebtedness; Absence of Covenant Protection

The Debentures will be subordinate to all Senior Indebtedness and to any indebtedness of our creditors. The payment of principal and interest on the Debentures will be subordinated to the Senior Indebtedness of us and to indebtedness of our trade creditors. The Debentures will also be effectively subordinate to claims of creditors of our subsidiaries except to the extent we are a creditor of such subsidiaries ranking at least pari passu with such other creditors.

The Indentures will not limit the ability of us to incur additional liabilities (including Senior Indebtedness) or to make distributions, except, in respect of distributions, where an Event of Default has occurred or would occur and such default has not been cured or waived. The Indentures do not contain any provision specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving Advantage. However, the Indentures, among other things, restrict our level of indebtedness, provide operating investment guidelines, mandate the making of distributions and specify the nature of our business.

Environmental Concerns

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in

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stricter standards and enforcement,  larger fines and liability and potentially increased capital expenditures and operating costs. In 2002, the Government of Canada ratified the Protocol which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada’s ability to meet these targets and the Government’s strategy or alternative strategies with respect to climate change and the control of greenhouse gases.

On March 10, 2008, the Government of Canada released “Turning the Corner – Taking Action to Fight Climate Change” (the “Updated Action Plan”) which provides some additional guidance with respect to the Government’s plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.

The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including the oil sands, oil and gas and refining. The Updated Action Plan is intended to create a carbon emissions trading market, including an offset system, to provide incentive to reduce greenhouse gas emission and establish a market price for carbon. There are mandatory reductions of 18% from the 2006 baseline starting in 2010 and an additional 2% in subsequent years for existing facilities. This target will be applied to regulated sectors on a facility-specific, sector-wide or corporate basis; in the case of oils sands production, petroleum refining, natural gas pipelines and upstream oil and gas the target will be considered facility-specific (sectors in which the facilities are complex and diverse, or where emissions are affected by factors beyond the control of the facility operator). Emissions from new facilities, which are those built between 2004 and 2011, will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time, and will be granted a 3-year grace period during which no emissions intensity targets will apply. Targets will begin to apply on the fourth year of commercial operation and the baseline will be the third year’s emissions intensity, with a 2% continuous annual emission intensity improvement required. The definition of new facility also includes greenfield facilities, major expansions constituting more than a 25% increase in a facility’s physical capacity, as well as transformations to a facility that involve significant changes to its processes. For upstream oil and gas and natural gas pipelines, it will be applied using a sector-specific approach. For the oil sands, its application will be process-specific, oil sands plants built in 2012 and later, those which use heavier hydrocarbons, up-graders and in-situ production will have mandatory standards in 2018 that will be based on carbon capture and storage.

In the following regulated sectors, the Updated Action Plan will apply only to facilities exceeding a minimum annual emissions threshold: (i) 50,000 tonnes of CO2 equivalent per year for natural gas pipelines; (ii) 3,000 tonnes of CO2 equivalent per upstream oil and gas facilities; and (iii) 10,000 boe/d/company. These proposed thresholds are significantly stricter than the current Alberta regulatory threshold of 100,000 tonnes of CO2 equivalent per year per facility.

Four separate compliance mechanisms are provided in respect of the above targets: Technology Fund contributions, offset credits, clean development credits and credits for early action. The most significant of these compliance mechanisms, at least initially, will be the Technology Fund and for which regulated entities will be able to contribute in order to comply with emissions intensity reductions. The contribution rate will increase over time, beginning at $15 for the 2010-12 period, rising to $20 in 2013, and thereafter increasing at the nominal rate of GDP growth. Contribution limits will correspondingly decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as mentioned above.

The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing non-regulated entities to participate in and benefit from emissions reduction activities. In order to generate offset credits, project proponents must propose and receive approval for emissions reduction activities that will be verified before offset credits will be issued to the project proponent. Those credits can then be sold to regulated entities for use in compliance or non-regulated purchasers that wish to either cancel the offset credits or bank them for future use or sale.

Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Protocol. The purchase of such Emissions Reduction Credits will be restricted to 10% of each firm’s regulatory obligation, with the added restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations.

Finally, a one-time credit of up to 15 Mt worth of emissions credits will be awarded to regulated entities for emissions reduction activities undertaken between 1992 and 2006. These credits will be both tradable and bankable.

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Implementation of strategies for reducing greenhouse gases whether to meet the limits required by the Protocol or the new regulatory framework, could have a material impact on the nature of oil and natural gas operations, including those of the Trust. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict at this time either the nature of those requirements or the impact on the Trust and its operations and financial condition. Although AOG estimates its future environmental and reclamation obligations based upon its current knowledge, there can be no assurance that we will be able to satisfy our actual future environmental and reclamation obligations.

Although AOG maintains insurance coverage considered to be customary in the industry, it is not fully insured against certain environmental risks, either because such insurance is not available, or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (compared to sudden and catastrophic damages) is not available. Accordingly, AOG’s properties may be subject to liability due to hazards which cannot be insured against, or have not been insured against due to prohibitive premium costs or for other reasons. In such an event, these environmental obligations will be funded out of AOG’s cash flow and could therefore reduce distributable income payable to Unitholders.

Unforeseen Title Defects

Although title reviews are generally conducted prior to any purchase of resource issuers or resource assets, such reviews do not guarantee that an unforeseen defect in the chain of title will not arise to defeat AOG’s title to certain assets. A reduction of the distributable cash flow of the Trust and possible reduction of capital could result from such defects.

Any site reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period will be funded out of cash flow and, therefore, will reduce the amounts available for distribution to Unitholders. Should we be unable to fully fund the cost of remedying an environmental problem, it might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

Foreign Currency Exchange Rates and Interest Rates

World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the $Cdn/$US exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar, which occurred in 2007, negatively impacted our net production revenue and may affect the future value of our reserves as determined by independent evaluations at this time. The Canadian dollar remained steady in 2008 at an average $0.94 US/Cdn compared to approximately the same amount in 2007. The impact is reduced to the extent that we have engaged in, or in the future will engage in risk management activities related to commodity prices and foreign exchange rates. We will be subject to unfavourable price changes and credit risks associated with the counterparties with which it contracts. We have not entered into any foreign exchange contracts at this time.

Variations in interest rates could result in a significant increase in the amount we pay to service debt which may result in a decrease in distributions to Unitholders, as well as impact the market price of the Trust Units on the TSX and the NYSE.

Reliance upon the Senior Executives of AOG

Unitholders will be dependent upon the management of AOG in respect of the administration and management of all matters relating to the Properties, the Royalty, the Trust and the Trust Units. The loss of the services of

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key individuals who currently comprise our management team could have a detrimental effect upon us. Investors who are not willing to rely on the management of AOG should not invest in the Trust Units.

Reserves

The value of the Trust Units will depend upon, among other things, the reserves attributable to our properties. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for our properties will vary from estimates and those variations could be material. The reserve and cash flow information contained in this annual information form represent estimates only. Reserves and estimated future net cash flow from our properties have been independently evaluated at the dates indicated by independent oil and gas reservoir engineering firms. These firms consider a number of factors and make assumptions when estimating reserves. These factors and assumptions include:

• historical production in the area compared with production rates from similar producing areas;

• the assumed effect of governmental regulation;

• assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures;

• initial production rates;

• production decline rates;

• ultimate recovery of reserves;

• timing and amount of capital expenditures;

• marketability of production;

• future prices of oil and natural gas;

• operating costs and royalties; and

• other government levies that may be imposed over the producing life of reserves.

These factors and assumptions were based upon prices at the date the relevant evaluations were prepared. If these factors and assumptions prove to be inaccurate, actual results may vary materially from the reserve estimates. Many of these factors are subject to change and are beyond our control. For example, evaluations are based in part upon the assumed success of exploitation activities intended to be undertaken in future years. Actual reserves and estimated cash flows will be less than those contained in the evaluations to the extent that such exploitation activities do not achieve the level of success assumed in the evaluations. Furthermore, cash flows may differ from those contained in the evaluations depending upon whether capital expenditures and operating costs differ from those estimated in the evaluations.

Depletion of Reserves

We have certain unique attributes that differentiate it from other oil and gas industry participants. Distributions of distributable income in respect of Properties, absent commodity price increases or cost effective acquisition and development activities will decline over time in a manner consistent with declining production from typical oil, natural gas and natural gas liquids reserves. AOG will not be reinvesting cash flow in the same manner as other industry participants. Accordingly, absent capital injections, AOG’s initial production levels and reserves will decline.

AOG’s future oil and natural gas reserves and production, and therefore its cash flows, will be highly dependent upon AOG’s success in exploiting its reserve base and acquiring additional reserves. Without reserve additions through acquisition or development activities, AOG’s reserves and production will decline over time as reserves are exploited.

To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, AOG’s ability to make the necessary capital investments to maintain or expand its oil and natural gas reserves will be impaired. To the extent that AOG is required to use cash flow to finance capital expenditures or property acquisitions, the level of distributable income will be reduced.

There can be no assurance that we will be successful in developing or acquiring additional reserves on terms that meet our investment objectives.

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Reliance upon Third Party Operators

Continuing production from a property and marketing of product produced from the property are dependent to a large extent upon the ability of the operator of the property. We currently operate properties that represent approximately 85% of our total daily production. To the extent the operator fails to perform these functions properly or becomes insolvent, revenue may be reduced.

Enforcement of Operating Agreements

Operations of the wells on properties not operated by us are generally governed by operating agreements, which typically require the operator to conduct operations in a good and workmanlike manner. Operating agreements generally provide, however, that the operator will have no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except such as may result from gross negligence or wilful misconduct. In addition, third-party operators are generally not fiduciaries with respect to us or our Unitholders. As an owner of working interests in properties we do not operate, we will generally have a cause of action for damages arising from a breach of such duty. Although not established by definitive legal precedent, it is unlikely that the Trust or Unitholders would be entitled to bring suit against third-party operators to enforce the terms of the operating agreements; thus, Unitholders will be dependent upon us, as owner of the working interest, to enforce such rights.

Changes in Legislation – SIFT Tax

On October 31, 2006, the Department of Finance (Canada) (“Finance”) announced proposed changes to the taxation of certain publicly-traded trusts and partnerships and their unitholders. Bill C-52, which received Royal Assent on June 22, 2007, contained legislation implementing these proposals (collectively, the “SIFT Rules”).

The SIFT Rules apply to trusts and partnerships that are resident in Canada for purposes of the Tax Act (in the case of partnerships, pursuant to new residency rules for this purpose), that hold one or more “non-portfolio properties”, and the units of which are listed on a stock exchange or other public market (a “SIFT trust” or a “SIFT partnership”, as the case may be). In the case of a trust that was a SIFT trust on October 31, 2006, the SIFT Rules generally will not take effect until January 1, 2011, provided the SIFT trust experiences only “normal growth” and no “undue expansion” before then. On December 15, 2006 Finance issued guidelines with respect to what would be considered “normal growth” for this purpose (the “Guidelines”).

The Trust would be a “SIFT trust” under the SIFT Rules but for the deferred implementation described above. Pursuant to the SIFT Rules, a SIFT trust will be subject to tax on its income from non-portfolio properties and taxable capital gains from dispositions of non-portfolio properties at a rate comparable to the combined federal and provincial corporate income tax rate and distributions of such income to unitholders will be treated as eligible dividends paid by a taxable Canadian corporation. The properties owned by the Trust would constitute “non-portfolio properties” under the SIFT Rules, with the result that all or substantially all of the Trust’s income would be subject to the new tax. As a result, the SIFT Rules will result in adverse consequences to the Trust and certain Unitholders (including most particularly Unitholders that are tax deferred, or non-residents of Canada) and may impact cash distributions from the Trust.

The SIFT Rules provide that the tax rate will be the federal general corporate income tax rate (which is anticipated to be 16.5% in 2011 and 15% in 2012) plus the provincial SIFT tax rate.

The provincial SIFT tax rate will be based on the general provincial corporate income tax rate in each province in which the Trust has a permanent establishment. For purposes of calculating this component of the tax, the general corporate taxable income allocation formula will be used. Specifically, the Trust’s taxable distributions will be allocated to provinces by taking half of the aggregate of:

• that proportion of the Trust’s taxable distributions for the year that the Trust’s wages and salaries in the province are of its total wages and salaries in Canada; and

• that proportion of the Trust’s taxable distributions for the year that the Trust’s gross revenues in the province are of its total gross revenues in Canada.

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It is anticipated that the Trust would be considered to have a permanent establishment only in Alberta, where the provincial tax rate in 2011 is expected to be 10%, which will result in an effective tax rate of 26.5% in 2011.

Although the SIFT Rules are not expected to effect the Trust until 2011, the Trust could become subject to the SIFT Rules sooner if it experiences growth other than “normal growth” before then. Under the Guidelines, a SIFT trust will be considered to have experienced only “normal growth” if its issuances of new equity, which includes trust units and debt convertible into trust units, do not exceed certain thresholds measured by reference to the SIFT trust’s market capitalization as of the close of trading on October 31, 2006, taking into account only the SIFT trust’s publicly-traded units and not any securities, whether or not listed, that are convertible into or exchangeable for units. The permitted expansion thresholds are the greater of $50 million and 40% of a SIFT trust’s October 31 market capitalization for the period from October 31, 2006 to the end of 2007, and the greater of $50 million and 20% of a SIFT trust’s October 31 market capitalization for each of 2008, 2009 and 2010. On December 4, 2008, Finance announced changes to the Guidelines to allow a SIFT trust to accelerate the utilization of the SIFT trust’s annual safe harbour amount for each of 2009 and 2010 so that the safe harbour amount is available on and after December 4, 2008. This change does not alter the maximum permitted expansion threshold for a SIFT trust, but it allows a SIFT trust to use its normal growth room remaining as of December 4, 2008 in a single year, rather than staging a portion of the normal growth room over the 2009 and 2010 years.

While it is unlikely that the restrictions on “normal growth” will affect our ability to raise the capital required to maintain and grow our existing operations in the ordinary course, such restrictions could adversely affect the cost of raising capital and our ability to undertake more significant acquisitions.

The introduction of the SIFT Rules has reduced the value of the Trust Units, which has increased the cost to the Trust of raising capital in the public capital markets. In addition management of AOG believes that the SIFT Rules: (a) substantially eliminate the competitive advantage that the Trust and other Canadian energy trusts enjoyed relative to their corporate peers in raising capital in a tax-efficient manner, and (b) place the Trust and other Canadian energy trusts at a competitive disadvantage relative to industry competitors, including U.S. master limited partnerships, which will continue to not be subject to entity level taxation. The SIFT Rules also makes the Trust Units less attractive as an acquisition currency. As a result, it may become more difficult for the Trust to compete effectively for acquisition opportunities.

No assurance can be provided that the SIFT Rules will not apply to the Trust prior to 2011, or that the income tax legislation will not be further changed in a manner which affects the Trust and its Unitholders.

Changes in Tax and Other Laws may Adversely Affect Unitholders.

Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource allowance, may in the future be changed or interpreted in a manner that adversely affects us and our Unitholders.

The Tax Act provides that a trust will permanently lose its “mutual fund trust” status (which is essential to the income trust structure) if it is established or maintained primarily for the benefit of non-residents of Canada (which is generally interpreted to mean that the majority of unitholders must not be non-residents of Canada), unless at all times after February 21, 1990, “all or substantially all” of the trust’s property consisted of property other than taxable Canadian property (the “TCP Exception”). Based on the most recent information obtained by us through our transfer agent and financial intermediaries, in February 2009 an estimated 76% of our issued and outstanding Trust Units were held by non-residents of Canada (as defined in the Tax Act) at that time. We are currently able to take advantage of the TCP Exception, and as a result, the Trust Indenture does not currently have a specific limit on the percentage of Trust Units that may be owned by non-residents.

There is no assurance that the TCP Exception will continue to be available to the Trust or that the Canadian federal government will not introduce new changes or proposals to tax regulations directed at non-resident ownership which, given our level of non-resident ownership, may result in us losing our mutual fund trust status or could otherwise detrimentally affect us and the market price of the Trust Units. We intend to continue to take the necessary measures in order to ensure that we continue to qualify as a mutual fund trust under the Tax Act. There would be material adverse consequences if we lost our status as a mutual fund trust under Canadian tax laws. See “Changes in Legislation – Material Adverse Tax Consequences to Loss of Mutual Fund Trust Status”.

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We may not be able to take steps necessary to ensure that we maintain our mutual fund trust status. Even if we are successful in taking such measures, these measures could be adverse to certain holders of Trust Units, particularly “non-residents” of Canada (as defined in the Tax Act). There can be no assurance that such circumstances would not detrimentally affect the market price of the Trust Units.

Additionally, legislation may be implemented to limit the investment in income funds and royalty trusts by certain investors or to change the manner in which these entities are taxed. Tax authorities having jurisdiction over us or our Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practices to our detriment or the detriment of our Unitholders.

Changes in Legislation – Material Adverse Tax Consequences to Loss of Mutual Fund Trust Status

There can be no assurance that the treatment of mutual fund trusts will not be changed in a manner adversely affecting Unitholders. If we cease to qualify as a “mutual fund trust” under the Tax Act, the Trust Units will cease to be qualified investments for registered retirement savings plans (“RRSPs”), registered education savings plans, deferred profit sharing plans, registered disability savings plan, registered retirement income funds (“RRIFs”) and tax free savings accounts (“TFSAs”) (collectively, the “Plans”).

Income tax laws, or other laws or government incentive programs relating to the oil and gas industry, such as the treatment of mutual fund trusts and resource taxation, may in the future be changed or interpreted in a manner that adversely affects us and our Unitholders. Tax authorities having jurisdiction over the Trust or the Unitholders may disagree with how we calculate our income for tax purposes or could change administrative practises to the detriment of us or the detriment of our Unitholders.

We expect that we will continue to qualify as a mutual fund trust for purposes of the Tax Act. We may not, however, always be able to satisfy any future requirements for the maintenance of mutual fund trust status. Should the status of the Trust as a mutual fund trust be lost or successfully challenged by a relevant tax authority, certain adverse consequences may arise for us and our Unitholders. Some of the significant consequences of losing mutual fund trust status are as follows:

• We would be taxed on certain types of income distributed to Unitholders, including income generated by the royalties held by us. Payment of this tax may have adverse consequences for some Unitholders, particularly Unitholders that are not residents of Canada and residents of Canada that are otherwise exempt from Canadian income tax.

• We would cease to be eligible for the capital gains refund mechanism available under Canadian tax laws if it ceased to be a mutual fund trust.

• 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.

• Trust Units would not constitute qualified investments for the Plans. If, at the end of any month, one of these exempt plans holds Trust Units that are not qualified investments, the plan must pay a tax equal to 1% of the fair market value of the Trust Units at the time the Trust Units were acquired by the exempt plan. An RRSP or RRIF holding non-qualified Trust Units would be subject to taxation on income attributable to the Trust Units. If an RESP holds non-qualified Trust Units, it may have our registration revoked by the Canada Customs and Revenue Agency. If a TFSA holds non-qualified Trust Units, a tax of 50% of the fair market value of the Trust Units is payable.

In addition, we may take certain measures in the future to the extent it believes necessary to ensure that we maintain our status as a mutual fund trust. These measures could be adverse to certain holders of Trust Units.

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Investment Eligibility

We will endeavour to ensure that the Trust Units continue to be qualified investments for the Plans. The holder of a TFSA that governs a trust which holds Trust Units will be subject to a penalty tax if the holder does not deal at arm’s length with the Trust for the purposes of the Tax Act or if the holder, alone or together with non-arm’s length persons or partnerships, has a significant interest (within the meaning of the Tax Act) in the Trust or a corporation, partnership or trust with which the Trust does not deal at arm’s length for the purposes of the Tax Act.

Adverse tax consequences may apply to a Plan, or an annuitant thereunder, if the Plan acquires or holds property that is non-qualified or ineligible investment for the Plan. There is no assurance that the conditions prescribed for such qualified or eligible investments will be adhered to at any particular time.

Nature of Trust Units

The Trust Units do not represent a traditional investment in the oil and natural gas sector and should not be viewed by investors as shares in AOG. The Trust Units represent a fractional interest in the Trust. As holders of Trust Units, Unitholders will not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring “oppression” or “derivative” actions. Our primary assets will be the Notes, the Common Shares, the Royalty and other investments in securities. The price per Trust Unit is a function of anticipated distributable income, the Properties acquired by AOG, and the Manager’s ability to effect long-term growth in our value. The market price of the Trust Units will be sensitive to a variety of market conditions including, but not limited to, interest rates and our ability to acquire suitable oil and natural gas properties. Changes in market conditions may adversely affect the trading price of the Trust Units.

The Trust Units are also unlike conventional debt instruments in that there is no principal amount owing to Unitholders. The Trust Units will have minimal value when reserves from our properties can no longer be economically produced or marketed. Unitholders will only be able to obtain a return of the capital they invested during the period when reserves may be economically recovered and sold. Accordingly, the distributions received over the life of the investment may not be equal to or greater than the initial capital investment.

The Trust Units are not “deposits” within the meaning of the Canada Deposit Insurance Corporation Act(Canada) and are not insured under the provisions of that Act or any other legislation. Furthermore, the Trust is not a trust company and, accordingly, is not registered under any trust and loan company legislation as it does not carry on or intend to carry on the business of a trust company.

Net Asset Value

The net asset value of our assets from time to time will vary depending upon a number of factors beyond the control of management, including oil and gas prices. The trading prices of the Trust Units from time to time is also determined by a number of factors which are beyond the control of management and such trading prices may be greater than the net asset value of our assets.

Additional Financing

In the normal course of making capital investments to maintain and expand our oil and gas reserves, additional Trust Units are issued from treasury which may result in a decline in production per Trust Unit and reserves per Trust Unit. Additionally, from time to time we issue Trust Units from treasury in order to reduce debt and maintain a more optimal capital structure. To the extent that external sources of capital, including the issuance of additional Trust Units, become limited or unavailable, our ability and AOG’s ability to make the necessary capital investments to maintain or expand our oil and gas reserves will be impaired. To the extent that the Trust and AOG are required to use cash flow to finance capital expenditures or property acquisitions or to pay debt service charges or to reduce debt, the level of distributable income will be reduced. Continued uncertainty in domestic and international credit markets could materially affect the Trust’s ability to access sufficient capital for its capital expenditures and acquisitions, and as a result, may have a material adverse effect on the Trust’s ability to execute its business strategy and on its financial condition.

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Competition

There is strong competition relating to all aspects of the oil and gas industry. There are numerous trusts in the oil and gas industry, who are competing for the acquisitions of properties with longer life reserves and properties with exploitation and development opportunities. As a result of such increasing competition, it will be more difficult to acquire reserves on beneficial terms. The Trust and AOG also compete for reserve acquisitions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial and other resources than the Trust and AOG.

Return of Capital

Trust Units will have no value when reserves from the Properties can no longer be economically produced and, as a result, cash distributions do not represent a “yield” in the traditional sense and are not comparable to bonds or other fixed yield securities, where investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments. Distributions represent a blend of a return of Unitholders’ initial investment and a return on Unitholders’ initial investment.

Unitholders have a limited right to require us to repurchase their Trust Units, which is referred to as a redemption right. See “Information Relating to the Trust – Right of Redemption”. It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investment. The right to receive cash in connection with a redemption is subject to limitations. Any securities which may be distributed in specie to Unitholders in connection with a redemption may not be listed on any stock exchange and a market may not develop for such securities. In addition, there may be resale restrictions imposed by law upon the recipients of the securities pursuant to the redemption right.

Redemption Right

It is anticipated that the redemption right will not be the primary mechanism for Unitholders to liquidate their investments. Long Term Notes or Redemption Notes which may be distributed in specie to Unitholders in connection with a redemption will not be listed on any stock exchange and no established market is expected to develop for such Long Term Notes or Redemption Notes. Cash redemptions are subject to limitations. See “Additional Information Respecting Advantage Energy Income Fund – Redemption Right”.

Unitholder Limited Liability

The Trust Indenture provides that no Unitholder will be subject to any liability in connection with us or our affairs or obligations and, in the event that a court determines that Unitholders are subject to any such liabilities, the liabilities will be enforceable only against, and will be satisfied only out of, such Unitholder’s share of our assets.

The Trust Indenture provides that all written instruments signed by or on behalf of us must contain a provision to the effect that such obligation will not be binding upon Unitholders personally. Notwithstanding the provisions of the Trust Indenture and the fact that Alberta (our governing jurisdiction) has adopted legislation purporting to limit trust unitholder liability, because of uncertainties in the law relating to investment trusts, there is a risk that a Unitholder could be held personally liable for obligations of the Trust in respect of contracts or undertakings which the Trust enters into and for certain liabilities arising otherwise than out of contracts including claims in tort, claims for taxes and possibly certain other statutory liabilities. The possibility of any personal liability of this nature arising is considered unlikely.

Future Dilution

One of our objectives is to continually add to our reserves through acquisitions and through development, and because we does not reinvest our cash flow, our success is in part dependent upon our ability to raise capital from time to time. Holders of Trust Units may also suffer dilution in connection with future issuances of Trust Units, whether issued pursuant to a financing or acquisition or otherwise.

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Regulatory Matters

Our operations are subject to a variety of federal and provincial laws and regulations, including laws and regulations relating to the protection of the environment.

The Economic Impact on Advantage of Claims of Aboriginal Title is Unknown.

Aboriginal people have claimed aboriginal title and rights to a substantial portion of western Canada. We are unable to assess the effect, if any, that any such claim would have on our business and operations.

Expansion of Operations

The operations and expertise of our management are currently focused on conventional oil and gas production and development in the Western Canadian Sedimentary Basin. In the future, we may acquire oil and gas properties outside this geographic area. In addition, the Trust Indenture does not limit our activities to oil and gas production and development, and we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines, or an interest in an oil sands project. Expansion of our activities into new areas may present new additional risks or alternatively, may significantly increase the exposure to one or more of the present risk factors which may result in our future operational and financial conditions being adversely affected.

Conflicts of Interest

The directors and officers of AOG are engaged in and will continue to be engaged in other activities in the oil and natural gas industry and, as a result of these and other activities, the directors and officers of AOG may become subject to conflicts of interest. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA.

Risks Particular to United States and Other Non-Resident Unitholders

In addition to the risk factors set forth above, the following risk factors are particular to Unitholders who are not residents of Canada.

United States and Other Non-Resident Unitholders may be Subject to Additional Taxation.

The Tax Act and the tax treaties between Canada and other countries may impose additional withholding or other taxes on the cash distributions or other property paid by us to Unitholders who are not residents of Canada, and these taxes may change from time to time. For instance, since January 1, 2005, a 15%withholding tax is applied to return of capital portion of distributions made to non-resident Unitholders.

Additionally, the reduced “Qualified Dividend” rate of 15% tax applied to our distributions under current U.S. tax laws is scheduled to expire at the end of 2010 and there is no assurance that this reduced tax rate will be renewed by the U.S. government at such time.

Furthermore, the SIFT Tax is anticipated to result in adverse tax consequences to certain Unitholders including non-resident Unitholders. See “Risk Factors – Changes in Legislation – SIFT Tax”.

Non-Resident Unitholders are Subject to Foreign Exchange Risk on the Distributions that they may Receive from the Trust.

Distributions from the Trust are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, investors are subject to foreign exchange risk. To the extent that the Canadian dollar weakens with respect to the currency of a non-resident, the amount of the distribution will be reduced when converted to the home currency of a non-resident.

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The Ability of United States and Other Non-Resident Unitholders Investors to Enforce Civil Remedies may be Limited.

We are a trust organized under the laws of Alberta, Canada, and our principal place of business is in Canada. All of the directors and officers of AOG are residents of Canada and most of the experts who provide services to us (such as its auditors and some of its independent reserve engineers) are residents of Canada, and all or a substantial portion of their assets and our assets are located within Canada. As a result, it may be difficult for investors in the United States or other non-Canadian jurisdictions (a “Foreign Jurisdiction”)to effect service of process within such Foreign Jurisdiction upon such directors, officers and representatives of experts who are not residents of the Foreign Jurisdiction or to enforce against them judgments of courts of the applicable Foreign Jurisdiction based upon civil liability under the securities laws of such Foreign Jurisdiction, including United States federal securities laws or the securities laws of any state within the United States. In particular, there is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or the securities laws of any state within the United States.

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE

As a Canadian issuer listed on the New York Stock Exchange (the “NYSE”), we are not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic requirements. As a foreign private issuer, we are only required to comply with four of the NYSE Rules: 1) have an audit committee that satisfies the requirements of the United States Securities Exchange Act of 1934; 2) the Chief Executive Officer must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE Rules; 3) provide a brief description of any significant differences between our corporate governance practices and those followed by U.S. companies listed under the NYSE; and 4) submit an executed annual written affirmation, as well as an interim affirmation each time a change occurs to the Audit Committee. We have reviewed the NYSE listing standards and confirm that our corporate governance practices do not differ significantly from such standards.

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of securities and interests of insiders in material transactions, where applicable, is contained in our information circular for the most recent annual meeting of Unitholders that involved the election of directors. Additional financial information is provided in our financial statements and management’s discussion and analysis for the year ended December 31, 2008. Documents affecting the rights of securityholders, along with additional information relating to Advantage, may be found on SEDAR at www.sedar.com.

SCHEDULE "A"

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

(FORM 51-101F3)

Management of Advantage Oil & Gas Ltd. (“AOG”) on behalf of Advantage Energy Income Fund (collectively, the “Trust”) is responsible for the preparation and disclosure of information with respect to the Trust’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Trust’s reserves data. The report of the independent qualified reserves evaluator is presented below.

The independent reserves evaluation committee of the Trust has:

(a) reviewed the Trust’s procedures for providing information to the independent qualified reserves evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The independent reserves evaluation committee has reviewed the Trust’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the independent reserves evaluation committee, approved:

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and

(c) the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

(signed)“Andy Mah”	(signed) “Kelly I. Drader”
Andy Mah	Kelly I. Drader
Chief Executive Officer	President and Chief Financial Officer
(signed) “Ronald A. McIntosh”	(signed) “John Howard”
Ronald A. McIntosh	John Howard
Director	Director
March 6, 2009

SCHEDULE "B"

REPORT ON RESERVES DATA

BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

(FORM 51-101 F2)

To the Board of Directors of Advantage Oil & Gas Ltd., on behalf of Advantage Energy Income Fund (the “Trust”):

1.	We have evaluated the Trust’s Reserves Data as at December 31, 2008. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.
2.	The Reserves Data are the responsibility of the Trust’s management. Our responsibility is to express an opinion on the Reserves Data based on our evaluation.
	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”), prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
3.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
4.	The following table sets forth the estimated future net revenue attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10%, included in the reserves data of the Trust evaluated by us as of December 31, 2008, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Trust’s management and Board of Directors:

			Net Present Value of Future Net Revenue Before Income Taxes (10% Discount Rate)
Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location of Reserves (County)	Audited(M$)	Evaluated (M$)	Reviewed(M$)	Total (M$)
Sproule Associates Limited	Evaluation of the P&NG Reserves of Advantage Energy Income Fund,	Canada	235,259	2,428,178	Nil	2,663,437
	As of December 31, 2008, prepared September 2008 to February 2009
Total			235,259	2,428,178	Nil	2,663,437

5.	In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
6.	We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date.
7.	Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

(signed) “Sproule Associates Limited”

Sproule Associates Limited

Calgary, Alberta

February 25, 2009