Exhibit 99.1

ANNUAL INFORMATION FORM

YEAR ENDED DECEMBER 31, 2009

March 16, 2010

TABLE OF CONTENTS

	Page
GLOSSARY OF TERMS		1
ABBREVIATIONS		2
CONVERSION		3
NON-GAAP MEASURES		5
ADVANTAGE OIL & GAS LTD.		6
GENERAL DEVELOPMENT OF THE BUSINESS		6
DESCRIPTION OF OUR BUSINESS AND OPERATIONS		9
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION		10
DIRECTORS AND OFFICERS		30
DIVIDEND POLICY		33
DESCRIPTION OF THE CORPORATION'S SECURITIES		33
PRICE RANGE AND TRADING VOLUME OF SECURITIES		34
ESCROWED SECURITIES		38
LEGAL PROCEEDINGS		38
REGULATORY ACTIONS		38
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS		38
MATERIAL CONTRACTS		38
INTEREST OF EXPERTS		38
AUDITORS, TRANSFER AGENT AND REGISTRAR		39
AUDIT COMMITTEE INFORMATION		39
AUDIT COMMITTEE CHARTER		40
AUDIT SERVICE FEES		45
INDUSTRY CONDITIONS		45
RISK FACTORS		53
DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE		61
ADDITIONAL INFORMATION		61

SCHEDULES

"A" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

"B" - REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

GLOSSARY OF TERMS

"5.00% Debentures" means 5.00% convertible unsecured subordinated debentures of the Corporation due January 30, 2015;

"6.50% Debentures" means 6.50% convertible unsecured subordinated debentures of the Corporation due June 30, 2010;

"7.75% Debentures" means 7.75% convertible unsecured subordinated debentures of the Corporation due December 1, 2011;

"8.00% Debentures" means 8.00% convertible unsecured subordinated debentures of the Corporation due December 31, 2011;

"ABCA" means the Business Corporations Act (Alberta), together with any or all regulations promulgated thereunder, as amended from time to time;

"AOG" or "Advantage" or the "Corporation" means Advantage Oil & Gas Ltd., a corporation amalgamation under the ABCA.  All references to "AOG" or "Advantage" or the "Corporation", 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 AOG;

"Common Shares" means the common shares of AOG;

"Debentures" means, collectively, the 5.00% Debentures, 6.50% Debentures, 7.75% Debentures and 8.00% Debentures;

"NI 51-101" means National Instrument 51-101 Standards Of Disclosure For Oil and Gas Activities;

"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;

"SET" means SET Resources Inc.;

"Shareholders" means the holders from time to time of one or more Common Shares, as shown on the register of such holders maintained by the Corporation or by the transfer agent of the Common Shares, on behalf of the Corporation;

"Sound" means Sound Resources Trust;

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

"Trust"means Advantage Energy Income Fund, a trust established under the laws of the Province of Alberta and dissolved effective July 9, 2009 pursuant to the Trust Conversion;

"Trust Conversion" means the plan of arrangement pursuant to Section 193 of the ABCA, which closed on July 9, 2009 and pursuant to which, among other things, the Trust was dissolved and the Corporation became the resulting entity;

"Trust Debentures" means, collectively, the 6.50% Debentures, the 7.75% Debentures and the 8.00% Debentures;

"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, as supplemented on July 9, 2009, pursuant to which the Trust was formed;

"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 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.

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.  A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 Bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
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.

Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

2

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

The term "boe" or barrels of oil equivalent may be misleading, particularly if used in isolation.  A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 Bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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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 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 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.

In particular, this annual information form contains 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;

• estimated timing of capital expenditures;

• timing of development of undeveloped reserves;

• 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 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 AOG believe to be reasonable, AOG cannot assure Shareholders that actual results will be consistent with these forward-looking statements.  With respect to forward-looking statements contained in this annual information form, 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.

AOG has included the above summary of assumptions and risks related to forward-looking information provided in this annual information form in order to provide Shareholders with a more complete perspective on the Corporation's current and future operations and such information may not be appropriate for other purposes. The Corporation'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 AOG will derive therefrom. These forward-looking statements are made as of the date of this annual information form and AOG disclaims 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.

NON-GAAP MEASURES

The Corporation discloses several financial measures in this Annual Information Form that do not have any standardized meaning prescribed under Generally Accepted Accounting Principles in Canada ("GAAP"). These financial measures include funds from operations and cash netbacks. Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by the Corporation’s principal business activities prior to the consideration of how those activities are financed or how the results are taxed. Investors should be cautioned that these measures should not be construed as an alternative to net income, cash provided by operating activities or other measures of financial performance as determined in accordance with GAAP. Advantage’s method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies.

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ADVANTAGE OIL & GAS LTD.

General

The Corporation was formed pursuant to the amalgamation of Advantage Oil & Gas Ltd., 1335703 Alberta Ltd., SET and Sound ExchangeCo Ltd. under the ABCA on September 5, 2007.  On July 9, 2009 the articles of the Corporation were amended in connection with the Trust Conversion to change the number of issued and outstanding Common Shares to equal the number of Trust Units outstanding immediately prior to the Trust Conversion. The Corporation is the resulting entity following the Trust Conversion with the Trust.  The Trust was created under the laws of the Province of Alberta pursuant to the Trust Indenture and was dissolved in connection with the Trust Conversion.

Following the Trust Conversion, the Corporation became a reporting issuer in each of the provinces of Canada and the Common Shares were listed on the TSX and NYSE under the symbol "AAV".

The head office of AOG is located at Suite 700, 400 - 3rd Avenue S.W., Calgary, Alberta T2P 4H2 and its registered office is located at 350 - 7th Avenue S.W., Calgary, Alberta  T2P 3N9.

Corporate Structure

The following diagram illustrates the organizational structure of the Corporation as at the date hereof which does not include the Corporation's subsidiaries, as the total assets and sales and operating revenues of such subsidiaries, on a combined basis, does not exceed 10% of the consolidated assets and the consolidated sales and operating revenues of the Corporation.

GENERAL DEVELOPMENT OF THE BUSINESS

General

The Corporation is actively engaged in the business of oil and gas exploitation, development, acquisition and production in the Provinces of Alberta and Saskatchewan. AOG is a growth-oriented corporation and continues to carry on the business previously carried out by the Trust.  See "Description of our Business and Operations" below.

A detailed description of the historical development of the business of the Trust and the Corporation is outlined below. Unless the context otherwise requires, references to "we", "us", "our" or similar terms, or to the "Trust" refer to the Corporation.

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Three Year History

2007

On February 14, 2007, the Trust 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 the Trust 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.

On July 9, 2007, the Trust 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 the Trust 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, the Trust also assumed approximately $108.0 million of bank indebtedness upon closing of the Sound Arrangement.

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

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

2008

On November 7, 2008, Mr. Paul Haggis was appointed to the AOG Board of Directors.

On December 18, 2008, the Trust 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.

2009

On January 20, 2009, the Trust announced that the AOG Board of Directors adopted a Unitholder Rights Plan (the "Rights Plan") for which Unitholder approval was obtained at the Trust's annual meeting of Unitholders held on July 9, 2009.  The Rights Plan was 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.

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.

7

On March 18, 2009, the Trust announced that the AOG Board had unanimously approved a conversion of the Trust to a growth-oriented corporation, the Corporation. The Trust Conversion was completed on July 9, 2009. Pursuant to the Trust Conversion, Unitholders received one Common Share in the Corporation for each Trust Unit they held and the Corporation assumed all the obligations of the Trust in respect of the Trust’s outstanding Trust Debentures such that, upon maturity of the Trust Debentures or such other date as communicated by the Corporation, the Trust Debentures will be satisfied with cash or the Common Shares of the Corporation in lieu of Trust Units, at the option of the Corporation. Following the completion of the Trust Conversion, the senior management and Board of Directors of the Corporation was substantially the same as the Trust, with the exception of Messrs. Bourgeois and Tourigny who retired from the Board of Directors of the Corporation.

On March 18, 2009, we further announced that as another step to increase the Trust’s financial flexibility and to focus on development and growth at our Glacier property, the Trust 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.

On March 18, 2009, the Trust announced that it 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 were initially used to reduce outstanding bank debt to improve the Trust’s financial flexibility.

On June 15, 2009, the Trust announced that it had signed two purchase and sale agreements relating to the disposition of $252.6 million of assets.  The disposition price for one package (the "Package One Assets") of the Sale Assets was $176 million, subject to customary adjustments. The Package One Assets were producing as of June 15, 2009 approximately 5,900 boe/d and proved plus probable reserves of the Package One Assets were estimated by Sproule to be 18.8 MMboe as of March 31, 2009. The closing of the sale of the Package One Assets occurred on July 24, 2009, with an April 1, 2009 effective date. The disposition price for the second package (the "Package Two Assets") of the Sale Assets was $76.6 million, subject to customary adjustments. The Package Two Assets were producing as of June 15, 2009 approximately 2,200 boe/d and proved plus probable reserves of the Package Two Assets were estimated by Sproule to be 8.5 MMboe as of March 31, 2009. The closing of the sale of the Package Two Assets occurred on July 15, 2009, with an April 1, 2009 effective date.

On July 7, 2009, the Trust completed a bought deal financing through a syndicate of underwriters. Pursuant to the financing, the Trust issued 17,000,000 Trust Units at a price of $6.00 per Trust Unit for gross proceeds of $102 million.  All of the net proceeds of the financing were initially used by the Trust to repay indebtedness under its credit facilities, which will be available to be subsequently redrawn and applied as needed to fund AOG's capital expenditure program.

On July 8, 2009, the Trust announced its corporate capital budget for the 12 month period ending June 2010 had been set at $207 million. The budget will focus on development of our Montney natural gas resource play at Glacier, Alberta where Advantage will continue to employ a phased development approach. Phase I of the development plan was achieved during Q2 2009 where production capacity was increased to approximately 25 mmcfd and included wells, compression facilities and additional pipelines. Phase II of the development plan will be undertaken from July, 2009 to July, 2010 and is designed to increase production capacity to approximately 50 mmcfd by mid-year 2010. Phase III of the development plan is intended to increase production capacity to 100 mmcfd by mid-year 2011.

On July 9, 2009 the Corporation announced completion of the Trust Conversion and the Corporation's Common Shares and the 6.50% Debentures, the 7.75% Debentures and the 8.00% Debentures commenced trading on the TSX and the Corporation's Common Shares commenced trading on the NYSE on July 14, 2009.

On August 13, 2009, in connection with completion of the Trust Conversion and Disposition of Assets, the Corporation's credit facilities were amended to be a $525 million facility comprised of a $20 million revolving operating loan facility and a $505 million extendible revolving credit facility (the "Credit Facilities").  Various borrowing options are available under the Credit Facilities, including prime rate based advances, U.S. base rate advances, U.S. dollar LIBOR advances and bankers' acceptances loans. The Credit Facilities are secured by a $1 billion floating charge demand debenture, a general security agreement and a subordination agreement from the Corporation covering all assets and cash flows. The amounts available to the Corporation from time to time under the Credit Facilities are based upon the borrowing base determined by the lenders and which is redetermined on a semi-annual basis by those lenders with the next redetermination anticipated to take place in June 2010. The borrowing base constitutes a revolving facility for a 364 day term which is extendible annually for a further 364 day revolving period, subject to a one year term maturity as to lenders not agreeing to such annual extension.

8

On December 7, 2009, the Corporation provided an operational update regarding its Montney drilling program at Glacier, Alberta and highlights of its proposed development program.

On December 31, 2009 the Corporation completed the offering of $86,250,000 principal amount of 5.00% Debentures, which included $11,250,000 principal amount of 5.00% Debentures issued on exercise in full of the over-allotment option granted to the underwriters. AOG used the net proceeds of the offering to repay outstanding bank indebtedness and for general corporate purposes.

Recent Developments

On January 19, 2010, our Board of Directors approved a capital budget and updated guidance for the six month period ended June 30, 2010. Capital expenditures during the period are estimated to be approximately $110 million (80% directed to Glacier) and will be funded out of funds from operations.

Anticipated Changes in the Business

As at the date hereof, we do not anticipate that any material change in our business shall occur during the balance of the 2010 financial year.

Significant Acquisitions

The Corporation did not complete any acquisitions during the year ended December 31, 2009 for which disclosure is required under Part 8 of National Instrument of 51-102 Continuous Disclosure Obligations.

As part of its ongoing business, the Corporation evaluates potential acquisitions of all types of petroleum and natural gas assets.  The Corporation is normally in the process of evaluating several potential acquisitions at any one time which individually or together could be material.  As of the date hereof, the Corporation has not reached agreement on the price or terms of any potential material acquisitions.  The Corporation cannot predict whether any current or future opportunities will result in one or more acquisitions for the Corporation.

DESCRIPTION OF OUR BUSINESS AND OPERATIONS

General

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

Advantage's exploitation and development program is focused primarily at Glacier, Alberta where we are developing a significant natural gas resource play. As current and future practice, AOG has established a financial hedging strategy and may manage the risk associated with changes in commodity prices by entering into derivatives.  See "Risk Factors".  Although Advantage has a significant capital development program, we also actively pursue growth opportunities through oil and gas asset 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 Common Share 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 Common Shares from treasury and the issuance of subordinated convertible debentures, maintaining prudent leverage.

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Reorganizations

Other than the Sound Arrangement and the Trust Conversion, there have been no material reorganizations of the Trust 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".

Bankruptcy and Similar Procedures

There have been no bankruptcy, receivership or similar proceedings against the Corporation or any of its subsidiaries or related entities, or any voluntary receivership, bankruptcy or similar proceeding by the Corporation or any of its subsidiaries or related entities since the inception of the Corporation or during or proposed for the current financial year.

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, 2009.  The effective date of the Statement is December 31, 2009 and the preparation date of the Statement is March 8, 2010.

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, 2009 contained in a report of Sproule dated March 8, 2010 (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 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, 2009

FORECAST PRICES AND COSTS

	RESERVES
	LIGHT AND MEDIUM OIL				HEAVY OIL
RESERVES CATEGORY	Gross (Mbbl)		Net (Mbbl)		Gross (Mbbl)		Net (Mbbl)
PROVED
Developed Producing		12,120		10,592		2,121		1,919
Developed Non-Producing		867		735		160		139
Undeveloped		2,615		2,218		185		175
TOTAL PROVED		15,602		13,545		2,466		2,233
PROBABLE		13,524		11,169		3,370		2,732
TOTAL PROVED PLUS PROBABLE		29,126		24,714		5,836		4,965

	RESERVES
	NATURAL GAS				NATURAL GAS LIQUIDS
RESERVES CATEGORY	Gross (MMcf)		Net (MMcf)		Gross (Mbbl)		Net (Mbbl)
PROVED
Developed Producing		194,485		168,111		4,614		3,409
Developed Non-Producing		15,123		13,766		46		32
Undeveloped		297,598		263,339		606		474
TOTAL PROVED		507,206		445,216		5,266		3,915
PROBABLE		630,116		527,466		2,483		1,820
TOTAL PROVED PLUS PROBABLE		1,137,322		972,682		7,749		5,735

	RESERVES
	TOTAL OIL EQUIVALENT
RESERVES CATEGORY	Gross (Mboe)		Net (Mboe)
PROVED
Developed Producing		51,269		43,939
Developed Non-Producing		3,593		3,200
Undeveloped		53,006		46,757
TOTAL PROVED		107,868		93,896
PROBABLE		124,396		103,631
TOTAL PROVED PLUS PROBABLE		232,264		197,527

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SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE

as at December 31, 2009

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		1,733,335		1,211,067		950,359		792,595		685,661		1,678,684		1,197,182		946,250		791,234		685,171		21.63
Developed Non-Producing		107,413		80,560		64,138		53,072		45,119		83,486		70,475		59,674		51,010		44,130		20.04
Undeveloped		1,217,821		615,481		329,653		172,860		78,904		910,593		455,476		237,093		115,585		41,737		7.05
TOTAL PROVED		3,058,569		1,907,108		1,344,150		1,018,527		809,684		2,672,764		1,723,133		1,243,017		957,829		771,038		14.32
PROBABLE		4,676,528		2,368,388		1,429,278		945,718		660,404		3,491,558		1,762,635		1,057,467		694,497		480,677		13.79
TOTAL PROVED PLUS PROBABLE		7,735,097		4,275,496		2,773,428		1,964,245		1,470,088		6,164,322		3,485,768		2,300,484		1,652,326		1,251,715		14.04

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		6,795,708	*		864,500		1,935,405		845,266		91,968		3,058,569		385,806		2,672,764
Proved Plus Probable Reserves		15,110,109	*		2,090,782		3,574,523		1,570,228		139,479		7,735,098		1,570,776		6,164,322

*Alberta Drilling Royalty Credits of 16,537 M$ for the proved case and 21,887 M$ for the proved plus probable case have been included as other revenue.

12

FUTURE NET REVENUE

BY PRODUCTION GROUP

as of December 31, 2009

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)	478,880	27.34
	Heavy Oil (including solution gas and other by-products)	61,376	23.92
	Natural Gas (including by-products but excluding solution gas and by-products from oil wells)	752,437	10.71
	Non-Conventional Oil and Gas Activities (Coalbed Methane)	51,458	14.57
	TOTAL	1,344,151	14.32
Proved Plus	Light and Medium Crude Oil (including solution gas and other by-products)	804,026	25.59
Probable Reserves	Heavy Oil (including solution gas and other by-products)	118,946	22.01
	Natural Gas (including by-products but excluding solution gas and by-products from oil wells)	1,776,955	11.41
	Non-Conventional Oil and Gas Activities (Coalbed Methane)	73,500	14.60
	TOTAL	2,773,427	14.04

Pricing Assumptions

The following tables set forth the benchmark reference prices, as at December 31, 2009, 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, 2009

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 ($Cdn/bbl)	INFLATION RATES %/Year	EXCHANGE RATE (2) ($US/$Cdn)
Forecast(3)
2010	79.17	84.25	80.04	69.93	5.36	86.28	59.65	2.0	0.92
2011	84.46	89.99	84.59	73.79	6.21	92.16	63.72	2.0	0.92
2012	86.89	92.61	85.20	74.08	6.44	94.84	65.57	2.0	0.92
2013	90.20	96.19	87.53	75.03	7.23	98.51	68.11	2.0	0.92
2014	92.01	98.13	88.32	74.58	7.98	100.50	69.48	2.0	0.92
2015	93.85	100.11	90.10	76.08	8.16	102.53	70.89	2.0	0.92
2016	95.72	102.13	91.92	77.62	8.34	104.60	72.32	2.0	0.92
2017	97.64	104.19	93.77	79.19	8.52	106.71	73.78	2.0	0.92
2018	99.59	106.30	95.67	80.79	8.71	108.86	75.27	2.0	0.92
2019	101.58	108.44	97.60	82.42	8.90	111.06	76.79	2.0	0.92
Thereafter	+2%	+2%	+2%	+2%	+2%	+2%	+2%	+2%	0.92

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, 2009, were $6.24/Mcf for natural gas, $60.55/bbl for crude oil, and $38.10/bbl for natural gas liquids.

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Reconciliations of Changes in Reserves

The following table sets forth a reconciliation of the Corporation's total gross proved, gross probable and total gross proved plus probable reserves as at December 31, 2009 against such reserves as at December 31, 2008 based on forecast prices and cost assumptions.

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, 2008		23,544			15,929			39,473			2,845			3,697			6,542			6,795			3,970			10,765
Extensions		200			31			231			15			8			23			32			1			33
Improved Recovery		0			0			0			0			0			0			0			0			0
Infill Drilling		50			24			74			29			16			45			0			0			0
Technical Revisions		(2,025	)		(826	)		(2,851	)		(63	)		(352	)		(415	)		328			(1,000	)		(672	)
Discoveries		0			0			0			0			0			0			0			0			0
Acquisitions		0			0			0			0			0			0			0			0			0
Dispositions		(3,991	)		(1,672	)		(5,663	)		(19	)		(10	)		(29	)		(997	)		(490	)		(1,487	)
Economic Factors		87			37			124			33			11			44			(59	)		2			(57	)
Production		(2,263	)		0			(2,263	)		(374	)		0			(374	)		(833	)		0			(833	)
December 31, 2009		15,602			13,523			29,125			2,466			3,370			5,836			5,266			2,483			7,749

	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, 2008		352,674			256,043			608,717			34,349			23,161			57,510
Extensions		97,267			334,066			431,333			688			125			813
Improved Recovery		0			0			0			0			0			0
Infill Drilling		107,694			58,853			166,547			253			127			380
Technical Revisions		17,425			(10,042	)		7,383			(3,915	)		(2,209	)		(6,124	)
Discoveries		0			0			0			0			0			0
Acquisitions		0			0			0			0			0			0
Dispositions		(75,500	)		(34,542	)		(110,042	)		(4,748	)		(5,367	)		(10,115	)
Economic Factors		(8,082	)		(567	)		(8,649	)		384			154			538
Production		(31,850	)		0			(31,850	)		(3,229	)		0			(3,229	)
December 31, 2009		459,628			603,811			1,063,439			23,782			15,991			39,773

14

	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, 2008		22,064			11,533			33,597			101,366			72,052			173,418
Extensions		204			52			256			16,607			55,747			72,354
Improved Recovery		0			0			0			0			0			0
Infill Drilling		0			0			0			18,070			9,870			27,940
Technical Revisions		4,882			(1,123	)		3,759			1,305			(4,407	)		(3,102	)
Discoveries		0			0			0			0			0			0
Acquisitions		0			0			0			0			0			0
Dispositions		0			0			0			(18,382	)		(8,823	)		(27,205	)
Economic Factors		(281	)		(148	)		(429	)		(1,269	)		(43	)		(1,312	)
Production		(3,073	)		0			(3,073	)		(9,829	)		0			(9,829	)
December 31, 2009		23,796			10,314			34,110			107,868			124,396			232,264

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" herein.

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

Proved Undeveloped Reserves

	Light and Medium Oil (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		2,419		2,419		0		0		14,809		14,809		787		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
2009		44		4,133		0		297		166,681		255,857		0		1,429

15

Sproule has assigned 53.0 MMboe of proven undeveloped reserves in the Sproule Report under forecast prices and costs, together with $836 million of associated undiscounted future capital expenditures.  Proven undeveloped capital spending in the first two forecast years of the Sproule Report accounts for $349 million, or 42 percent, of the total forecast.  These figures increase to $670 million or 80 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		1,777		1,777		0		0		31,103		31,103		1,018		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
2009		869		5,206		0		2,312		309,476		450,349		8		1,995

Sproule has assigned 102 MMboe of probable undeveloped reserves and has allocated future development capital of $721 million to all probable undeveloped reserves with $639 million scheduled for the first five years.

Significant Factors or Uncertainties

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. The Corporation's reserves are evaluated by Sproule.

As circumstances change and additional data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, commodity prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can be either positive or negative.

In addition, 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$)		Proved Plus Probable Reserves (MM$)
2010		146,563		220,817
2011		209,752		348,266
2012		176,063		364,092
2013		74,276		232,106
2014		72,460		156,502
Total: Undiscounted for all years		845,266		1,570,228

16

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 Common Shares, 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 are intended to maximize the investment return to Shareholders 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 and in southeast Saskatchewan.  These properties produce from a variety of various aged geological formations and reservoirs.  We operate over 85% of our properties.  This allows us to control the nature and timing of the capital investments necessary to maximize the potential in developing these assets.

Our properties can be divided on the broad basis of commodity and of production type.  Light or medium gravity oil accounts for 27% of our production and 13% of our reserves.  A further 62% of production and 82% of reserves are natural gas.

Rates referenced in the following property descriptions are as of February 28, 2010 unless otherwise noted and reserves quoted are as reported in the Sproule Report to December 31, 2009.

Advantage Oil and Gas Major Properties

Glacier, Alberta

The Glacier property lies along the Alberta side of the border with British Columbia between Grande Prairie, Alberta and Dawson Creek, British Columbia.  The primary zones of interest are within the Triassic - Montney and Doig Formation siltstones. The property consists of 82.5 gross sections with Montney interests with an average working interest of 94.5% (78 net).   There are 72.5 gross (67.5 net) of these sections which also have shallow rights prospective for unconventional resource type tight sand/silt reservoirs in the Jurassic - Nordegg and Nikanassin Formations and Cretaceous - Wilrich Formation.

In 2009, Advantage drilled and completed 2 gross (2 net) vertical and 27 gross (19.4 net) horizontal wells in the Montney and Doig Formations on the Glacier property.  In the first quarter of 2010 Advantage has drilled an additional 8 (gross and net) horizontal Montney/Doig wells.  One additional net horizontal well was drilled in the Nikanassin Formation.  These wells are geographically spread across the Glacier property with the majority drilled in the Upper Montney (Doig formation) however 8 gross (5.4 net) wells are drilled into the Lower Montney.

Advantage cases its’ horizontal wells to total depth for production and uses an abras-a-jet and sand plug completion technique.  On average 10 fracs per horizontal well have been placed (however in newer wells this is increasing with as many as 15).   The fracs are water and CO2 fracs carrying 75 tonnes of sand per frac.  All the wells drilled in 2009 have been completed however several of the wells drilled in 2010 will not be able to be completed until after spring break up has lifted. The average first month production rate for the first 15 net wells  having at least one month of production is 3.9 MMcf/d.  Subsequently 14 gross (9 net) wells have been tested at an average final test rate of 5.1 Mmcf/d (average wellhead flowing pressure of 7057 kpa).  Glacier is Advantage’s largest producing property.  At 8,200 boe/d Glacier’s production represents 31% of corporate volumes.

17

In the first quarter of 2009 Advantage expanded the capacity of its gas compression facility to 25 Mmcf/d from 8 Mmcf/d.   Advantage will be onstream with its phase 2 expansion to 50 Mmcf/d capacity at the end of the first quarter 2010.  In 2009 Advantage constructed a 22 kilometer sales pipeline which carried our gas to a third party gas plant for processing and sale.  The 2010 expansion of Advantage’s facility included the addition of amine for H2S removal which allows for gas to be sold directly into TransCanada’s pipeline system concurrent with the start up of the phase 2 expansion.  The phase 2 expansion is reducing operating costs from $8.25/boe to $2.75/boe.

Advantage has drilled just 42 gross horizontal Montney wells across only 20 of the 82.5 gross sections of land.   This represents a well density of just 2.1 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).  On this basis 118 wells remain on lands which have already had some drilling.  An additional 500 remain on sections where no drilling has occurred to date.

The Sproule Report assigns 305 bcf of proven natural gas reserves and 12.8 Mbbls of proven crude oil and NGL reserves to this property on 53 sections of land.  In addition, 531 bcf of probable natural gas reserves and 2.6 Mbbls of probable crude oil and NGL 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 second largest producing property with current production from all zones of 3950 boe/d representing 15% of total corporate volumes.

The main producing zone is the 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 35o and 42o API.  The Wabamun is developed in two main pools each situated on different sides of the Red Deer River which results in Advantage operating two facilities to process the oil which is gathered through company pipelines to each of the respective facilities.  Oil is trucked from the facilities and water is disposed of back into the reservoir.   Gas is transported through company pipelines to third party compression and sales.  Four (net and gross) wells were drilled and completed in the Wabamun in 2009.

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 a 120 mcf/d initial average rate and have since maintained a very flat production profile.  No drilling occurred in 2009, however subsequent to year end, 3 wells were drilled and completed, primarily for land retention purposes.  In 2008 the main gathering system had been expanded and compression was added at two central sites along with optimization of field compression.  Advantage has approximately 40 remaining CBM drilling locations under current spacing which is on the basis of 4 wells per section of land.

The Sproule Report assigns 42.5 bcf of proven natural gas reserves and 4,253 Mbbls of proven crude oil and NGL reserves to this property.  In addition, 18.0 bcf of probable natural gas reserves and 2,413 Mbbls of probable crude oil and NGL reserves have been assigned to this property.

Shallow Gas Properties

The third largest portion (7%) of corporate production comes from three shallow gas properties at Medicine Hat, Bantry, and Shouldice.    Production from these three properties collectively is 1,860boe/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 and co-mingled to allow for multiple gas wells per section from multiple producing horizons per well bore.

18

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 1134 boe/d.

Sproule evaluated our reserves in the Medicine Hat property and assigned 29.6 bcf of proved natural gas reserves and 10.7 bcf of probable reserves.

BANTRY - This property is located immediately east of the town of Brooks straddling the TransCanada Highway.  It 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 or 2009.  Natural gas is gathered into our operated compression and dehydration facilities.  Current production from this area is 390 boe/d.

The Sproule Report assigns 6.6 bcf of proven natural gas reserves and 2.9 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 or 2009.  Both natural gas and crude oil are produced and gathered through our facilities of varying working interests.  Current natural gas production of 340boe/d is produced on a co-mingled basis from the Medicine Hat Formation sands with various Belly River Formation sands.

The Sproule Report assigns 7.3 bcf of proven natural gas reserves and 4 bcf of probable natural gas reserves to this property.

Southeast Saskatchewan

MIDALE AND STEELMAN AREAS - 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.  Production is mature with low decline rate and the light oil delivers a high netback.  No drilling was undertaken in 2009.  One (50% net) horizontal well is being drilled in the Mississippian Midale Formation in 2010.  Advantage holds significant mineral title interest in southeast Saskatchewan.  There has been significant industry activity occurring surrounding these lands particularly for the light oil resource plays in the Bakken and Three Forks Sanish Formations.  As the information from this activity comes into the public domain, Advantage will be evaluating the drilling potential on its lands.  Further north, resulting from three separate farmouts to three industry partners in the Midale, Froude and Viewfield areas, approximately 30 Bakken horizontal wells with an average 10% overriding royalty to Advantage have been drilled. Combined production from all the properties in southeast Saskatchewan (excluding the Wapella area) is 1090 boe/d.

Sproule evaluated our proved reserves in southeast Saskatchewan and assigned 3,388 Mbbls of crude oil and NGLs.  Probable reserves in this area were evaluated by Sproule at 1,852 Mbbls of crude oil and NGLs.

19

WAPELLA AREA- Our Wapella property is located 200 kilometres east of Regina and produces medium-gravity (25º 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 2009 or are anticipated in 2010.  Production from the Wapella area is currently 550 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.

Total production from the Southeast Saskatchewan properties is 1,640boe/d (6% of corporate total).

Sproule evaluated our proved reserves in Wapella and assigned 2,700 Mbbls of crude oil.  Probable reserves in this area were evaluated by Sproule at 1,674 Mbbls of crude oil.

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 went down for significant overhaul and reconfiguration of its sour operating trains since the third quarter of 2008 and was not operational until November 2009.  There was no production from the field during this period.  Production from this field is back on stream at 1,125boe/d, (approximately 4% of corporate volumes).

Sproule evaluated our proved reserves at Lookout Butte and assigned 30 bcf of natural gas and 1,595 Mbbls of crude oil and NGLs.  Probable reserves in this area were evaluated by Sproule at 11.1 bcf of natural gas and 622 Mbbls of crude oil and NGLs.

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.  There are two principle plays on this property including the Jurassic Rock Creek gas play on the east side of the property and the Cretaceous Ostracode/Glauconite oil on the north side of the property.  Two of the Ostracode oil wells, capable of 400bbl/d, were rate restricted under production allowables until good production practise (GPP) was received in August 2009.  An additional well is budgeted for 2010 and the pool is being evaluated for waterflood pressure maintenance.  Current production from all zones at Willesden Green is 1,125boe/d (approximately 4% of corporate volumes).

Sproule evaluated our proved reserves in the Willesden Green area and assigned 6.6 bcf of natural gas and 941 Mbbls of crude oil and NGLs.  Probable reserves in this area were evaluated by Sproule at 3.2 bcf of natural gas and 489 Mbbls of crude oil and NGLs.

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 990boe/d (just under 4% of corporate volumes).

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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 reservoir is currently under active waterflood pressure maintenance since 2003.  Injectors continue to be evaluated and will be added as required.  We also operate five compressor stations and 80 kilometres of pipeline gathering facilities that are connected to the Rimbey gas plant.  No wells were drilled in 2009 and no additional wells are planned in 2010.

Sproule evaluated our proved reserves and assigned 7.8 bcf of natural gas and 2,347 Mbbls of crude oil and NGLs.  Probable reserves in this area were evaluated by Sproule at 2.4 bcf of natural gas and 1,440 Mbbls of crude oil and NGLs.

Brazeau -Ferrier, Alberta

The Brazeau-Ferrier area is located between 50 and 80 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.  Major facility interests include a 25.7% working interest in the West Pembina Sour Gas Plant.  Additional gas production occurs from several non operated Rock Creek, Basal Quartz and Notikewin pools.

In 2009 we completed and tied in a new well drilled late in 2008 on a four section new land block acquired at crown landsale.  This is the second well completed in the Cretaceous Belly River Formation.  Additional lands have been acquired in 2010 and a new drilling location is budgeted in 2010 for the Belly River.  In addition the acreage is being reviewed for the potential to drill a horizontal multi-stage frac well in the Notikewin Formation later in 2010. Current production from this area is 920boe/d (3.5% of total production).

Sproule evaluated our proved reserves in the Brazeau River area and assigned 8.6 bcf of natural gas and 524 Mbbls of crude oil and NGLs.  Probable reserves in this area were evaluated by Sproule at 2.8 bcf of natural gas and 131 Mbbls of crude oil and NGLs.

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 880boe/d.

SUNSET "A" - Production is from the Triassic Montney Formation, which in this area is a conventional sandstone reservoir (unlike the siltstone resource reservoir at Glacier).  The reservoir has a contributing water leg which provides partial pressure support.   Advantage has a 70% working interest, and operates the Sunset Triassic "A" Unit.  Production from the unit is predominantly oil (32o API).  The unit has a forty year production history with a stable performance and low decline.  Advantage commenced infill development of the pool in 2005 where two wells were drilled and came on-stream at an average rate of 75 bbls/d per well, similar to that of the original wells.  The success of this pilot led to the drilling of an additional 19 oil wells and an injector in 2006 and 2007. Significant upgrading to oil production and handling facilities and gathering systems as well as water handling occurred as well this period.  Although no new wells were drilled in 2009, 4 wells are being drilled in Q1 2010.  Three will be completed as producers and the fourth will be used as a water injector for additional pressure maintenance.  Up to three additional wells may be converted to water injectors in 2010.

SUNSET "B" - Production from this Montney reservoir is predominantly natural gas although there is a thin oil (32o 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 2009 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 2009.

For the three properties, Sunset "A", Sunset "B" and Valleyview, the Sproule Report assigns 8.1 bcf of proven natural gas reserves and 1,182 Mbbls of proven crude oil and NGL reserves.  In addition, 13.4 bcf of probable natural gas reserves and 1,916 Mbbls of probable crude oil and NGL reserves have been assigned to these properties.

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Heavy Oil Properties ( Lloydminster, Saskatchewan area)

The Lashburn, 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 19º 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.  Both wells were each brought on production at approximately 50bbl/d.  Four wells were drilled on the Eyehill property in Q1 2010 and are currently being completed.  The Eyehill property is a Sparky oil pool which responds well to water injection pressure maintenance.  Two wells were converted to injectors in 2009 for a total of 5 injectors.  Currently production from these oil properties is 740boe/d.

Sproule evaluated our proved reserves in the Heavy Oil Properties of western Saskatchewan and assigned 1,250 Mbbls of crude oil and NGLs.  Probable reserves in this area were evaluated by Sproule at 2,893 Mbbls of crude oil and NGLs.

Oil and Gas Wells

The following table sets forth the number and status of wells as at December 31, 2009 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		633		387		381		245		1,949		1,277		1,218		839
Saskatchewan		314		260		164		138		125		43		41		31
Manitoba		-		-		-		-		1		1		-		-
Total		947		647		545		383		2,075		1,321		1,259		870

Note:

(1) Excluding minor interest in the following units (less than 5% working interest):  Steelman Unit No. 3, Carrot Creek Cardium K Unit No. 1, Delburne Gas Unit, Nevis Unit No. 1, Bonnie Glen D-3A Gas Cap Unit, Turner Valley Unit No. 5, Sunchild Gas Unit No. 1, North Pembina Cardium Unit and Kakwa Cardium A Unit.  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, 2009.

	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Alberta		961,790		462,788		466,706		208,788		1,428,496		671,576
Saskatchewan		53,690		35,928		129,179		91,679		182,869		127,607
Total		1,015,480		498,716		595,885		300,467		1,611,365		799,183

In the year ended December 31, 2009, rights to explore, develop and exploit 81,174 net acres of undeveloped land expired.  We expect that rights to explore, develop and exploit 60,676 net acres of our undeveloped land holdings will expire by December 31, 2010.  The land expirations do not consider our 2010 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.

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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 and capital development.

We have implemented a hedging policy to use costless collars and fixed price swaps to hedge up to 60% of our gross production in the first two years and up to 50% of our gross production in the third year.  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 55% of our net gas production is now hedged for the 2010 calendar year at a floor of $7.46/mcf. For the first quarter of 2010, we have secured approximately 81% of our net gas production at a floor of $7.64/mcf. For 2011, approximately 27% of our net gas production is hedged at a floor of $6.30/mcf. We have also hedged approximately 33% of our 2010 net crude production at an average floor price of Cdn$67.83/bbl.  For the first quarter of 2011, we have secured approximately 11% of our net oil production at a floor of Cdn$69.50/bbl.

Advantage has the following derivatives in place:

Description of Derivative	Term	Volume	Average Price
Natural gas - AECO
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
Fixed price (1)	January 2011 to December 2011	9,478 mcf/d	Cdn $6.24/mcf
Fixed price (1)	January 2011 to December 2011	9,478 mcf/d	Cdn $6.24/mcf
Fixed price (1)	January 2011 to December 2011	9,478 mcf/d	Cdn $6.26/mcf
Crude oil - WTI
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

Note:

(1) These financial contracts were entered into after December 31, 2009.

Additional Information Concerning Abandonment and Reclamation Costs

We estimate the costs to abandon and reclaim all our non-producing and producing wells, gas plants, pipelines, batteries, and other facilities. No estimate of salvage value is netted against the estimated cost. Our model for estimating the amount of future abandonment and reclamation expenditures was done on an individual well and facility level. Estimated expenditures for each well and facility are base on internal estimates through consultation with our Health, Safety and Environment Department. Each well and facility are assigned an average cost for abandonment and reclamation over a 60 year period. Timing of expenditures are based on budgets and estimates of such annual activities. Facility reclamation costs are generally scheduled to begin shortly before the end of the reserve life of our associated reserves and continue beyond the reserve life under the assumption that decommissioning of plant/facilities are generally mobile assets with a long useful life.

We estimate that we will incur reclamation and abandonment costs on 3,221 net producing and non-producing wells. The approximate net cost to abandon and reclaim all wells and facilities, discounted at 10%, totals $39.8 million ($380.8 million undiscounted), of which approximately $13.9 million are included in the estimate of future net revenue ($57.1 million undiscounted). Abandonment and reclamation costs undiscounted and expected to be paid over the next three years totals $13.8 million.

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Tax Horizon

In 2009, we did not pay any income related taxes and it is expected, based on current legislation, that no cash income taxes are to be paid by AOG prior to 2016.

Capital Expenditures

The following tables summarize capital expenditures (including capitalized general and administrative expenses) related to our activities for the year ended December 31, 2009:

Capital Expenditures ($ thousands)	2009
Land and seismic	$	2,080
Drilling, completions and workovers		107,060
Well equipping and facilities		61,515
Other		213
		170,868
Property acquisitions
Proved properties		-
Unproved properties		-
Property dispositions		(245,150	)
Total capital expenditures (dispositions)		(74,282	)

The total capital expenditures for the year ended December 31, 2009 include approximately $12 million related to exploration activities.

Exploration and Development Activities

The following table sets forth the gross and net wells in which we participated during the year ended December 31, 2009:

	Exploratory				Development				Total
	Gross		Net		Gross		Net		Gross		Net
Oil wells		0		0		13		7.4		13		7.4
Gas wells		4		4		37		21.8		41		25.8
Dry holes		0		0		1		1		1		1
Total		4		4		51		30.2		55		34.2

Subject to, among other things, the availability of drilling rigs and weather that permits access to drill sites, in the first six months of 2010, we plan to drill, complete and tie-in 17.5net wells.

We estimate capital expenditures of $110 million for the first six months of 2010 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".

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Production Estimates

The following table sets out the volume of our production estimated for the year ended December 31, 2010 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
	(bbls/d)				(bbls/d)				(Mcf/d)				(bbls/d)				(Boe/d)
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Proved Producing		4,373		3,717		899		792		79,962		67,753		1,662		1,219		20,261		17,020
Proved Developed Non-Producing		111		93		22		21		5,868		5,567		1		1		1,112		1,043
Proved Undeveloped		28		14		0		0		12,822		12,068		0		0		2,165		2,025
Total Proved		4,511		3,824		921		812		98,652		85,388		1,663		1,220		23,537		20,088
Total Probable		265		206		59		46		13,468		11,242		92		70		2,662		2,195
Total Proved PlusProbable		4,776		4,030		980		858		112,120		96,630		1,755		1,290		26,199		22,283

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 2009
	Mar. 31		June 30			Sept. 30			Dec. 31			Year Ended Dec. 31, 2009
Average Daily Production(1)
Crude Oil (bbls/d)		8,677		7,989			6,289			5,985			7,225
Gas (MMcf/d)		117,968		124,990			91,200			84,466			104,527
NGLs (bbls/d)		2,265		2,223			2,142			2,503			2,283
Combined (boe/d)		30,603		31,044			23,631			22,566			26,929
Average Net Production Prices Received(2)
Crude Oil ($/bbl)		44.94		61.13			65.34			70.86			59.29
Gas ($/Mcf)		5.36		3.56			2.89			4.28			4.06
NGLs ($/bbl)		37.54		37.06			32.96			44.34			38.10
Combined ($/boe)		36.16		32.72			31.49			39.74			34.90
Gain/(Loss) on Derivatives
Crude Oil ($/bbl)		14.03		(1.76	)		(3.98	)		(7.36	)		1.26
Gas ($/Mcf)		1.16		2.07			3.21			2.62			2.18
Combined ($/boe)		8.48		7.87			11.33			7.84			8.80
Royalties Paid
Crude Oil ($/bbl)		7.47		10.31			11.36			12.30			10.12
Gas ($/Mcf)		0.72		0.24			-			0.26			0.32
NGLs ($/bbl)		12.93		12.93			10.91			11.40			12.03
Combined ($/boe)		5.84		4.53			4.02			5.49			4.99
Operating Expenses(3)(4)
Crude oil ($/bbl)		15.04		15.52			14.25			14.09			14.80
Natural gas ($/Mcf)		2.06		1.86			1.74			1.65			1.84
NGLs ($/bbl)		12.05		12.97			11.54			9.84			11.55
Combined ($/boe)		13.08		12.40			11.55			11.01			12.11
Netback Received(5)
Crude Oil ($/bbl)		36.46		33.54			35.75			37.11			35.63
Gas ($/Mcf)		3.74		3.53			4.36			4.99			4.08
NGLs ($/bbl)		12.56		11.16			10.01			23.10			14.52
Combined ($/boe)		25.72		23.66			27.25			31.08			26.60

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 a well by well basis based upon the relative volume of production of crude oil and NGLs and natural gas.

(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.

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The following table indicates our approximate average daily production from our important fields for the quarter ended December 31, 2009:

	Natural Gas		Crude Oil & NGLs		Total
Properties	(Mcf/d)		(bbls/d)		(boe/d)
Nevis		14,957		1,736		4,229
Glacier		15,073		407		2,919
Willesden Green		4,382		690		1,421
Medicine Hat		7,541		-		1,257
Westerose		3,218		705		1,242
Brazeau/Ferrier		4,472		267		1,013
Eastern Alberta		5,023		123		960
Sunset		2,214		459		828
Red Deer		4,123		132		820
Lookout Butte		3,346		237		795
Major Properties		64,349		4,758		15,483
Other		20,117		3,730		7,083
Total		84,466		8,488		22,566

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)	2010		2011		2012		2013		2014		2015
Building leases	$	3.9	$	1.5	$	1.0	$	-	$	-	$	-
Capital leases		1.5		0.7		-		-		-		-
Pipeline/transportation		4.4		6.6		6.6		6.6		1.7		-
Convertible debentures(1)		69.9		62.3		-		-		-		86.3

Note:

(1) As at December 31, 2009, AOG had $218.5million Debentures outstanding.  Each series of Debentures are convertible to Common Shares based on an established conversion price.  All remaining obligations related to Debentures can be settled through the payment of cash or issuance of Common Shares at AOG'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.

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

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

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

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

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

(d) provide improved recovery systems.

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

(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 "gross reserves", which are our interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of AOG;

(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.

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"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.

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.

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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 4% of our natural gas production is sold to aggregators who accumulate production from various producers and market the gas on behalf of the group.  Such contracts are reserve specific and continue for the life of production from the specified reserves.

Cyclical and Seasonal Impact of Industry

Our operational results and financial condition will be dependent on the prices received for oil and natural gas production.  Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions.  Any decline in oil and natural gas prices could have an adverse effect on our financial condition.  We mitigate such price risk through closely monitoring the various commodity markets and establishing hedging programs, as deemed necessary, to 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 2010 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. Our Environmental Management System is continuously updated and meets the Canadian Association of Petroleum Producers ("CAPP") Environmental Management Guidelines.

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.

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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.

Human Resources

As at December 31, 2009, we employed 129 full-time employees, 105 of which are located in the head office and 24 of which are located in the field.  We also employed 18 consultants in the head office.

DIRECTORS AND OFFICERS

The following table sets forth the name, place of residence, date first elected as a director of AOG and positions for each of the proposed directors and officers of AOG, together with their principal occupations during the last five years.  The directors of AOG shall hold office until the next annual meeting of shareholders or until their respective successors have been duly elected or appointed.

Name, Province and Country of Residence	Position Held and Period Served as a Director or Officer(4)(5)	Principal Occupations During Past Five Years
Kelly I. Drader 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)(7) 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.

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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
Ronald A. McIntosh(1)(3) Alberta, Canada	Director since September 25, 1998(6)	Chairman of North American Energy Partners Inc., a publicly traded corporation and a director of Fortress Energy Inc.
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.
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	Managing Director, The EmBeSa Corporation and Chairman and Chief Executive Officer of Prime Restaurants Royalty Income Fund. Until July, 2009, 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. Prior to EBS, Mr. Sharpe was Executive Vice President of The Kroll-O'Gara Company, New York.
Sheila O'Brien(2) (3) 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) Alberta, 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. He is also Chair of the Audit Committee of C.A. Bancorp and Prime Restaurants Royalty Income Fund.  He is in addition a member of the Board of UBC Investment Management Inc. and a Chairman of Alberta Enterprise Corp.
Patrick J. Cairns Alberta, Canada	Senior Vice President	Senior Vice President of AOG since June 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 Alberta, Canada	Vice President, Finance	Vice President, Finance of AOG since January 27, 2009. Mr. Blackwood is a Chartered Accountant and was the Director of Finance of AOG from November 2004 to January 27, 2009.
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.
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 Reserve Evaluation Committee.

(4) AOG does not have an executive committee of the Board.

(5) AOG's directors shall hold office until the next annual general meeting of Shareholders or until each director's successor is appointed or elected pursuant to the ABCA.

(6) The period of time served by Ronald A. McIntosh as a director of AOG includes the period of time served as a director of Search prior to the Amalgamation, where applicable.  Mr. McIntosh was appointed a director of post-Reorganization Search on May 24, 2001.

(7) 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.

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As at March 16, 2010 the directors and executive officers of AOG, as a group, beneficially owned, directly or indirectly, or exercised control or direction over, 1,777,690 Common Shares, or approximately 1.0% of the issued and outstanding Common Shares.

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 AOG to affect materially the control of 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 AOG to affect materially the control of 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 AOG to affect materially the control of 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 AOG to affect materially the control of 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 AOG to affect materially the control of 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.

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.

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DIVIDEND POLICY

The Corporation does not anticipate paying dividends in the immediate future and will instead direct cash flow to capital expenditures and debt repayment. The amount of future cash dividends, if any, is not assured and will be subject to the discretion of the Board of Directors and may vary depending on a variety of factors, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens and foreign exchange rates.  See "Risk Factors".

DESCRIPTION OF THE CORPORATION'S SECURITIES

Share Capital

The Corporation is authorized to issue an unlimited number of Common Shares, non-voting shares, preferred shares and exchangeable shares.  As of December 31, 2009, there were 162,745,528 Common Shares issued and outstanding and there were no non-voting shares, preferred shares or exchangeable shares issued and outstanding.

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

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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Debentures

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

	6.50%	7.75%	8.00%	5.00%
Trading symbol	AAV.DB.E	AAV.DB.D	AAV.DB.G	AAV.DB.H
Issue date	May 18, 2005	Sep. 15, 2004	Nov. 13, 2006	Dec. 31, 2009
Maturity date	June 30, 2010	Dec. 1, 2011	Dec. 31, 2011	Jan. 30, 2015
Conversion price	$24.96	$21.00	$20.33	$8.60
Outstanding	$69,927,000	$46,766,000	$15,528,000	$86,250,000

The convertible debentures are redeemable prior to their maturity dates, at the option of the Corporation, upon providing appropriate days advance notification as per the terms of the applicable debenture indenture. 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
6.50%	After June 30, 2009 and before June 30, 2010	$1,025
7.75%	After December 1, 2009 and before December 1, 2011	$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
5.00%	After January 31, 2013 and on or before January 30, 2015 (provided that the Current Market Price exceeds 125% of Conversion Price)	$1,000

PRICE RANGE AND TRADING VOLUME OF SECURITIES

Common Shares

The Common Shares are listed and trade on the TSX and the NYSE and commenced trading under the symbol "AAV" following the completion of the Trust Conversion on July 9, 2009.  The following table sets forth the trading history of the Common Shares since July 14, 2009.

Period	High	Low	Volume
	($)	($)
TSX Trading
2009
July (14 to 31)	5.79	5.08	10,493,587
August	6.38	5.33	13,373,774
September	7.75	5.76	15,622,176
October	8.23	6.57	11,246,992
November	7.08	5.72	12,795,740
December	7.25	5.81	15,019,097
NYSE Trading (U.S.$)
2009
July (14 to 31)	5.25	4.39	4,868,319
August	5.85	4.84	7,393,672
September	7.24	5.20	11,286,374
October	7.92	6.08	10,208,374
November	6.71	5.40	6,699,105
December	6.80	5.53	5,027,107

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Trust Units

Prior to completion of the Trust Conversion, the outstanding Trust Units were listed for trading on the TSX under the symbol "AVN.UN" and on the NYSE under the symbol "AAV".  As a result of the completion of the Trust Conversion, the Trust Units were delisted from the TSX and NYSE after the close of markets on July 13, 2009.  The following table sets forth the high and low trading prices and the aggregate trading volume of the Trust Units as reported by the TSX and the NYSE for the periods indicated.

Period	High	Low	Volume
	($)	($)
TSX Trading
2009
January	6.13	5.06	5,658,642
February	5.20	2.62	10,005,123
March	3.77	2.41	16,945,850
April	4.00	2.90	11,483,926
May	5.05	3.12	14,371,076
June	6.57	4.70	24,689,988
July (1 to 13)	5.22	4.05	9,924,777
NYSE Trading (U.S.$)
2009
January	5.20	4.14	4,485,565
February	4.19	2.11	8,684,601
March	3.03	1.87	9,985,242
April	3.30	2.28	5,752,929
May	4.42	2.62	8,012,767
June	5.97	4.16	8,869,692
July (1 to 13)	4.52	3.46	7,148,268

6.50% Debentures

The 6.50% Debentures are listed for trading on the TSX under the symbol "AAV.DB.E". The following table sets forth the high and low 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
	($)	($)
2009
July (14 to 31)	99.50	96.49	15,870
August	100.25	99.00	22,460
September	100.89	99.65	22,130
October	100.80	100.05	13,220
November	101.50	100.20	22,690
December	101.50	100.61	27,980

Prior to completion of the Trust Conversion, the outstanding 6.50% Debentures were listed for trading on the TSX under the symbol "AVN.DB.E". As a result of the completion of the Trust Conversion, the 6.50% Debentures were delisted from the TSX after the close of markets on July 13, 2009.  The following table sets forth the high and low 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
	($)	($)
2009
January	90.00	84.50	12,080
February	88.00	80.00	5,610
March	85.00	79.00	4,080
April	86.24	82.00	6,400
May	94.00	86.00	64,890
June	98.00	92.50	84,990
July (1 to 13)	96.99	95.75	15,980

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7.75% Debentures

The 7.75% Debentures are listed for trading on the TSX under the symbol "AAV.DB.D". The following table sets forth the high and low 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
	($)	($)
2009
July (14 to 31)	93.75	91.75	53,310
August	101.45	97.00	29,410
September	101.45	100.00	14,520
October	101.89	100.50	35,070
November	103.75	102.00	6,390
December	103.99	102.50	4,290

Prior to completion of the Trust Conversion, the outstanding 7.75% Debentures were listed for trading on the TSX under the symbol "AVN.DB.D". As a result of the completion of the Trust Conversion, the 7.75% Debentures were delisted from the TSX after the close of markets on July 13, 2009.  The following table sets forth the high and low 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
	(%)	(%)
2009
January	85.00	77.00	3,660
February	79.68	60.00	3,330
March	74.00	59.00	7,120
April	81.00	73.00	14,390
May	89.50	77.00	3,790
June	94.75	89.00	71,510
July (1 to 13)	93.75	91.75	53,310

8.00% Debentures

The 8.00% Debentures are listed for trading on the TSX under the symbol "AAV.DB.G". The following table sets forth the high and low 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
	($)	($)
2009
July (14 to 31)	100.00	95.00	1,700
August	102.00	97.00	2,480
September	102.00	98.01	1,760
October	102.00	100.25	3,760
November	103.50	101.94	7,630
December	103.99	102.26	3,190

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Prior to completion of the Trust Conversion, the outstanding 8.00% Debentures were listed for trading on the TSX under the symbol "AVN.DB.G". As a result of the completion of the Trust Conversion, the 8.00% Debentures were delisted from the TSX after the close of markets on July 13, 2009.  The following table sets forth the high and low 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
	(%)	(%)
2009
January	95.00	90.00	2,050
February	-	-	-
March	70.00	60.05	550
April	-	-	-
May	85.00	85.00	750
June	95.00	90.00	3,840
July (1 to 13)	95.00	90.00	750

5.00% Debentures

The 5.00% Debentures are listed for trading on the TSX under the symbol "AAV.DB.H". The following table sets forth the high and low trading prices and the aggregate trading volume of the 5.00% Debentures as reported by the TSX for the period indicated.

Period	High	Low	Volume
	($)	($)
2009
December 31	103.00	100.05	78,410

Cash Distributions

Prior to the completion of the Trust Conversion, Unitholders of the Trust of record on a distribution record date were entitled to receive distributions which were paid by the Trust to its Unitholders on the corresponding distribution payment date.  The following is a summary of the distributions made by us for each of the three most recently completed financial years.

For the 2009 Period Ended	Distributions per Unit	Payment Date
January 31	$0.08	February 17, 2009
February 28	$0.04	March 16, 2009
Total:	$0.12

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 31	$0.12	September 15, 2008
September 30	$0.12	October 15, 2008
October 31	$0.12	November 17, 2008
November 30	$0.12	December 15, 2008
December 31	$0.08	January 15, 2009
Total:	$1.40

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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

Note:

(1) 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".

ESCROWED SECURITIES

There are presently no AOG securities held in escrow.

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, 2009 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 Shareholder who beneficially owns or directs or controls more than 10% of the Common Shares or any known associate or affiliate of such persons in any transaction during 2009 or in any proposed transaction which has materially affected or would materially affect AOG.

MATERIAL CONTRACTS

Except for contracts entered into by us in the ordinary course of business or otherwise disclosed herein, the only agreement which is material to AOG is the Credit Facility, a copy of which is available 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 AOG 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.

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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 AOG or of any associate or affiliate of AOG except for Mr. Jay Reid, the Corporate Secretary of AOG, who is a partner of Burnet, Duckworth & Palmer LLP, which law firm provides 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 Common Shares and the 5.00% Debentures, 7.75% Debentures and 8.00% Debentures.

Valiant Trust Company at its offices in Calgary, Alberta and Toronto, Ontario acts as the transfer agent and registrar for the 6.50% debentures.

AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

The audit committee (the "Audit Committee") is comprised of Messrs. 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
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. He is also a director of Fortress Energy Inc.
Paul Haggis Alberta, 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. He is also Chair of the Audit Committee of C.A. Bancorp and Prime Restaurants Royalty Income Fund, a member of the Board of UBC Investment Management Inc. and a Chairman of Alberta Enterprise Corp. 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.

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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 September, 2009:

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 AOG to any governmental body or the public; AOG's systems of internal controls regarding finance, accounting, legal compliance and ethics that management and the Board have established; and AOG'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, AOG'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 AOG 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;

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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 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 AOG 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 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 its annual review procedures, the Board will determine whether any member or proposed nominee for the Audit Committee serves on the Audit Committees of more than three public companies.  To the extent that any member or 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 AOG's annual information circular and annual report on Form 40-F filed with the Securities and Exchange Commission.

Meetings

The Audit Committee shall meet at least four times annually, or more frequently as circumstances dictate.  As part of its job to foster open communication, the Audit Committee should meet at least annually with management, internal auditors 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 AOG'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.

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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 AOG'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 AOG's internal quality control procedures, any material issues raised by the most recent interim quality-control review, or peer review, of AOG or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps to deal with any such issues.

Independent Auditors

12. Recommend to the Board the external auditors to be nominated for appointment by the Shareholders.

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 AOG 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.

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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 AOG.

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 AOG and its subsidiary entities to the auditors during the fiscal year in which the services are provided;

(e) AOG or the subsidiary entity, as the case may be, did not recognize the services as non-audit services at the time of the engagement;

(f) the services are promptly brought to the attention of the Audit Committee and approved, prior to completion of the audit, by the Audit Committee or by one or more of its members to whom authority to grant such approvals has been delegated by the Audit Committee; and

23. Review, 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 AOG's auditing and accounting principles and practices as suggested by the independent auditors or management.

27. Review risk management policies and procedures of 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.

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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 AOG regarding accounting, internal accounting controls or auditing matters; and

(b) the confidential, anonymous submission by employees of AOG of concerns regarding questionable accounting or auditing matters;

which procedure shall be set forth in a "whistle blower program" to be adopted by the Audit Committee in connection with such matters.

Ethical and Legal Compliance

35. Establish, review and update periodically a Code of Ethical Conduct and ensure that management has established a system to enforce this code.

36. Review management's monitoring of AOG'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 AOG's auditors or counsel, as appropriate, any legal matters that could have a significant impact on the organization's financial statements, AOG'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, 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.

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AUDIT SERVICE FEES

Auditor Services Fees

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

Type of Service Provided	2009			2008
Audit Fees	$	663,000	(2)	$	515,200	(1)
Audit-Related Fees		55,000		$	38,440
Tax Fees (these services included general tax consultations)		-		$	154,171

Notes:

(1) Includes work related to the Sound Arrangement.

(2) Includes work related to Trust Unit and 5.00% Debenture offerings.

INDUSTRY CONDITIONS

Companies operating in the oil and natural gas industry are subject to extensive regulation and control of operations (including land tenure, exploration, development, production, refining, transportation, and marketing) as a result of legislation enacted by various levels of government and with respect to the pricing and taxation of oil and natural gas through 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 regulations or controls will affect the Corporation's operations in a manner materially different than they will affect other oil and natural gas companies of similar size.  All current legislation is a matter of public record and the Corporation is 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

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil.  Oil prices are primarily based on worldwide supply and demand.  The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, and contractual terms of sale.  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 a licence requires a public hearing and the approval of the Governor in Council.

Natural Gas

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 for a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such a 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.

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Pipeline Capacity

Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limits the ability to produce and to market oil and 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, the United States 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 signatory countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, that any prohibition in any circumstances in which any other form of quantitative restriction is applied is prohibited, and in the case of import-price requirements, that such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

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

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations which govern royalties, production rates and other matters.  The royalty regime in a given province 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.  Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of 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 or royalty tax credits and are generally introduced when commodity prices are low to encourage exploration and development activity by improving earnings and cash flow within the industry.

Alberta

Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced.

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On October 25, 2007, the Government of Alberta released a report entitled "The New Royalty Framework" ("NRF") containing the Government's proposals for Alberta's new royalty regime which were subsequently implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008.  The NRF took effect on January 1, 2009.  On March 11, 2010, the Government of Alberta announced changes to Alberta's royalty system intended to increase Alberta's competitiveness in the upstream oil and natural gas sectors; specifically, the maximum royalty rates for conventional oil and natural gas production will be decreased effective for the January 2011 production month and certain temporary incentive programs currently in place will be made permanent.  Further details with respect to the changes to Alberta's royalty system are expected to be provided in the coming months.

With respect to conventional oil, the NRF eliminated the classification system used by the previous royalty structure which classified oil based on the date of discovery of the pool.  Under the NRF, royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and incorporates separate variables to account for production rates and market prices.  Royalty rates for conventional oil under the NRF range from 0-50%, an increase from the previous maximum rates of 30-35% depending on the vintage of the oil, and rate caps are set at $120 per barrel.  Effective January 1, 2011, the maximum royalty payable under the NRF will be reduced to 40%.

Royalty rates for natural gas under the NRF are similarly determined using a single sliding rate formula incorporating separate variables to account for production rates and market prices.  Royalty rates for natural gas under the NRF range from 5-50%, an increase from the previous maximum rates of 5-35%, and rate caps are set at $17.75/GJ.  Effective January 1, 2011, the maximum royalty payable under the NRF will be reduced to 36%.

Oil sands projects are also subject to the NRF.  Prior to payout, the royalty is payable on gross revenues of an oil sands project.  Gross revenue royalty rates range between 1-9% depending on the market price of oil: rates are 1% when the market price of oil is less than or equal to $55 per barrel and increase for every dollar of market price of oil increase to a maximum of 9% when oil is priced at $120 or higher.  After payout, the royalty payable is the greater of the gross revenue royalty based on the gross revenue royalty rate of 1-9% and the net revenue royalty based on the net revenue royalty rate.  Net revenue royalty rates start at 25% and increase for every dollar of market price of oil increase above $55 up to 40% when oil is priced at $120 or higher.  An oil sands project reaches payout when its cumulative revenue exceeds its cumulative costs.  Costs include specified allowed capital and operating costs related to the project plus a specified return allowance.  As part of the implementation of the NRF, the Government of Alberta renegotiated existing contracts with certain oil sands producers that were not compatible with the NRF.

In August 2006, the Government of Alberta introduced the Innovative Energy Technologies Program (the "IETP"), which has a stated objective of promoting producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value.  The IETP is backed by a $200 million funding commitment over a five-year period beginning April 1, 2005 and provides royalty adjustments to specific pilot and demonstration projects that utilize innovative technologies to increase recovery from existing reserves.

On April 10, 2008, the Government of Alberta introduced two new royalty programs to be implemented along with the NRF and intended to encourage the development of deeper, higher cost oil and gas reserves.  A five-year program for conventional oil exploration wells over 2,000 metres provides qualifying wells with up to a $1 million or 12 months of royalty relief, whichever comes first, and a five-year program for natural gas wells deeper than 2,500 metres provides a sliding scale royalty credit based on depth of up to $3,750 per metre.

On November 19, 2008, in response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced the introduction of a five-year program of transitional royalty rates with the intent of promoting new drilling.  The 5-year transition option is designed to provide lower royalties at certain price levels in the initial years of a well’s life when production rates are expected to be the highest.  Under this new program companies drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500 m) are 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.  Pursuant to the changes made to Alberta's royalty structure announced on March 11, 2010, producers will only be able to elect to adopt the transitional royalty rates prior to January 1, 2011 and producers that have already elected to adopt the transitional royalty rates as of that date will be permitted to switch to Alberta's conventional royalty structure.  On December 31, 2013, all producers operating under the transitional royalty rates will automatically become subject to Alberta's conventional royalty structure.

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On March 3, 2009, the Government of Alberta announced a three-point incentive program in order to stimulate new and continued economic activity in Alberta.  The program introduced a drilling royalty credit for new conventional oil and natural gas wells and a new well royalty incentive program, both applying to conventional oil or natural gas wells drilled between April 1, 2009 and March 31, 2010.  The drilling royalty credit provides up to a $200 per metre royalty credit for new wells and is primarily expected to benefit smaller producers since the maximum credit available will be determined using the company's production level in 2008 and its drilling activity between April 1, 2009 and March 31, 2010, favouring smaller producers with lower activity levels.  The new well incentive program initially applied to wells that began producing conventional oil or natural gas between April 1, 2009 and March 31, 2010 and provided for a maximum 5% royalty rate for the first 12 months of production on a maximum of 50,000 barrels of oil or 500 MMcf of natural gas.  In June, 2009, the Government of Alberta announced the extension of these two incentive programs for one year to March 31, 2011.  On March 11, 2010, the Government of Alberta announced that the incentive program rate of 5% for the first 12 months of production would be made permanent, with the same volume limitations.

In addition to the foregoing, Alberta currently maintains a royalty reduction program for low productivity oil and oil sands wells, a royalty adjustment program for deep marginal gas wells and a royalty exemption for re-entry wells, among others.

Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the type and vintage of oil, the quantity of oil produced in a month, the value of the oil produced and specified adjustment factors determined monthly by the provincial government.  For Crown royalty and freehold production tax purposes, conventional oil is classified as "heavy oil", "southwest designated oil" or "non-heavy oil other than southwest designated oil".  The conventional royalty and production tax classifications ("fourth tier oil", "third tier oil", "new oil" and "old oil") depend on the finished drilling date of a well and are applied to each of the three crude oil types slightly differently.  Heavy oil is classified as third tier oil (having a finished drilling date on or after January 1, 1994 and before October 1, 2004), fourth tier oil (having a finished drilling date on or after October 1, 2002) or new oil (not classified as either third tier oil or fourth tier oil).  Southwest designated oil uses the same definitions of third and fourth tier oil but new oil is defined as conventional oil produced from a horizontal well having a finished drilling date on or after February 9, 1998 and before October 1, 2002.  For non-heavy oil other than southwest designated oil, the same classification is used but new oil is defined as conventional oil produced from a vertical well completed after 1973 and having a finished drilling date prior to 1994, whereas old oil is defined as conventional oil not classified as third or fourth tier oil or new oil.

Base prices are used to establish lower limits in the price-sensitive royalty structure for conventional oil.  Where average wellhead prices are below the established base prices of $100 per m3 for third and fourth tier oil and $50 per m3 for new oil and old oil, base royalty rates are applied.  Base royalty rates are 5% for all fourth tier oil, 10% for heavy oil that is third tier oil or new oil, 12.5% for southwest designated oil that is third tier oil or new oil, 15% for non-heavy oil other than southwest designated oil that is third tier or new oil, and 20% for old oil.  Where average wellhead prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base oil price.  Marginal royalty rates are 30% for all fourth tier oil, 25% for heavy oil that is third tier oil or new oil, 35% for southwest designated oil that is third tier oil or new oil, 35% for non-heavy oil other than southwest designated oil that is third tier or new oil, and 45% for old oil.

The amount payable as a royalty in respect of natural gas production 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.  Like conventional oil, natural gas is classified as "non-associated gas" or "associated gas" and royalty rates are determined according to the finished drilling date of the respective well.  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.  Non-associated gas is classified as new gas (having a finished drilling date before February 9, 1998 with a first production date on or after October 1, 1976), third tier gas (having a finished drilling date on or after February 9, 1998 and before October 1, 2002), fourth tier gas (having a finished drilling date on or after October 1, 2002) and old gas (not classified as either third tier, fourth tier or new gas).  A similar classification is used for associated gas except that the classification of old gas is not used, the definition of fourth tier gas also includes production from 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 m3 of gas for every m3 of oil, and new gas is defined as oil produced from a well with a finished drilling date before February 9, 1998 that received special approval, prior to October 1, 2002, to produce oil and gas concurrently without gas-oil ratio penalties.

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As with conventional oil production, base prices are used to establish lower limits in the price-sensitive royalty structure for natural gas.  Where average field-gate prices are below the established base prices of $50 per thousand m3 for third and fourth tier gas and $35 per thousand m3 for new gas and old gas, base royalty rates are applied.  Base royalty rates are 5% for all fourth tier gas, 15% for third tier or new gas, and 20% for old gas.  Where average well-head prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base gas price.  Marginal royalty rates are 30% for all fourth tier gas, 35% for third tier and new gas, and 45% for old gas.

The Government of Saskatchewan currently provide a number of targeted incentive programs.  These include both royalty reduction and incentive volume programs, including the following:

• Royalty/Tax Incentive Volumes for Vertical Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 8,000 m3 for deep development vertical oil wells, 4,000 m3 for non-deep exploratory vertical oil wells and 16,000 m3 for deep exploratory vertical oil wells (more than 1,700 metres or within certain formations);

• Royalty/Tax Incentive Volumes for Exploratory Gas Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 25,000,000 m3 for qualifying exploratory gas wells;

• Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 6,000 m3 for non-deep horizontal oil  wells and 16,000 m3 for deep horizontal oil  wells (more than 1,700 metres or within certain formations);

• Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects Implemented on or after October 1, 2002 treating incremental production from waterflood projects as fourth tier oil for the purposes of royalty calculation;

• Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing prior to April 1, 2005 providing Crown royalty and freehold tax determinations based in part on the profitability of enhanced recovery projects pre- and post-payout; and

• Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing on or after April 1, 2005 providing a Crown royalty of 1% of gross revenues on enhanced oil recovery projects pre-payout and 20% post-payout and a freehold production tax of 0% on operating income from enhanced oil recovery projects pre-payout and 8% post-payout.

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.

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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.

Each of the provinces of Alberta, British Columbia and Saskatchewan has implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or license.

In Alberta, the NRF includes a policy of "shallow rights reversion" which provides, for the first time in western Canada, for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licenses.  For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or license.  Holders of leases or licences that have been continued indefinitely 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 order in which these agreements will receive the reversion notice will depend on their vintage and location, with the older leases and licenses receiving reversion notices first beginning in January 2011.  Leases and licences that were granted prior to January 1, 2009 but continued after that date will not be subject to shallow rights reversion until they reach the end of their primary term and are continued (at which time deep rights reversion will be applied); thereafter, the holders of such agreements will be served with shallow rights reversion notices based on vintage and location similar to leases and licences that were already continued as of January 1, 2009.

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, such as sulphur dioxide and nitrous oxide.  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.

In December, 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the "ALUF").  The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province.  It calls for the development of region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.   The Alberta Land Stewardship Act (the "ALSA") was proclaimed in force in Alberta on October 1, 2009, providing the legislative authority for the Government of Alberta to implement the policies contained in the ALUF.  Regional plans established pursuant to the ALSA are deemed to be legislative instruments equivalent to regulations and are binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry.  In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail.  Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan.  The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licenses, approvals and authorizations in order for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan.  Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment.  Although no regional plans have been established under the ALSA, the planning process is underway for the Lower Athabasca Region (which contains the majority of oil sands development) and the South Saskatchewan Region.  While the potential impact of the regional plans established under the ALSA cannot yet be determined, it is clear that such regional plans may have a significant impact on land use in Alberta and may affect the oil and gas industry.

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Climate Change Regulation

Federal

In December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto Protocol"), which requires a reduction in greenhouse gas emissions by signatory countries between 2008 and 2012.  The Kyoto Protocol officially came into force on February 16, 2005 and commits Canada to reduce its greenhouse gas emissions levels to 6% below 1990 "business-as-usual" levels by 2012.

In anticipation of the expiry of the Kyoto Protocol in 2012, government leaders and representatives from approximately 170 countries met in Copenhagen, Denmark from December 6 to 18, 2009 (the "Copenhagen Conference") to attempt to negotiate a successor to the Kyoto Protocol.  The primary result of the Copenhagen Conference was the Copenhagen Accord, which represents a broad political consensus rather than a binding international treaty like the Kyoto Protocol and has not been endorsed by all participating countries.  The Copenhagen Accord reinforces the commitment to reducing GHG emissions contained in the Kyoto Protocol and promises funding to help developing countries mitigate and adapt to climate change.  Although certain countries, including Canada, have committed to reducing their emissions individually or jointly by at least 80% by 2050, the Copenhagen Accord does not establish binding GHG emissions reduction targets.  The Copenhagen Accord calls for a review and implementation of its stated goals by 2016.

In response to the Copenhagen Accord, the Government of Canada has recently indicated that it will seek to achieve a 17% reduction in greenhouse gas emissions from 2005 levels by 2020.  This goal is similar to the goal expressed in previous policy documents which are discussed below.

On February 14, 2007, the House of Commons passed Bill C-288, An Act to ensure Canada meets its global climate change obligations under the Kyoto Protocol.  The resulting Kyoto Protocol Implementation Act came into force on June 22, 2007.  Its stated purpose is to "ensure that Canada takes effective and timely action to meet its obligations under the Kyoto Protocol and help address the problem of global climate change." It requires the federal Minister of the Environment to, among other things, produce an annual climate change plan detailing the measures to be taken to ensure Canada meets its obligations under the Kyoto Protocol.  It also authorizes the establishment of regulations respecting matters such as emissions limits, monitoring, trading and enforcement.

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both greenhouse gases and air pollution.  An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan").  Although draft regulations for the implementation of the Updated Action Plan were intended to be published in the fall of 2008 and become binding on January 1, 2010, no such regulations have been proposed to date.  Further, representatives the Government of Canada have recently indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to greenhouse gas emissions regulation.  The approach of the Unites States is expected to include an absolute cap on emissions combined with allowances to be used for compliance that may be partially auctioned off to regulated entities.  It is also unclear whether the approach adopted by the United States will provide for the payment into a technology fund as a compliance mechanism, as is currently permitted in Alberta and by the Updated Action Plan.  As a result, many provisions of the Updated Action Plan, described below, are expected to be significantly modified.

The stated goal of the Updated Action Plan, as currently drafted, is to reduce greenhouse gas emissions to 20% below 2006 levels by 2020 and 60-70% by 2050.  As noted above, the goal has now been modified by the Government of Canada.  The Updated Action Plan outlines emissions intensity-based targets which will be applied to regulated sectors on either a facility-specific, sector-wide or company-by-company basis.  Facility-specific targets applied to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors.  Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets.

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The Updated Action Plan makes a distinction between "Existing Facilities" and "New Facilities".  For Existing Facilities, the Updated Action Plan requires an emissions intensity reduction of 18% below 2006 levels by 2010 followed by a continuous annual emissions intensity improvement of 2%.  "New Facilities" are defined as facilities beginning operations in 2004 and include both greenfield facilities and major facility expansions that (i) result in a 25% or greater increase in a facility's physical capacity, or (ii) involve significant changes to the processes of the facility.  New Facilities will be given a 3-year grace period during which no emissions intensity reductions will be required.  Targets requiring an annual 2% emissions intensity reduction will be begin to apply in the fourth year of commercial operation of a New Facility.  Further, emissions intensity targets for New Facilities will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time.  The method of applying this cleaner fuel standard has not yet been determined.  In addition, the Updated Action Plan indicates that targets for the adoption of carbon capture and storage ("CCS") technologies will be developed for oil sands in-situ facilities, upgraders and coal-fired power generators that begin operations in 2012 or later.  These targets will become operational in 2018, although the exact nature of the targets has not yet been determined.

Given the large number of small facilities within the upstream oil and gas and natural gas pipeline sectors, facilities within these sectors will only be subject to emissions intensity targets if they meet certain minimum emissions thresholds.  That threshold will be (i) 50,000 tonnes of CO2 equivalents per facility per year for natural gas pipelines; (ii) 3,000 tonnes of CO2 equivalents per facility per year for the upstream oil and gas facility; and (iii) 10,000 boe/d/company.  These regulatory thresholds are significantly lower than the regulatory threshold in force in Alberta, discussed below.  In all other sectors govern by the Updated Action Plan, all facilities will be subject to regulation

Four separate compliance mechanisms are provided for in the Updated Action Plan in respect of the above targets: Technology Fund contributions, offset credits, clean development credits and credits for early action.  Regulated entities will be able to use Technology Fund contributions to meet their emissions intensity targets.  The contribution rate for Technology Fund contributions will increase over time, beginning at $15 tonnes per CO2 equivalent for the 2010-12 period, rising to $20 in 2013, and thereafter increasing at the nominal rate of GDP growth.  Maximum contribution limits will also 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 described 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 purchase the offset credits for cancellation or banking 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 which facilitates investment by developed nations in emissions-reduction projects in developing countries.  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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Alberta

Alberta enacted the Climate Change and Emissions Management Act (the "CCEMA") on July 1, 2007, amending it through the Climate Change and Emissions Management Amendment Act which received royal asset on November 4, 2008.  The CCEMA is based on an emissions intensity approach similar to the Updated Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020.

Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year are subject to comply with the CCEMA.  Similarly to the Updated Action Plan, the CCEMA and the associated Specified Gas Emitters Regulation make a distinction between "Existing Facilities" and "New Facilities".  Existing Facilities are defined as facilities that completed their first year of commercial operation prior to January 1, 2008 or that have completed 8 or more years of commercial operation.  Existing Facilities were required to reduce their emissions intensity by March 31, 2008 by 12% from a baseline established by their average emissions intensity between 2003 and 2005.  New Facilities are defined as facilities that completed their first year of commercial operation subsequent to December 31, 2008, have completed less than 8 years of commercial operation, or are designated as New Facilities in accordance with the Specified Gas Emitters Regulation.  New Facilities are also required to reduce their emissions intensity by 12% but this target is based on the emissions intensity of the facility in its third year of commercial operation and does not apply during the first 3 years of operation of the New Facility.  Unlike the Updated Action Plan, the CCEMA does not contain any provision for continuous annual improvements beyond the 12% emissions intensity required.

The CCEMA contains similar compliance mechanisms as the Updated Action Plan.  Regulated emitters can meet their emissions intensity targets by contributing to the Climate Change and Emissions Management Fund (the "Fund") at a rate of $15 per tonne of CO2 equivalent.  Unlike the Updated Action Plan, CCEMA contains no provisions for an increase to this contribution rate.  Emissions credits can be purchased from regulated emitters that have reduced their emissions below the 100,000 tonne threshold or non-regulated emitters that have generated emissions offsets through activities that result in emissions reductions in accordance with established protocols published by the Government of Alberta.  Unlike the Updated Action Plan, the CCEMA does not contemplate a linkage to external compliance mechanisms such as the Kyoto Protocol's Clean Development Mechanism.

Saskatchewan

On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act (the "MRGGA") to regulate greenhouse gas emissions in the province.  Although the MRGGA has only passed first reading in the Saskatchewan legislature and the specific details of the legislation have not yet been determined, it is expected that the MRGGA will adopt the goal of a 20% reduction in greenhouse gas emissions by 2020 and permit the use of technology fund contributions and emissions offsets in compliance, similar to both the federal and Alberta climate change initiatives.  It remains unclear whether the scheme implemented by the MRGGA will be based on emissions intensity or an absolute cap on emissions.

RISK FACTORS

The following is a summary of certain risk factors relating to the business of AOG.  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.

Investors should carefully consider the risk factors set out below and consider all other information contained herein and in the Corporation's other public filings before making an investment decision.

Prices, Markets and Marketing

The marketability and price of oil and natural gas that may be acquired or discovered by the Corporation is and will continue to be affected by numerous factors beyond its control.  The Corporation'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 Corporation 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.

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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 Corporation'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 Corporation's reserves.  The Corporation might also elect not to produce from certain wells at lower prices.  All of these factors could result in a material decrease in the Corporation'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 Corporation.  These factors include economic conditions, in the United States and Canada, the actions of OPEC, 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 Corporation's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

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

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  The long-term commercial success of the Corporation depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves.  Without the continual addition of new reserves, any existing reserves the Corporation may have at any particular time, and the production therefrom will decline over time as such existing reserves are exploited.  A future increase in the Corporation's reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects.  No assurance can be given that the Corporation will be able to continue to locate satisfactory properties for acquisition or participation.  Moreover, if such acquisitions or participations are identified, management of the Corporation may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.  There is no assurance that further commercial quantities of oil and natural gas will be discovered or acquired by the Corporation.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs.  Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.  In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells.  These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.  While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

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Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury.  In particular, the Corporation may explore for and produce sour natural gas in certain areas.  An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Corporation.  In accordance with industry practice, the Corporation is not fully insured against all of these risks, nor are all such risks insurable.  Although the Corporation maintains liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event the Corporation could incur significant costs.  Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations.  Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

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 continued 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.  Although economic conditions improved towards the latter portion of 2009, these factors have negatively impacted company valuations and may impact the performance of the global economy going forward.

Substantial Capital Requirements

The Corporation anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future.  If the Corporation's revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs.  In addition, uncertain levels of near term industry activity coupled with the present global credit crisis exposes the Corporation to additional access to capital risk.  There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Corporation.  The inability of the Corporation to access sufficient capital for its operations could have a material adverse effect on the Corporation's business financial condition, results of operations and prospects.

Additional Funding Requirements

The Corporation's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times.  From time to time, the Corporation may require additional financing in order to carry out its oil and gas acquisition, exploration and development activities.  Failure to obtain such financing on a timely basis could cause the Corporation to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations.  If the Corporation's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Corporation's ability to expend the necessary capital to replace its reserves or to maintain its production.  If the Corporation's cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on terms acceptable to the Corporation.  Continued uncertainty in domestic and international credit markets could materially affect the Corporation's ability to access sufficient capital for its capital expenditures and acquisitions, and as a result, may have a material adverse effect on the Corporation's ability to execute its business strategy and on its business, financial condition, results of operations and prospects.

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Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves.  The reserve and associated cash flow information set forth herein are estimates only.  In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results.  For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary.  The Corporation's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history.  Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools.  Estimates based on these methods are generally less reliable than those based on actual production history.  Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

In accordance with applicable securities laws, the Corporation's independent reserves evaluator has used forecast prices and costs in estimating the reserves and future net cash flows as summarized herein.  Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived from the Corporation's oil and gas reserves will vary from the estimates contained in the reserve evaluation, and such variations could be material.  The reserve evaluation is based in part on the assumed success of activities the Corporation intends to undertake in future years.  The reserves and estimated cash flows to be derived therefrom contained in the reserve evaluation will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation.  The reserve evaluation is effective as of a specific effective date and has not been updated and thus does not reflect changes in the Corporation's reserves since that date.

Project Risks

The Corporation manages a variety of small and large projects in the conduct of its business.  Project delays may delay expected revenues from operations.  Significant project cost over-runs could make a project uneconomic.  The Corporation's ability to execute projects and market oil and natural gas depends upon numerous factors beyond the Corporation's control, including:

• the availability of processing capacity;

• the availability and proximity of pipeline capacity;

• the availability of storage capacity;

• the supply of and demand for oil and natural gas;

• the availability of alternative fuel sources;

• the effects of inclement weather;

• the availability of drilling and related equipment;

• unexpected cost increases;

• accidental events;

• currency fluctuations;

• changes in regulations;

• the availability and productivity of skilled labour; and

• the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

Because of these factors, the Corporation could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that it produces.

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Hedging

From time to time the Corporation may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, the Corporation will not benefit from such increases and the Corporation may nevertheless be obligated to pay royalties on such higher prices, even though not received by it, after giving effect to such agreements.  Similarly, from time to time the Corporation may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United States dollar, the Corporation will not benefit from the fluctuating exchange rate.

Issuance of Debt

From time to time the Corporation may enter into transactions to acquire assets or the shares of other organizations.  These transactions may be financed in whole or in part with debt, which may increase the Corporation's debt levels above industry standards for oil and natural gas companies of similar size.  Depending on future exploration and development plans, the Corporation may require additional equity and/or debt financing that may not be available or, if available, may not be available on favourable terms.  Neither the Corporation's articles nor its by-laws limit the amount of indebtedness that the Corporation may incur.  The level of the Corporation's indebtedness from time to time, could impair the Corporation's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

Availability of Drilling Equipment and Access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted.  Demand for such limited equipment or access restrictions may affect the availability of such equipment to the Corporation and may delay exploration and development activities.

Management of Growth

The Corporation may be subject to growth-related risks including capacity constraints and pressure on its internal systems and controls.  The ability of the Corporation to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expand, train and manage its employee base.  The inability of the Corporation to deal with this growth may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Variations in Foreign Exchange Rates and Interest Rates

World oil and gas prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time.  In recent years, the Canadian dollar has increased materially in value against the United States dollar.  Material increases in the value of the Canadian dollar negatively impact the Corporation's production revenues.  Future Canadian/United States exchange rates could accordingly impact the future value of the Corporation's reserves as determined by independent evaluators.

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To the extent that the Corporation engages in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which the Corporation may contract.

An increase in interest rates could result in a significant increase in the amount the Corporation pays to service debt, which could negatively impact the market price of the Common Shares of the Corporation.

Regulatory

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time.  See "Industry Conditions".  Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas.  Such regulations may be changed from time to time in response to economic or political conditions.  The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for natural gas and crude oil and increase the Corporation's costs, any of which may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  In order to conduct oil and gas operations, the Corporation will require licenses from various governmental authorities.  There can be no assurance that the Corporation will be able to obtain all of the licenses and permits that may be required to conduct operations that it may wish to undertake.

Geo-Political Risks

The marketability and price of oil and natural gas that may be acquired or discovered by the Corporation is and will continue to be affected by political events throughout the world that cause disruptions in the supply of oil.  Conflicts, or conversely peaceful developments, arising in the Middle-East, and other areas of the world, have a significant impact on the price of oil and natural gas.  Any particular event could result in a material decline in prices and therefore result in a reduction of the Corporation's net production revenue.

In addition, the Corporation's oil and natural gas properties, wells and facilities could be subject to a terrorist attack.  If any of the Corporation's properties, wells or facilities are the subject of terrorist attack it may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  The Corporation will not have insurance to protect against the risk from terrorism.

Climate Change

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called "greenhouse gases".  Recently, representatives from approximately 170 countries met in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol.  Pursuant to the resulting Copenhagen Accord, a non-binding political consensus rather than a binding international treaty such as the Kyoto Protocol, the Government of Canada revised its emissions reduction targets slightly.  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.  The Corporation's exploration and production facilities and other operations and activities emit greenhouse gases and require the Corporation to comply with Alberta's greenhouse gas emissions legislation contained in the Climate Change and Emissions Management Amendment Act and the Specified Gas Emitters Regulation.  The Corporation may also be required comply with the regulatory scheme for greenhouse gas emissions ultimately adopted by the federal government, which is now expected to be modified to ensure consistency with the regulatory scheme for greenhouse gas emissions adopted by the United States.  The direct or indirect costs of these regulations may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  The future implementation or modification of greenhouse gases regulations, whether to meet the limits required by the Kyoto Protocol, the Copenhagen Accord or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including those of the Corporation.  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 the impact on the Corporation and its operations and financial condition.  See "Industry Conditions - Climate Change Regulation".

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Environmental

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.  Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations.  The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material.  Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.  The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge.  Although the Corporation believes that it will be in material compliance with current applicable environmental regulations, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Competition

The petroleum industry is competitive in all its phases.  The Corporation competes with numerous other organizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas.  The Corporation's competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of the Corporation.  The Corporation's ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling.  Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery and storage.  Competition may also be presented by alternate fuel sources.

Insurance

The Corporation's involvement in the exploration for and development of oil and natural gas properties may result in the Corporation becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards.  Although the Corporation maintains insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities.  In addition, such risks are not, in all circumstances, insurable or, in certain circumstances, the Corporation may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons.  The payment of any uninsured liabilities would reduce the funds available to the Corporation.  The occurrence of a significant event that the Corporation is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Reliance on Key Personnel

The Corporation's success depends in large measure on certain key personnel.  The loss of the services of such key personnel may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  The Corporation does not have any key person insurance in effect for the Corporation. The contributions of the existing management team to the immediate and near term operations of the Corporation are likely to be of central importance.  In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Corporation will be able to continue to attract and retain all personnel necessary for the development and operation of its business.  Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of the Corporation.

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Third Party Credit Risk

The Corporation may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties.  In the event such entities fail to meet their contractual obligations to the Corporation, such failures may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.  In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Corporation's ongoing capital program, potentially delaying the program and the results of such program until the Corporation finds a suitable alternative partner.

Title to Assets

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the Corporation's claim which may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Seasonality

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns.  Wet weather and spring thaw may make the ground unstable.  Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels.  Also, certain oil and gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain.  Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for the goods and services of the Corporation.

Expiration of Licences and Leases

The Corporation's properties are held in the form of licences and leases and working interests in licences and leases.  If the Corporation or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire.  There can be no assurance that any of the obligations required to maintain each licence or lease will be met.  The termination or expiration of the Corporation's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The Corporation makes acquisitions and dispositions of businesses and assets in the ordinary course of business.  Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as the Corporation's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation.  The integration of acquired business may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters.  Management continually assesses the value and contribution of services provided and assets required to provide such services.  In this regard, non-core assets are periodically disposed of, so that the Corporation can focus its efforts and resources more efficiently.  Depending on the state of the market for such non-core assets, certain non-core assets of the Corporation, if disposed of, could be expected to realize less than their carrying value on the financial statements of the Corporation.

Operational Dependence

Other companies operate some of the assets in which the Corporation has an interest.  As a result, the Corporation has limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Corporation's financial performance.  The Corporation's return on assets operated by others therefore depends upon a number of factors that may be outside of the Corporation's control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

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Dilution

The Corporation may make future acquisitions or enter into financings or other transactions involving the issuance of securities of the Corporation which may be dilutive.

Conflicts of Interest

Certain directors of the Corporation are also directors of other oil and gas companies and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions.  Conflicts, if any, will be subject to the procedures and remedies of the ABCA.  See "Conflicts of Interest".

Aboriginal Claims

Aboriginal peoples have claimed aboriginal title and rights to portions of Canada.  The Corporation is not aware that any claims have been made in respect of its properties and assets; however, if a claim arose and was successful such claim may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Dividends

The Corporation has not paid any dividends on its outstanding shares.  Payment of dividends in the future will be dependent on, among other things, the cash flow, results of operations and financial condition of the Corporation, the need for funds to finance ongoing operations and other considerations as the board of directors of the Corporation considers relevant.

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE

As a foreign private issuer listed on the NYSE, AOG is not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic Canadian requirements.  AOG is, however, required to comply with the following NYSE Rules: (i) AOG must have an audit committee that satisfies the requirements of Rule 10A-3 under the United States Securities Exchange Act of 1934, as amended; (ii) 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; (iii) submit an executed annual written affirmation to the NYSE, as well as an interim affirmation each time certain changes occurs to the audit committee; and (iv) provide a brief description of any significant differences between its corporate governance practices and those followed by U.S. domestic issuers listed under the NYSE.  AOG has reviewed the NYSE listing standards and confirms that its corporate governance practices do not differ significantly from such standards.

ADDITIONAL INFORMATION

Additional information relating to the Corporation can be found on SEDAR at www.sedar.com.

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of Common Shares and securities authorized for issuance under equity compensation plans, will be contained in the Corporation's Information Circular for the most recent annual meeting of shareholders that involved the election of directors of AOG.

Additional financial information is provided for in the Corporation's financial statements and management's discussion and analysis for the year ended December 31, 2009.

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SCHEDULE "A"

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

(FORM 51-101F3)

Management of Advantage Oil & Gas Ltd. ("AOG") is responsible for the preparation and disclosure of information with respect to AOG'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, 2009, estimated using forecast prices and costs.

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

The independent reserves evaluation committee of AOG has:

(a) reviewed AOG'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 AOG'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 16, 2010

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. (the "Company"):

1. We have evaluated the Company's Reserves Data as at December 31, 2009.  The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2009, estimated using forecast prices and costs.

2. The Reserves Data are the responsibility of the Company'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 Company evaluated by us as of December 31, 2009, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's management and Board of Directors:

Independent Qualified Reserves Evaluator or Auditor	Description and Preparation Date of Evaluation Report	Location of Reserves (County)	Net Present Value of Future Net Revenue Before Income Taxes (10% Discount Rate)
			Audited (M$)	Evaluated (M$)	Reviewed (M$)	Total (M$)
Sproule Associates Limited	Evaluation of the P&NG Reserves of Advantage Oil & Gas Ltd.	Canada
	As of December 31, 2009, prepared October 2009 to February 2010		Nil	2,773,428	Nil	2,773,428
Total			Nil	2,773,428	Nil	2,773,428

5. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook.

6. We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date.

7. Because the reserves data are based 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.

Executed as to our report referred to above:

Sproule Associates Limited Calgary, Alberta March 8, 2010 Original Signed by Cameron P. Six, P. Eng. Cameron P. Six, P. Eng. Manager, Engineering   Original Signed by Brent A. Hawkwood, C.E.T.. Brent A. Hawkwood, C.E.T. Shareholder   Original Signed by Tanja M. Hale, P. Eng. Tanja M. Hale, P. Eng. Senior Petroleum Engineer   Original Signed by Henry C.J. VanderRee, MBA, P. Eng. Henry C.J. VanderRee, MBA, P. Eng. Senior Petroleum Engineer   Original Signed by Vadim Y. Savenkov, P. Eng. Vadim Y. Savenkov, P. Eng. Associate   Original Signed by John Hanko, P. Geol. John Hanko, P. Geol. Associate   Original Signed by Harry J. Helwerda, P. Eng. Harry J. Helwerda, P. Eng. Executive Vice-President

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