ANNUAL INFORMATION
FORM



YEAR ENDED
DECEMBER 31, 2011



March 23, 2012











TABLE OF
CONTENTS



|                                                                                   | Page
|---------------------------------------------------------------------------------- | ----
|                                                                                   |     
|GLOSSARY OF TERMS                                                                  | 1   
|ABBREVIATIONS                                                                      | 6   
|CONVERSION                                                                         | 6   
|NON-GAAP MEASURES                                                                  | 8   
|ADVANTAGE OIL & GAS LTD.                                                           | 9   
|GENERAL DEVELOPMENT OF THE BUSINESS                                                | 10  
|DESCRIPTION OF OUR BUSINESS AND OPERATIONS                                         | 13  
|STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION                       | 15  
|DIRECTORS AND OFFICERS                                                             | 40  
|DIVIDEND POLICY                                                                    | 44  
|DESCRIPTION OF THE CORPORATION'S SECURITIES                                        | 45  
|PRICE RANGE AND TRADING VOLUME OF SECURITIES                                       | 46  
|ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER | 48  
|LEGAL PROCEEDINGS                                                                  | 48  
|REGULATORY ACTIONS                                                                 | 48  
|INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS                         | 48  
|MATERIAL CONTRACTS                                                                 | 49  
|INTEREST OF EXPERTS                                                                | 50  
|AUDITORS, TRANSFER AGENT AND REGISTRAR                                             | 50  
|AUDIT COMMITTEE INFORMATION                                                        | 51  
|AUDIT COMMITTEE CHARTER                                                            | 52  
|AUDIT SERVICE FEES                                                                 | 58  
|INDUSTRY CONDITIONS                                                                | 58  
|RISK FACTORS                                                                       | 69  
|DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE             | 81  
|ADDITIONAL INFORMATION                                                             | 81  



|SCHEDULES
|---------
|         
|"A"      
|"B"      











GLOSSARY
OF TERMS



Selected Defined 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 which matured on June 30, 2010;



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



"8.00% Debentures" means
8.00% convertible unsecured subordinated debentures of the Corporation which matured on 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;



"GAAP" means generally
accepted accounting principles for publicly accountable enterprises in Canada which is currently in accordance with IFRS;



"IFRS" means International
Financial Report Standards as issued by the International Accounting Standards Board;



"Longview" means Longview
Oil Corp., a corporation incorporated under the ABCA;



"Longview Non-Controlling Interest"
means the approximately 37% interest of third party minority public shareholders in the common shares of Longview;



"NYSE" means the New York
Stock Exchange;



"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;



"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;



2







"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.



Selected Defined
Oil and Gas Terms



"API" means the American
Petroleum Institute;



"API gravity" means the
American Petroleum Institute gravity expressed in degrees in relation to liquids, which is a measure of how heavy or light a petroleum
liquid is compared to water. If a petroleum liquid's API gravity is greater than 10, it is lighter and floats on water; if less
than 10, it is heavier than water and sinks. API gravity is thus a measure of the relative density of a petroleum liquid and the
density of water, but it is used to compare the relative densities of petroleum liquids;



"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 (Petroleum Society) as amended from time to time;



"Current Production" means
average daily gross production for the three month period ended December 31, 2011;



"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;



"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;



"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;



"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;
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



3







| | (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
(collectively referred to as "geological and geophysical costs");
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| | (c) | dry hole contributions and bottom hole contributions;
| | --- | -----------------------------------------------------



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



| | (e) | costs of drilling exploratory type stratigraphic test wells;
| | --- | ------------------------------------------------------------



"forecast
prices and costs" means future prices and costs that are:



| | (a) | generally accepted as being a reasonable outlook of the future; or
| | --- | ------------------------------------------------------------------



| | (b) | if, and only to the extent that, there are fixed or presently determinable future prices or costs
to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for
an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred
to in subparagraph (a);
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



"gross"
means:



| | (a) | in relation to an entity's interest in production and reserves, its "company gross reserves",
which are such entity's working interest (operating or non-operating) share before deduction of royalties and without including
any royalty interest of such entity;
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (b) | in relation to wells, the total number of wells in which an entity has an interest; and
| | --- | ---------------------------------------------------------------------------------------



| | (c) | in relation to properties, the total area of properties in which an entity has an interest;
| | --- | -------------------------------------------------------------------------------------------



"net"
means:



| | (a) | in relation to an entity's interest in production and reserves, such entity's working interest
(operating or non-operating) share after deduction of royalty obligations, plus the entity's royalty interests in production or
reserves;
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (b) | in relation to an entity's interest in wells, the number of wells obtained by aggregating an entity's
working interest in each of its gross wells; and
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------



4







| | (c) | in relation to an entity's interest in a property, the total area in which an entity has an interest
multiplied by the working interest owned by it;
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------



"NI 51-101" means National
Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities;



"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;



"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;



"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;



"reserves" are estimated
remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of
a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology;
and (iii) specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to
the degree of certainty associated with the estimates;



"resource play" refers
to drilling programs targeted at regionally distributed crude oil or natural gas accumulations; successful exploitation of these
reservoirs is dependent upon technologies such as horizontal drilling and multi-stage fracture stimulation to access large rock
volumes in order to produce economic quantities of oil or natural gas;



"Total Current Production"
means aggregate average daily gross production from the Properties for the three month period ended December 31, 2011; and



"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.



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.



5







ABBREVIATIONS



|Oil and Natural Gas Liquids |                                                                                                                         | Natural Gas
|--------------------------- | ----------------------------------------------------------------------------------------------------------------------- | -----------
|                            |                                                                                                                         |            
|bbls                        | barrels                                                                                                                 |            
|Mbbls                       | thousand barrels                                                                                                        |            
|MMbbls                      | million barrels                                                                                                         |            
|NGLs                        | natural gas liquids                                                                                                     |            
|stb                         | stock tank barrels of oil                                                                                               |            
|Mstb                        | thousand stock tank barrels of oil                                                                                      |            
|MMboe                       | million barrels of oil equivalent                                                                                       |            
|boe/d                       | barrels of oil equivalent per day                                                                                       |            
|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.
|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.                                                                                          



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. As the value ratio between natural gas and crude oil
based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing
a conversion on a 6:1 basis may be misleading as an indication of value.



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.



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      



6







FORWARD-LOOKING
STATEMENTS



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, but not limited 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;
| | - | ---------------------------------------

| | · | 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;
| | - | ---------------

| | · | estimated timing of capital expenditures;
| | - | -----------------------------------------

| | · | future development plans for the Corporation's assets;
| | - | ------------------------------------------------------

| | · | focus of capital budget;
| | - | ------------------------

| | · | timing of development of undeveloped reserves;
| | - | ----------------------------------------------

| | · | future abandonment and reclamation costs;
| | - | -----------------------------------------

| | · | tax horizons;
| | - | -------------

| | · | terms of Longview's material contracts discussed under "Material Contracts";
| | - | ----------------------------------------------------------------------------

| | · | treatment under governmental regulatory regimes and tax laws; and
| | - | -----------------------------------------------------------------

| | · | capital expenditures programs.
| | - | ------------------------------



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.



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;
| | - | --------------------------------------------------------------------------------------------------------------



7







| | · | geological, technical, drilling and processing problems and other difficulties in producing petroleum
reserves; and
| | - | -------------------------------------------------------------------------------------------------------------------

| | · | the other factors discussed under "Risk Factors".
| | - | -------------------------------------------------



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, but not limited to: 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; future operating costs; that the Corporation will have
sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures
and requirements as needed; that the Corporation’s conduct and results of operations will be consistent with its expectations;
that the Corporation will have the ability to develop the Corporation’s oil and gas properties in the manner currently contemplated;
current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated
as described herein; and the estimates of the Corporation’s reserves volumes and the assumptions related thereto (including
commodity prices and development costs) are accurate in all material respects.



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.



Moreover, the current global economic conditions
and uncertainty, including the current volatility in financial markets, is adding a substantial amount of risk to the North American
and worldwide economy, and the continuation of such factors may adversely impact the Corporation's anticipated or expected results
of operations and may cause the actual results to materially deviate from the forward-looking information contained in this annual
information form.



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 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, comprehensive income, and 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.



Funds from operations, as presented, is
based on cash provided by operating activities before expenditures on asset retirement and changes in non-cash working capital
reduced for finance expense excluding accretion. Cash netbacks are dependent on the determination of funds from operations and
include the primary cash sales and expenses on a per boe basis that comprise funds from operations.



8







ADVANTAGE
OIL & GAS LTD.



General



The Corporation was formed pursuant to
the amalgamation of Advantage Oil & Gas Ltd., 1335703 Alberta Ltd., SET Resources Inc. 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 2400, 525 –
8th Avenue S.W., Calgary, Alberta T2P 1G1.



Corporate Structure



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









Note:



| | (1) | On April
                                                            14, 2011, Advantage’s subsidiary, Longview Oil Corp., completed
                                                            its initial public offering of common shares (the "Longview
                                                            Offering") and purchased certain oil-weighted assets from
                                                            Advantage for consideration comprised of cash and 29,450,000 common
                                                            shares (the "Longview Transaction"). As a result
                                                            of the Longview Offering and the Longview Transaction, Advantage currently
                                                            holds approximately 63% of the common shares of Longview and the remaining
                                                            37% is held by public shareholders. See "General Development
                                                            of the Business – 2011".
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



9







GENERAL
DEVELOPMENT OF THE BUSINESS



General



The Corporation and its subsidiaries are
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 and its subsidiaries is outlined below. Unless the context otherwise
requires, references to "we", "us", "our" or similar terms, or to the "Trust" refer to
the Corporation.



Three Year History



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 takeover 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, the Trust 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.



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, the Trust further announced
that as another step to increase the Trust’s financial flexibility and to focus on development and growth at its 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





10







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 was 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 was to focus on development
of our Montney natural gas resource play at the Glacier property where Advantage was to 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 MMcf/d and included wells, compression facilities and additional pipelines. Phase II of the development plan was undertaken
from July, 2009 to July, 2010 and was designed to increase production capacity to approximately 50 MMcf/d by mid-year 2010. Phase
III of the development plan was intended to increase production capacity to 100 MMcf/d 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.



On December 7, 2009, the Corporation provided
an operational update regarding its Montney drilling program at the Glacier property and highlighted 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.



2010



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



On April 19, 2010, the Corporation announced
that production from the Corporation's Glacier property exceeded 50 MMcf/d with the commissioning of Advantage’s new 100%
working interest gas plant at Glacier.



11







On May 10, 2010, the Corporation announced
that it had signed purchase and sale agreements relating to the disposition of non-core natural gas weighted assets located in
South Eastern Alberta for gross cash proceeds of $67 million, subject to customary adjustments. The disposition was comprised of
two separate transactions which included combined production of approximately 1,700 boe/d (80% natural gas) and proved plus probable
reserves of 6.4 MMboe as at December 31, 2009. The transactions closed on May 31, 2010 and June 3, 2010 with effective dates of
March 1, 2010 and April 1, 2010, respectively. The net proceeds from these dispositions were initially used to repay bank indebtedness
under the Credit Facilities.



On June 14, 2010, the Board of Directors
of AOG approved a capital budget and updated guidance for the twelve month period ending June 30, 2011. The capital budget was
focused on increasing production at the Glacier property from 50 MMcf/d to a target of 100 MMcf/d by the second quarter of 2011.
Capital expenditures during the period were estimated to be approximately $219 million (80% directed to the Glacier property) and
to be funded out of funds from operations.



On June 25, 2010, the Corporation announced
that its lenders had completed their review of the borrowing base of the Credit Facilities, which would remain unchanged at $525
million and continue to provide significant financial flexibility in support of future capital program requirements and general
corporate purposes.



2011



Longview Offering and Longview Transaction



On April 14, 2011, Longview completed the
Longview Offering and completed the acquisition of certain oil-weighted assets (the "Acquired Assets") of the
Corporation located in West Central Alberta, Southeast Saskatchewan and the Lloydminster area of Saskatchewan. Pursuant to the
Longview Offering, Longview issued 15,000,000 common shares at $10.00 per common share for aggregate gross proceeds of $150,000,000.
The over-allotment option granted by Longview to the underwriters pursuant to the Longview Offering to purchase up to an additional
2,250,000 common shares at a purchase price of $10.00 per common share was exercised in full on April 28, 2011.



The purchase price for the Longview Transaction
was approximately $554.1 million, prior to closing adjustments pursuant to the terms of the purchase and sale agreement for the
Acquired Assets. The purchase price for the Acquired Assets was comprised of the net proceeds of the Longview Offering (including
the net proceeds from the exercise of the over-allotment option) in the amount of $162.1 million, the issuance of 29,450,000 common
shares to the Corporation and approximately $83.4 million drawn from Longview's credit facilities. As a result of the Longview
Offering and the Longview Transaction, Advantage retained an equity ownership interest of approximately 63% of the common shares
of Longview. See "Statement of Reserves Data and Other Oil & Gas Information - Ownership of Longview - Interests of
Minority Shareholders in Longview Reserves".



Concurrent with closing of the Longview
Offering, AOG entered into a Technical Services Agreement (the "TSA") with Longview. Under the TSA, AOG provides
the necessary personnel and technical services to manage Longview's business and Longview reimburses AOG on a monthly basis for
its share of administrative charges based on respective levels of production. Longview has an independent board of directors and
the officers of Longview are Kelly Drader (President and Chief Executive Officer), Craig Blackwood (Chief Financial Officer), Andy
Mah (Chief Operating Officer), Patrick Cairns (Senior Vice President), Neil Bokenfohr (Vice President, Exploitation) and Weldon
Kary (Vice President, Geosciences and Land). The officers of Longview provide services to Longview under the TSA but remain as
employees of Advantage. See "Material Contracts".



In connection with the Longview Transaction,
on April 14, 2011, Longview entered into a credit agreement with a syndicate of financial lenders for an extendible revolving credit
facility in the maximum principal amount of $180 million as well as an operating credit agreement with a Canadian financial institution
in the maximum principal amount of $20 million (collectively, the "Longview Credit Facilities"). See "Material
Contracts".



12







As a result of the sale of the assets pursuant
to the Longview Transaction, Advantage's borrowing base under its Credit Facilities was reduced to $275 million.



Other Developments



On July 4, 2011, the Board of Directors
of AOG approved a capital and operating budget for the twelve month period ending June 30, 2012. The capital budget is focused
on a Phase IV development program at Glacier with two key objectives to: (i) increase throughput capacity at the Glacier gas plant
from 100 MMcf/d to 140 MMcf/d by Q2 2012 and drill a sufficient number of wells to fill the plant; and (ii) further evaluate the
Middle and Lower Montney formations.



On December 20, 2011 the board of directors
of Longview approved operational guidance and a capital budget of approximately $73 million for the year ending December 31, 2012.
The capital budget will be primarily focused on oil or oil with liquids rich solution gas projects.



Recent Developments



On March 22, 2012 Advantage announced that,
due to the prevailing low natural gas pricing environment, production at Glacier will be maintained between 90 MMcf/d to 100 MMcf/d
and interim guidance was issued for the six months ending June 30, 2012.



Anticipated Changes
in the Business



As at the date hereof, we do not anticipate
that any material change in our business will occur during the balance of the 2012 financial year. See "General Development
of the Business – Recent Developments".



Significant Acquisitions



The Corporation did not complete any acquisitions
during the year ended December 31, 2011 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 and its subsidiaries are actively engaged
in the business of oil and gas exploitation, development, acquisition and production in the provinces of Alberta and Saskatchewan.



Advantage's exploitation and development
program is focused primarily at Glacier, Alberta where it is 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





13







increase reserves and
production. It is currently intended that AOG will finance acquisitions and investments through the Credit Facilities, the issuance
of additional Common Shares from treasury and the issuance of subordinated convertible debentures, maintaining prudent leverage.





14









Reorganizations



As at the date hereof, other than the Trust
Conversion and the Longview Transaction, 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 bankruptcy, receivership
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.



Human Resources



As at December 31, 2011, the Corporation
employed 125 full-time employees, 99 of which are located in the head office and 26 of which are located in the field. We also
retained 19 consultants in the head office.



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 consolidated reserves data by Sproule Associates Limited ("Sproule")
in Form 51-101F2 are attached as Schedules "A" and "B" to this annual information form, respectively, which
forms are incorporated herein by reference.



The consolidated statement of reserves
data and other oil and gas information set forth below (the "Statement") is dated December 31, 2011. The effective
date of the Statement is December 31, 2011 and the preparation date of the Statement is March 9, 2012.



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, 2011 contained
in a consolidated report of Sproule dated March 9, 2012 (the "Sproule Report"). The Sproule Report evaluated,
as at December 31, 2011, the oil, NGLs and natural gas reserves of AOG and its consolidated subsidiaries, including Longview. The
Reserves Data summarizes AOG's consolidated oil, NGLs and natural gas reserves and the net present values of future net revenue
for these reserves using forecast prices and costs. In accordance with NI 51-101, the Sproule Report includes 100% of the reserves
and future net revenue attributable to Longview's properties, without reduction to reflect the approximately 37% third-party minority
interests in Longview. Accordingly, the Reserves Data for the Corporation's consolidated reserves set forth below, which has been
derived from the Sproule Report, reflects 100% of Longview's reserves and future net revenue without reduction to reflect the Longview
Non-Controlling Interest. Approximately 5.4% of the assigned total gross proved plus probable reserves and 12.2% of the total gross
proved plus probable future net revenue discounted at 10% in the Sproule Report is attributable to the Longview Non-Controlling
Interest. See "Statement of Reserves Data and Other Oil & Gas Information - Ownership of Longview - Interests of Minority
Shareholders in Longview Reserves".



The Sproule Report has been prepared in
accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101 and the COGE Handbook.
Additional information not required by NI 51-101 has been presented to provide continuity and additional information which the
Corporation believes is important to readers of this annual information form. Sproule was engaged to provide evaluations of proved
and proved plus probable reserves and no attempt was made to evaluate possible reserves.



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



15







There are numerous uncertainties inherent
in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The
reserve and associated cash flow information set forth in this annual information form 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 natural 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 crude oil, NGL 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 consolidated reserves will vary from estimates thereof and such variations could
be material.



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, NGLs 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.



The information relating to the Corporation's
consolidated crude oil, NGL and natural gas reserves contains forward-looking statements relating to future net revenues, forecast
capital expenditures, future development plans and costs related thereto, forecast operating costs, anticipated production and
abandonment costs. See "Forward-Looking Statements", "Industry Conditions" and "Risk
Factors – Reserves Estimates".



In certain of the tables set forth below,
the columns may not add due to rounding.



16







SUMMARY OF OIL AND GAS RESERVES
as at December 31, 2011
FORECAST PRICES AND COSTS





|                           |  | RESERVES             |          
|-------------------------- |  | -------------------- | ---------
|                           |  | LIGHT AND MEDIUM OIL |          
|RESERVES CATEGORY(1)       |  | Gross (Mbbl)         |          
|                           |  |                      |          
|PROVED                     |  |                      |          
|Developed Producing        |  |                      | 9,966.1  
|Developed Non-Producing    |  |                      | 417.7    
|Undeveloped                |  |                      | 3,767.8  
|TOTAL PROVED               |  |                      | 14,151.70
|                           |  |                      |          
|PROBABLE                   |  |                      | 10,293.8 
|TOTAL PROVED PLUS PROBABLE |  |                      | 24,445.6 







|                           |  | RESERVES     |          
|-------------------------- |  | ------------ | ---------
|                           |  | NATURAL GAS  |          
|RESERVES CATEGORY(1)       |  | Gross (MMcf) |          
|                           |  |              |          
|PROVED                     |  |              |          
|Developed Producing        |  |              | 264,178  
|Developed Non-Producing    |  |              | 17,923   
|Undeveloped                |  |              | 562,421  
|TOTAL PROVED               |  |              | 844,523  
|                           |  |              |          
|PROBABLE                   |  |              | 473,197  
|TOTAL PROVED PLUS PROBABLE |  |              | 1,317,720



|                           |  | RESERVES             |          
|-------------------------- |  | -------------------- | ---------
|                           |  | TOTAL OIL EQUIVALENT |          
|RESERVES CATEGORY(1)       |  | Gross (Mboe)         |          
|                           |  |                      |          
|PROVED                     |  |                      |          
|Developed Producing        |  |                      | 59,058.0 
|Developed Non-Producing    |  |                      | 3,619.0  
|Undeveloped                |  |                      | 98,468.4 
|TOTAL PROVED               |  |                      | 161,145.5
|                           |  |                      |          
|PROBABLE                   |  |                      | 94,293.3 
|TOTAL PROVED PLUS PROBABLE |  |                      | 255,438.8



Note:



| | (1) | All reserves
                                                           presented herein represent the Corporation's and the Corporation's
                                                           consolidated subsidiaries interest. The Reserves Data reflects 100%
                                                           of Longview's reserves and future net revenue without reduction to
                                                           reflect the Longview Non-Controlling Interest. As at December 31, 2011,
                                                           the Corporation held an approximately 63% interest in Longview. For
                                                           further discussion see "Statement of Reserves Data and Other
                                                           Oil & Gas Information - Ownership of Longview - Interests of Minority
                                                           Shareholders in Longview Reserves".
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



17







SUMMARY OF NET PRESENT VALUES OF FUTURE
NET REVENUE

as at December 31, 2011

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(2) |  | 0%
    ($000's)                          |           |  | 5%
    ($000's)                           |  |           | 10%
    ($000's)                                                                                                                                                                                                                                                                                                                                              | 
|                                                                            |  |                                          |           |  |                                           |  |           |                                                                                                                                                                                                                                                                                                                                                               | 
|PROVED                                                                      |  |                                          |           |  |                                           |  |           |                                                                                                                                                                                                                                                                                                                                                               | 
|Developed
    Producing                                                     |  |                                          | 1,279,093 |  |                                           |  | 985,496   |                                                                                                                                                                                                                                                                                                                                                               | 
|Developed Non-Producing                                                     |  |                                          | 88,980    |  |                                           |  | 64,648    |                                                                                                                                                                                                                                                                                                                                                               | 
|Undeveloped                                                                 |  |                                          | 1,717,981 |  |                                           |  | 892,738   |                                                                                                                                                                                                                                                                                                                                                               | 
|TOTAL PROVED                                                                |  |                                          | 3,086,055 |  |                                           |  | 1,942,882 |                                                                                                                                                                                                                                                                                                                                                               | 
|                                                                            |  |                                          |           |  |                                           |  |           |                                                                                                                                                                                                                                                                                                                                                               | 
|PROBABLE                                                                    |  |                                          | 2,964,965 |  |                                           |  | 1,446,995 |                                                                                                                                                                                                                                                                                                                                                               | 
|                                                                            |  |                                          |           |  |                                           |  |           |                                                                                                                                                                                                                                                                                                                                                               | 
|TOTAL
    PROVED PLUS PROBABLE                                              |  |                                          | 6,051,020 |  |                                           |  | 3,389,877 |                                                                                                                                                                                                                                                                                                                                                               | 



Notes:



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

| | (2) | All reserves
                                                           presented herein represent the Corporation's and the Corporation's
                                                           consolidated subsidiaries interest. The Reserves Data reflects 100%
                                                           of Longview's reserves and future net revenue without reduction to
                                                           reflect the Longview Non-Controlling Interest. As at December 31, 2011,
                                                           the Corporation held an approximately 63% interest in Longview. For
                                                           further discussion see "Statement of Reserves Data and Other
                                                           Oil & Gas Information - Ownership of Longview - Interests of Minority
                                                           Shareholders in Longview Reserves".
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (3) | Values
                                                           are calculated by considering existing tax pools for Advantage in the
                                                           evaluation of Advantage's oil and gas properties, and take into account
                                                           current federal tax regulations. Values do not represent an estimate
                                                           of the value at the business entity level, which may be significantly
                                                           different. For information at the business entity level, please see
                                                           Advantage's Consolidated Financial Statements and Management's Discussion
                                                           and Analysis for the year ended December 31, 2011.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



TOTAL FUTURE NET REVENUE (UNDISCOUNTED)

as at December 31, 2011

FORECAST PRICES AND
COSTS

|RESERVES     
                                                                                      CATEGORY(1) |  | REVENUE
    ($000's) |            |  | ROYALTIES
    ($000's) |  |           | OPERATING
    COSTS ($000's) |  |  | DEVELOP-MENT
    COSTS ($000's) |  |  | ABANDONMENT
    AND RECLAMATION COSTS ($000's) |           |  | FUTURE
    NET REVENUE BEFORE INCOME TAXES ($000's) |  |         | FUTURE
    INCOME TAXES ($000's) |  |  | FUTURE
    NET REVENUE AFTER INCOME TAXES ($000's) | 
|--------------------------------------------------------------------------------------------------------------- |  | -------------------- | ---------- |  | ---------------------- |  | --------- | ---------------------------- |  |  | ------------------------------- |  |  | ---------------------------------------------- | --------- |  | --------------------------------------------------- |  | ------- | -------------------------------- |  |  | -------------------------------------------------- | 
|                                                                                                                |  |                      |            |  |                        |  |           |                              |  |  |                                 |  |  |                                                |           |  |                                                     |  |         |                                  |  |  |                                                    | 
|Proved Reserves                                                                                                 |  |                      | 7,081,309  |  |                        |  | 572,831   |                              |  |  | 2,070,081                       |  |  |                                                | 1,265,695 |  |                                                     |  | 86,647  |                                  |  |  | 3,086,054                                          | 
|                                                                                                                |  |                      |            |  |                        |  |           |                              |  |  |                                 |  |  |                                                |           |  |                                                     |  |         |                                  |  |  |                                                    | 
|Proved Plus Probable Reserves                                                                                   |  |                      | 12,237,504 |  |                        |  | 1,057,595 |                              |  |  | 3,346,645                       |  |  |                                                | 1,655,724 |  |                                                     |  | 126,520 |                                  |  |  | 6,051,020                                          | 



Note:



| | (1) | All reserves
                                                           presented herein represent the Corporation's and the Corporation's
                                                           consolidated subsidiaries interest. The Reserves Data reflects 100%
                                                           of Longview's reserves and future net revenue without reduction to
                                                           reflect the Longview Non-Controlling Interest. As at December 31, 2011,
                                                           the Corporation held an approximately 63% interest in Longview. For
                                                           further discussion see "Statement of Reserves Data and Other
                                                           Oil & Gas Information - Ownership of Longview - Interests of Minority
                                                           Shareholders in Longview Reserves".
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



18







FUTURE NET REVENUE
BY PRODUCTION GROUP
as at December 31, 2011
FORECAST PRICES AND COSTS





|RESERVES
        CATEGORY(1)  |  | 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)                     |  | 401,710                                                                                                          |  | 26.22                             
|                              |  | Heavy Oil (including solution gas and other by-products)                                      |  | 50,726                                                                                                           |  | 24.65                             
|                              |  | Natural Gas (including by-products but excluding solution gas and by-products from oil wells) |  | 873,519                                                                                                          |  | 6.76                              
|                              |  | Non-Conventional Oil and Gas Activities (Coalbed Methane)                                     |  | 19,168                                                                                                           |  | 7.21                              
|                              |  | TOTAL                                                                                         |  | 1,345,123                                                                                                        |  | 9.01                              
|                              |  |                                                                                               |  |                                                                                                                  |  |                                   
|Proved Plus
Probable Reserves |  | Light and Medium Crude Oil (including solution gas and other by-products)                     |  | 635,945                                                                                                          |  | 24.86                             
|                              |  | Heavy Oil (including solution gas and other by-products)                                      |  | 106,048                                                                                                          |  | 23.02                             
|                              |  | Natural Gas (including by-products but excluding solution gas and by-products from oil wells) |  | 1,444,238                                                                                                        |  | 7.16                              
|                              |  | Non-Conventional Oil and Gas Activities (Coalbed Methane)                                     |  | 25,848                                                                                                           |  | 7.20                              
|                              |  | TOTAL                                                                                         |  | 2,212,079                                                                                                        |  | 9.39                              





Note:



| | (1) | All reserves
                                                           presented herein represent the Corporation's and the Corporation's
                                                           consolidated subsidiaries interest. The Reserves Data reflects 100%
                                                           of Longview's reserves and future net revenue without reduction to
                                                           reflect the Longview Non-Controlling Interest. As at December 31, 2011,
                                                           the Corporation held an approximately 63% interest in Longview. For
                                                           further discussion see "Statement of Reserves Data and Other
                                                           Oil & Gas Information - Ownership of Longview - Interests of Minority
                                                           Shareholders in Longview Reserves".
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Pricing Assumptions



The following tables set forth the benchmark
reference prices, as at December 31, 2011, 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.



19







SUMMARY OF PRICING AND INFLATION RATE
ASSUMPTIONS(1)as at December 31, 2011
FORECAST PRICES AND COSTS





|Year        |  | WTI
                                                  Cushing
                                                  Oklahoma
                                                  ($US/bbl) |   | Light Sweet
                                                  Crude Oil
                                                  at
                                                  Edmonton
                                                  40oAPI
                                                  ($Cdn/bbl) |   | Medium
                                                  Crude Oil
                                                  29oAPI
                                                  ($Cdn/bbl) |   | Hardisty
                                                  Heavy 12oAPI
                                                  ($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)
|----------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | ------------------------------------------------------------------------------------------------------------------------------------ | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | -------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------------------------------------------
|2011        |  | 95.00                                                                                                                                                                                |   | 95.16                                                                                                                                                                                                                                                                                                         |   | 87.86                                                                                                                                                                                    |   | 69.10                                                                                                                                |   | 3.72                                                                                                                                                                                                                                                                                            |   | 104.12                                                                                                                                                                                                                                                                                                                                                            |   | 70.93                                                                                                                                                                                                                                                                                                     |   | 1.5                                                                                                                        |  | 1.012                                                                       
|Forecast(3) |  |                                                                                                                                                                                      |   |                                                                                                                                                                                                                                                                                                               |   |                                                                                                                                                                                          |   |                                                                                                                                      |   |                                                                                                                                                                                                                                                                                                 |   |                                                                                                                                                                                                                                                                                                                                                                   |   |                                                                                                                                                                                                                                                                                                           |   |                                                                                                                            |  |                                                                             
|2012        |  | 98.07                                                                                                                                                                                |   | 96.87                                                                                                                                                                                                                                                                                                         |   | 90.09                                                                                                                                                                                    |   | 74.59                                                                                                                                |   | 3.16                                                                                                                                                                                                                                                                                            |   | 103.57                                                                                                                                                                                                                                                                                                                                                            |   | 72.20                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2013        |  | 94.90                                                                                                                                                                                |   | 93.75                                                                                                                                                                                                                                                                                                         |   | 87.19                                                                                                                                                                                    |   | 72.19                                                                                                                                |   | 3.78                                                                                                                                                                                                                                                                                            |   | 100.23                                                                                                                                                                                                                                                                                                                                                            |   | 69.87                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2014        |  | 92.00                                                                                                                                                                                |   | 90.89                                                                                                                                                                                                                                                                                                         |   | 84.52                                                                                                                                                                                    |   | 69.98                                                                                                                                |   | 4.13                                                                                                                                                                                                                                                                                            |   | 97.17                                                                                                                                                                                                                                                                                                                                                             |   | 67.74                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2015        |  | 97.42                                                                                                                                                                                |   | 96.23                                                                                                                                                                                                                                                                                                         |   | 89.5                                                                                                                                                                                     |   | 74.10                                                                                                                                |   | 5.53                                                                                                                                                                                                                                                                                            |   | 102.89                                                                                                                                                                                                                                                                                                                                                            |   | 71.73                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2016        |  | 99.37                                                                                                                                                                                |   | 98.16                                                                                                                                                                                                                                                                                                         |   | 91.29                                                                                                                                                                                    |   | 75.58                                                                                                                                |   | 5.65                                                                                                                                                                                                                                                                                            |   | 104.94                                                                                                                                                                                                                                                                                                                                                            |   | 73.16                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2017        |  | 101.35                                                                                                                                                                               |   | 100.12                                                                                                                                                                                                                                                                                                        |   | 93.11                                                                                                                                                                                    |   | 77.09                                                                                                                                |   | 5.77                                                                                                                                                                                                                                                                                            |   | 107.04                                                                                                                                                                                                                                                                                                                                                            |   | 74.63                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2018        |  | 103.38                                                                                                                                                                               |   | 102.12                                                                                                                                                                                                                                                                                                        |   | 94.98                                                                                                                                                                                    |   | 78.64                                                                                                                                |   | 5.89                                                                                                                                                                                                                                                                                            |   | 109.18                                                                                                                                                                                                                                                                                                                                                            |   | 76.12                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2019        |  | 105.45                                                                                                                                                                               |   | 104.17                                                                                                                                                                                                                                                                                                        |   | 96.88                                                                                                                                                                                    |   | 80.21                                                                                                                                |   | 6.01                                                                                                                                                                                                                                                                                            |   | 111.37                                                                                                                                                                                                                                                                                                                                                            |   | 77.64                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2020        |  | 107.56                                                                                                                                                                               |   | 106.25                                                                                                                                                                                                                                                                                                        |   | 98.81                                                                                                                                                                                    |   | 81.81                                                                                                                                |   | 6.14                                                                                                                                                                                                                                                                                            |   | 113.59                                                                                                                                                                                                                                                                                                                                                            |   | 79.19                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|2021        |  | 109.71                                                                                                                                                                               |   | 108.38                                                                                                                                                                                                                                                                                                        |   | 100.79                                                                                                                                                                                   |   | 83.45                                                                                                                                |   | 6.27                                                                                                                                                                                                                                                                                            |   | 115.87                                                                                                                                                                                                                                                                                                                                                            |   | 80.78                                                                                                                                                                                                                                                                                                     |   | 2.0                                                                                                                        |  | 1.012                                                                       
|Thereafter  |  | +1.5                                                                                                                                                                                 | % | +1.5                                                                                                                                                                                                                                                                                                          | % | +1.5                                                                                                                                                                                     | % | +1.5                                                                                                                                 | % | +1.5                                                                                                                                                                                                                                                                                            | % | +1.5                                                                                                                                                                                                                                                                                                                                                              | % | +1.5                                                                                                                                                                                                                                                                                                      | % |                                                                                                                            |  |                                                                             







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, 2011, were $4.17/Mcf for natural gas, $85.38/bbl for crude oil, and $65.64/bbl
for NGLs.



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, 2011 against
such reserves as at December 31, 2010 based on forecast prices and cost assumptions.



20







RECONCILIATION OF
GROSS RESERVES(1)BY PRODUCT TYPE

FORECAST PRICES AND COSTS



|                    |  | Light And Medium Oil |          |   | Heavy Oil           |  |          | Natural Gas Liquids                     | 
|------------------- |  | -------------------- | -------- | - | ------------------- |  | -------- | --------------------------------------- | 
|FACTORS             |  | Proved
    (Mbbl)    |          |   | Probable
    (Mbbl) |  |          | Proved
    Plus
    Probable
    (Mbbl) | 
|                    |  |                      |          |   |                     |  |          |                                         | 
|December 31, 2010   |  |                      | 13,862.1 |   |                     |  | 10,182.3 |                                         | 
|                    |  |                      |          |   |                     |  |          |                                         | 
|Extensions          |  |                      | 357.0    |   |                     |  | 321.4    |                                         | 
|Improved Recovery   |  |                      | 1,654.2  |   |                     |  | 1,606.8  |                                         | 
|Infill Drilling     |  |                      | -        |   |                     |  | -        |                                         | 
|Technical Revisions |  |                      | (261.7   | ) |                     |  | (1,832.4 | )                                       | 
|Discoveries         |  |                      | -        |   |                     |  | -        |                                         | 
|Acquisitions        |  |                      | -        |   |                     |  | -        |                                         | 
|Dispositions        |  |                      | -        |   |                     |  | -        |                                         | 
|Economic Factors    |  |                      | 7.9      |   |                     |  | 15.7     |                                         | 
|Production          |  |                      | (1,467.8 | ) |                     |  | -        |                                         | 
|                    |  |                      |          |   |                     |  |          |                                         | 
|December 31, 2011   |  |                      | 14,151.7 |   |                     |  | 10,293.8 |                                         | 



|                    |  | Associated and Non-Associated Gas |         |   | Natural Gas - Solution | 
|------------------- |  | --------------------------------- | ------- | - | ---------------------- | 
|FACTORS             |  | Proved
    (MMcf)                 |         |   | Probable
    (MMcf)    | 
|                    |  |                                   |         |   |                        | 
|December 31, 2010   |  |                                   | 696,919 |   |                        | 
|                    |  |                                   |         |   |                        | 
|Extensions          |  |                                   | 11,936  |   |                        | 
|Improved Recovery   |  |                                   | 15,819  |   |                        | 
|Infill Drilling     |  |                                   | -       |   |                        | 
|Technical Revisions |  |                                   | 147,799 |   |                        | 
|Discoveries         |  |                                   | -       |   |                        | 
|Acquisitions        |  |                                   | 19      |   |                        | 
|Dispositions        |  |                                   | -       |   |                        | 
|Economic Factors    |  |                                   | (19,583 | ) |                        | 
|Production          |  |                                   | (42,720 | ) |                        | 
|                    |  |                                   |         |   |                        | 
|December 31, 2011   |  |                                   | 810,189 |   |                        | 



21







|                    |  | Coalbed Methane   |        |   | Oil Equivalent     | 
|------------------- |  | ----------------- | ------ | - | ------------------ | 
|FACTORS             |  | WI  Proved (MMcf) |        |   | WI Probable (MMcf) | 
|                    |  |                   |        |   |                    | 
|December 31, 2010   |  |                   | 20,136 |   |                    | 
|                    |  |                   |        |   |                    | 
|Extensions          |  |                   | 266    |   |                    | 
|Improved Recovery   |  |                   | -      |   |                    | 
|Infill Drilling     |  |                   | -      |   |                    | 
|Technical Revisions |  |                   | (426   | ) |                    | 
|Discoveries         |  |                   | -      |   |                    | 
|Acquisitions        |  |                   | -      |   |                    | 
|Dispositions        |  |                   | -      |   |                    | 
|Economic Factors    |  |                   | (360   | ) |                    | 
|Production          |  |                   | (2,038 | ) |                    | 
|                    |  |                   |        |   |                    | 
|December 31, 2011   |  |                   | 17,578 |   |                    | 



Note:



| | (1) | All reserves
                                                           presented herein represent the Corporation's and the Corporation's
                                                           consolidated subsidiaries interest. The Reserves Data reflects 100%
                                                           of Longview's reserves and future net revenue without reduction to
                                                           reflect the Longview Non-Controlling Interest. As at December 31, 2011,
                                                           the Corporation held an approximately 63% interest in Longview. For
                                                           further discussion see "Statement of Reserves Data and Other
                                                           Oil & Gas Information - Ownership of Longview - Interests of Minority
                                                           Shareholders in Longview Reserves".
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Ownership of Longview
- Interests of Minority Shareholders in Longview Reserves



On April 14, 2011, Longview completed the
Longview Offering and the Longview Transaction. The purchase price for the Longview Transaction was approximately $554.1 million,
prior to closing adjustments pursuant to the terms of the purchase and sale agreement for the Acquired Assets. The purchase price
for the Acquired Assets was comprised of the net proceeds of the Longview Offering (including the net proceeds from the exercise
of the over-allotment option) in the amount of $162.1 million, the issuance of 29,450,000 common shares to the Corporation and
approximately $83.4 million drawn from Longview's credit facilities. As a result of the Longview Offering and the Longview Transaction,
as at December 31, 2011, the Corporation held an approximately 63% equity interest in Longview.



As at December 31, 2011, the Sproule Report
estimated Longview's share of proved, probable and proved plus probable reserves, representing 100% of the working interest of
Longview, which were consolidated in the Corporation's reserves. Third-party minority shareholders indirectly owned approximately
37% of these reserves at December 31, 2011. The tables below represent a summary of reserves indirectly owned by Longview's third-party
minority shareholders and a summary of the net present value (before tax) of such reserves, all as at December 31, 2011. All reserves
stated herein are based on forecast prices and costs.



22







SUMMARY OF OIL AND GAS RESERVES
as at December 31, 2011
FORECAST PRICES AND COSTS



|                           |  | RESERVES             |        
|-------------------------- |  | -------------------- | -------
|                           |  | LIGHT AND MEDIUM OIL |        
|RESERVES CATEGORY          |  | Gross (Mbbl)         |        
|                           |  |                      |        
|PROVED                     |  |                      |        
|Developed Producing        |  |                      | 3,178.8
|Developed Non-Producing    |  |                      | 140.4  
|Undeveloped                |  |                      | 1,376.3
|TOTAL PROVED               |  |                      | 4,695.5
|                           |  |                      |        
|PROBABLE                   |  |                      | 3,487.0
|TOTAL PROVED PLUS PROBABLE |  |                      | 8,182.5



|                           |  | RESERVES     |       
|-------------------------- |  | ------------ | ------
|                           |  | NATURAL GAS  |       
|RESERVES CATEGORY          |  | Gross (MMcf) |       
|                           |  |              |       
|PROVED                     |  |              |       
|Developed Producing        |  |              | 7,307 
|Developed Non-Producing    |  |              | 246   
|Undeveloped                |  |              | 2,341 
|TOTAL PROVED               |  |              | 9,895 
|                           |  |              |       
|PROBABLE                   |  |              | 7,746 
|TOTAL PROVED PLUS PROBABLE |  |              | 17,640



|                           |  | RESERVES             |         
|-------------------------- |  | -------------------- | --------
|                           |  | TOTAL OIL EQUIVALENT |         
|RESERVES CATEGORY          |  | Gross (Mboe)         |         
|                           |  |                      |         
|PROVED                     |  |                      |         
|Developed Producing        |  |                      | 5,388.9 
|Developed Non-Producing    |  |                      | 257.9   
|Undeveloped                |  |                      | 2,013.4 
|TOTAL PROVED               |  |                      | 7,660.2 
|                           |  |                      |         
|PROBABLE                   |  |                      | 6,244.5 
|TOTAL PROVED PLUS PROBABLE |  |                      | 13,904.7







23







SUMMARY OF NET PRESENT VALUES OF FUTURE
NET REVENUE

as at December 31, 2011

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)                                                                                                                                                                                                                                                                                                                                              | 
|                           |  |                                          |         |  |                                           |  |         |                                                                                                                                                                                                                                                                                                                                                               | 
|PROVED                     |  |                                          |         |  |                                           |  |         |                                                                                                                                                                                                                                                                                                                                                               | 
|Developed
    Producing    |  |                                          | 200,422 |  |                                           |  | 149,772 |                                                                                                                                                                                                                                                                                                                                                               | 
|Developed Non-Producing    |  |                                          | 9,015   |  |                                           |  | 6,930   |                                                                                                                                                                                                                                                                                                                                                               | 
|Undeveloped                |  |                                          | 63,675  |  |                                           |  | 45,231  |                                                                                                                                                                                                                                                                                                                                                               | 
|TOTAL PROVED               |  |                                          | 273,112 |  |                                           |  | 201,932 |                                                                                                                                                                                                                                                                                                                                                               | 
|                           |  |                                          |         |  |                                           |  |         |                                                                                                                                                                                                                                                                                                                                                               | 
|PROBABLE                   |  |                                          | 272,679 |  |                                           |  | 161,502 |                                                                                                                                                                                                                                                                                                                                                               | 
|                           |  |                                          |         |  |                                           |  |         |                                                                                                                                                                                                                                                                                                                                                               | 
|TOTAL PROVED PLUS PROBABLE |  |                                          | 545,791 |  |                                           |  | 363,434 |                                                                                                                                                                                                                                                                                                                                                               | 



Note:



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



Additional Information
Relating to Reserves Data



Unless otherwise indicated, the additional
information contained in this section pertains to Advantage and Longview on a consolidated basis and references to Advantage include
Longview (without reduction to reflect the Longview Non-Controlling Interest). See "Statement of Reserves Data and Other
Oil & Gas Information - Ownership of Longview - Interests of Minority Shareholders in Longview Reserves".



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.



24







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 | 
|              |  |                             |       |  |                        |  |       |                    |  |  |                        | 
|Prior thereto |  |                             | 312   |  |                        |  | 3,730 |                    |  |  | -                      | 
|2009          |  |                             | 44    |  |                        |  | 2,615 |                    |  |  | -                      | 
|2010          |  |                             | 210   |  |                        |  | 2,795 |                    |  |  | -                      | 
|2011          |  |                             | 1,391 |  |                        |  | 3,768 |                    |  |  | 311                    | 



Sproule has assigned 98.5 MMboe of gross
proved undeveloped reserves in the Sproule Report under forecast prices and costs, together with $1,256.5 million of associated
undiscounted future capital expenditures. Proved undeveloped capital spending in the first two forecast years of the Sproule Report
accounts for $319.2 million, or 25.4%, of the total forecast. These figures increase to $916.4 million or 72.9%, 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 | 
|              |  |                             |       |  |                        |  |       |                    |  |  |                        | 
|Prior thereto |  |                             | 243   |  |                        |  | 7,382 |                    |  |  | -                      | 
|2009          |  |                             | 23    |  |                        |  | 8,221 |                    |  |  | -                      | 
|2010          |  |                             | 656   |  |                        |  | 5,069 |                    |  |  | -                      | 
|2011          |  |                             | 1,636 |  |                        |  | 6,212 |                    |  |  | 125                    | 



Sproule has assigned 69.2 MMboe of gross
probable undeveloped reserves and has allocated future development capital of $385.7 million to all gross probable undeveloped
reserves with $221.7 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.



25







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$)     |        
|                                  |  |                           |        
|2012                              |  |                           | 123.0  
|2013                              |  |                           | 202.7  
|2014                              |  |                           | 265.4  
|2015                              |  |                           | 230.9  
|2016                              |  |                           | 102.2  
|Total: Undiscounted for all years |  |                           | 1,265.7



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



AOG's 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 the Corporation's properties concentrated in Alberta and Saskatchewan. These properties produce from a variety
of various aged geological formations and reservoirs. The Corporation operates over 85% of its properties, which allows the Corporation
to control the nature and timing of the capital investments necessary to maximize the potential in developing these assets.



AOG's properties can be divided on the
broad basis of commodity and of production type. Light or medium gravity oil accounts for 22% of Total Current Production and 10%
of gross proved reserves, and natural gas accounts for 78% of Total Current Production and 86% of gross proved reserves.



The following property descriptions are
as of March 23, 2012 unless otherwise noted and reserves quoted are as reported in the Sproule Report.



Property
Descriptions



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 Glacier property consists of 82.5 gross (77.75 net)
sections of land with Montney interests.



26







In 2011, Advantage drilled and completed
24 gross (23.5 net) horizontal wells in the Montney and Lower Doig formations on the Glacier property. Subsequent to year end and
prior to spring breakup Advantage will have drilled an additional 8 gross (8 net) horizontal Montney/Doig wells. Since the spud
of the first horizontal well on July 26, 2008, Advantage has drilled 98 gross (89.9 net) horizontal wells at the Glacier property.
One vertical well, drilled in 2010, into the underlying Belloy Formation was completed for use as an acid gas disposal well and
one existing vertical well proximal to the 05-02 main compression facility was recompleted as a service well for water disposal
purposes.



Although Advantage has utilised a number
of completion techniques, to date, the majority of the wells have been completed using an abrasa-jet and sand plug completion technique
in wellbores which are cased to total depth. On average 12 fracs per horizontal well have been placed in the wells to date with
as many as 18 in the longer horizontal wells. The fracs are water and CO2 fracs carrying on average 75 tonnes of sand per frac.
All of the wells drilled by Advantage have been completed with the exception of the last portion of the Phase IV wells which will
be completed following spring breakup 2012. Test rates per well in the Doig (Upper Montney) have been improving from 3.7 MMcf/d
for the 8 wells in the Phase I (2008-2009) program through 7.3 MMcf/d for the 25 wells in the Phase II (2009-2010) program to 8.0
MMcf/d for the 24 wells in the Phase III program and the initial 10 wells in Phase IV. These rates are average wellhead rates all
normalized to 435 psi. Current Production of 100 MMcf/d or 16,667 boe/d represents over 50% of the Corporation's Total Current
Production.



In the second quarter of 2011 Advantage
completed the Phase III expansion of capacity at its 5-02 gas compression facility to 100 MMcf/d from 50 MMcf/d. With the completion
of the acid gas disposal well and installation of acid gas compression at the 5-02 facility, Advantage has discontinued flaring
of acid gas. All gas is sold through Advantage’s 22 kilometer sales pipeline into the TransCanada pipeline system. Advantage
is currently concluding Phase IV expansion which will increase available capacity to 135 MMcf/d. Operating costs have dropped from
a high of $5.80/mcf at the start of the project to just under $0.30/mcf at year end 2011. 2011 exit rate sales production was 99.3
MMcf/d from the 5-02 facility.



The Sproule Report assigns 701 bcf of gross
proved natural gas reserves and 401 bcf of gross probable natural gas reserves to this property.



Southern Alberta



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. 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. Current Production from this field is 1,100 boe/d.



The Sproule Report assigns 24.3 bcf of
gross proved natural gas reserves and 80.7 Mbbls of gross proved crude oil and NGL reserves to Lookout Butte. In addition, 13.0
bcf of gross probable natural gas reserves and 87.4 Mbbls of gross probable crude oil and NGL reserves have been assigned to this
property.



Medicine Hat, Alberta



The Medicine Hat property lies 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 Current Production of 5.1 MMcf/d 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. These
sands occur at approximately 500 metres



27







of depth and typical of shallow gas, these
sands 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. This property
has been downspaced and co-mingled to allow for multiple gas wells per section from multiple producing horizons per well bore.



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.



The Sproule Report assigns 17.0 bcf of
gross proved natural gas reserves to the Medicine Hat property. In addition, 14.0 bcf of gross probable natural gas reserves have
been assigned to this property.



West Central Alberta



Willesden Green (Open
Lake), Alberta



The Willesden Green property is located
approximately 35 kilometres north of the Town of Rocky Mountain House. There are two principle areas in this property, being 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. The Rock Creek is a mixed lithology reservoir in which liquids rich gas is trapped stratigraphically in individual
lenses of sand. 3D seismic is used to explore for this porosity and a number of future targets have been identified. The Ostracode
is developed in a linear sand bar and produces 39oAPI oil. This pool is being evaluated for potential water injection
pressure maintenance. Additional drilling targeting both the Second White Specks and Glauconite is being evaluated.



The Sproule Report assigns 3.4 bcf of gross
proved natural gas reserves and 505 Mbbls of gross proved crude oil and NGL reserves to the Willesden Green property. In addition,
1.6 bcf of gross probable natural gas reserves and 225 Mbbls of gross probable crude oil and NGL reserves have been assigned to
this property.



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 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 the southern part of this area Advantage
has acquired 6.75 sections (100% net) for Cretaceous Belly River and Notikewin Formation natural gas. 3D seismic has been acquired
and locations are being evaluated as vertical drill targets in the Belly River. The acreage is being reviewed for the potential
to drill a horizontal multi-stage frac well in the Notikewin Formation.



The Sproule Report assigns 5.1 bcf of gross
proved natural gas reserves and 445 Mbbls of gross proved crude oil and NGL reserves to the Brazeau River area. In addition, 1.9
bcf of gross probable natural gas reserves and 210 Mbbls of gross probable crude oil and NGL reserves have been assigned to this
area.



Northeast and East Central Alberta



Chigwell and Oberlin
(Nevis), Alberta



Advantage has two coal bed methane ("CBM")
fields in the Chigwell and Oberlin (Nevis) areas of Alberta which produce natural gas from Horseshoe Canyon Formation coal beds
and adjacent associated sandstones. These fields lie approximately 60 kilometers northeast and east of the City of Red Deer Alberta
respectively. The wells on these fields are completed on a commingled basis in multiple layers of individual coals which range
in thickness from 1 to



28







3 meters along with associated and adjacent
gas charged sandstones. The fields are for the most part developed on the basis of 4 vertical wells per section. These wells are
shallow with completed intervals ranging between 150 and 550 meters in depth. The wells are connected with low pressure gathering
system to central compression facilities which allows the fields to be drawn down to very low operating pressure of between 35
and 70 kpa. Advantage operates the Oberlin property with 31 gross and 24.5 net sections. The Chigwell property is a combination
of operated and nonoperated with a wide range of working interests across 27.5 gross (11.25 net) sections. Current Production from
these fields is 1,689 boe/d.



The Sproule Report assigns 20.1 bcf of
gross proved natural gas reserves to these CBM properties. In addition, 7.7 bcf of gross probable natural gas reserves have been
assigned to this area.



Northeastern Shallow
Gas



Advantage has shallow gas properties located
in the eastern side of Alberta, including the Wainwright property, which is located north of the town of Wainwright, and the Tweedie
and Cache properties which are located west of the town of Bonnyville. These properties produce from multiple horizons generally
all at depths of 750 meters or less. The principle producing intervals are Cretaceous Mannville Formation sands, Viking Formation
sands and Second White Specks sands and silts. Current Production from these fields is 726 boe/d.



The Sproule Report assigns 10.5 bcf of
gross proved natural gas reserves and 6.2 Mbbls of gross proved crude oil and NGL reserves to these fields. In addition, 2.8 bcf
of gross probable natural gas reserves and 4.8 Mbbls of gross probable crude oil and NGL reserves have been assigned.



Longview Oil
and Gas Major Properties



West Central
Alberta



This area consists of a number of individual
properties and lands located in the West Central area of Alberta. Current Production from this area is approximately 4,320 boe/d
and is comprised mainly of low decline, high netback light oil with average API gravity of 34o. Production is derived
from numerous large oil pools where opportunities exist to increase production and reserves through low risk development drilling
and the application of enhanced oil recovery techniques. Drilling opportunities also exist for step-out and exploration drilling
on undeveloped lands.



Nevis, Alberta



Nevis is an operated property consisting
of approximately 44 gross (34.6 net) sections of land which are situated 60 kilometres east of Red Deer, Alberta. Nevis is Longview's
largest producing property with Current Production of approximately 2,219 boe/d. The property is divided into two main pools each
trapped structurally and stratigraphically with an associated updip gas cap to each pool. Crude oil quality averages 39o
API which also produces associated natural gas and NGLs. Two operated facilities are utilized for processing the oil and natural
gas production which is gathered from the wells through pipelines to the respective central facilities. Clean oil is trucked from
the facilities and water is disposed of back into the reservoir. Associated gas is transported through pipelines to third party
compression and sales.



The main producing zone is the Devonian
age Wabamun Formation, which occur at 1,600 metres of depth. This reservoir is a high porosity, low permeability carbonate which
results in relatively low production inflow from vertical wells. As a result, horizontal drilling technology is used to access
additional inflow from the low permeability rock with current development drilling downspacing to six wells per section. Production
has increased and the ultimate recovery has been enhanced through increased well density as a result of receiving regulatory approval
to downspace sections of this property. Horizontal well laterals are on average 1,200 metres in length. Wells are completed on
an open hole basis and only require an acid wash as stimulation to clean the wellbore before being placed on production.



29







In the eastern pool, a pilot waterflood
scheme has been started to evaluate the potential for enhanced recovery of these pools in order to access the large oil-in place
which is not being drained through primary development. Longview is also studying the implementation of CO2flood applications to enhance production recovery and reserves at Nevis.



The Sproule Report assigns 6.8 bcf of gross
proved natural gas reserves and 3,085.9 Mbbls of gross proved crude oil and NGL reserves to this property. In addition, 2.4 bcf
of gross probable natural gas reserves and 1,431.3 Mbbls of gross probable crude oil and NGL reserves have been assigned to this
property.



Westerose,
Alberta



The Westerose property is located approximately
60 kilometres southwest of Edmonton, Alberta and consists mainly of the Westerose Banff "C" Unit, Chip Lake, interests
in several Pembina Cardium oil units and other liquids rich natural gas production in areas surrounding the Westerose Banff "C"
Unit. Current Production at Westerose area is approximately 634boe/d.



Westerose
Banff "C" Unit



The Westerose Banff "C" Unit
(52% unit interest) produces 24o API gravity crude oil which is trapped stratigraphically along the erosional subcrop
edge of the Mississippian Banff Formation. The reservoir in the Banff Formation is a dolomitized carbonate which occurs at a depth
of 1,800 metres. The Westerose Banff "C" Unit is currently developed on 40 acre spacing with four water injection wells
and Current Production is approximately 170 boe/d. This reservoir is currently under an active waterflood pressure maintenance
scheme which commenced in 2003 and production is responding positively to injection. Additional producing and injection wells are
being evaluated and will be added as required to increase oil recovery.



Chip Lake,
Alberta



The Chip Lake property is located 125 kilometres
west of Edmonton, Alberta. Longview holds a 100% working interest in seven sections of land with Current Production of approximately
212 boe/dfrom the Rock Creek Formation. The field consists of 12 producing vertical oil wells, four water injection wells
and a central oil processing battery and water disposal facility. Associated natural gas is compressed and sold through third party
facilities where nautral gas liquids (35 bbls/MMcf) are extracted and sold. Clean oil is trucked for sale.



The Rock Creek Formation is a conventional
sandstone reservoir in which 40o API oil is trapped against an updip shale plug channel that truncates the reservoir
which occurs at a depth of 1,850 metres. Pay thickness is in excess of eight metres along the axis of the reservoir and it is there
and along the updip margin that infill drilling, potentially with a combination of vertical and horizontal wells, will be targeted
after water injection has re-pressured this area of the pool. The water injection scheme is currently being optimized and regulatory
and spacing work is proceeding to allow for additional wells or conversion of existing wells into water injectors.



Cardium
properties, West Central Alberta



The Cardium Formation properties lie in
the west central Alberta basin primarily between Townships 38 and 48, Ranges 2 to 11W5. These properties consist of a variety of
lands with working interests ranging between 8% and 100% with an average working interest of 32%. Most of the properties are non-operated
with the exception of the Pembina Rose Creek Cardium Unit, which is an operated Cardium producing property consisting of 1,600
acres of 100% unit interest. In total, Longview has 34,155 gross (10,907 net) acres of Cardium rights in this area with Current
Production of approximately 155 boe/d. This acreage is exclusive of a 1.5% working interest in the North Pembina Cardium Unit Number
1.



30







Pembina
Rose Creek Cardium Unit



Longview has a 100% unit interest in and
operates this 1,600 acre Cardium Formation unit which has Current Production of approximately 100 boe/d. The Cardium Formation
in this unit consists of up to seven metres of net pay located within the southern boundary of the main Pembina field producing
36° API oil. The updip half of the property is overlain by one metre of highly permeable conglomerate. The unit has 15
active wells of which four are injecting water as pressure maintenance into the property. This property represents an opportunity
for the application of multi-stage frac horizontal drilling in the Cardium trend.



The Sproule Report assigned 2.3 bcf of
gross proved natural gas reserves and 2,051.8 Mbbls of gross proved crude oil and NGL reserves to the Westerose property. In addition,
1.1 bcf of gross probable natural gas reserves and 1,778.4 Mbbls of gross probable crude oil and NGL reserves have been assigned
to this property.



Sunset, Alberta



This property consists of three pools all
of which are producing from Triassic age Montney Formation reservoirs and lies approximately 100 kilometres east of the City of
Grande Prairie. Current Production from the three main pools in the Sunset area is approximately 655 boe/d.



Sunset "A"



Current Production of 406 boe/d consists
of 29o API crude oil from the Montney Formation occurring at 1,450 metres of depth. In this area, the Montney is a conventional
tight fine grained sandstone reservoir in which crude oil has been trapped stratigraphically against cap rock overlying the updip
subcrop unit of the reservoir. The reservoir has an underlying water leg which provides partial pressure support. Longview has
a 70% working interest, and operates the Sunset Triassic "A" Unit. The field is currently developed with vertical wells
drilled mainly on 40 acre spacing from central production pads. There is a 40 year production history with stable well performance
and low decline. Infill drilling to 40 acre spacing in the pool commenced in 2005 and since that time 24 new oil wells and four
additional injector wells have been added to the pool. In the center of the field, drilling has been successfully downspaced to
20 acre spacing units. A waterflood scheme was initiated in 2006 and expansion of the water injection system is ongoing. Once completed
and re-pressurization of the reservoir has progressed sufficiently, further infill drilling will proceed to capture additional
oil reserves.



Sunset "B"



Current Production from this Montney reservoir
is approximately 219 boe/d of liquids rich natural gas. Longview has a 100% interest in this
pool and owns 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 processed through this facility.



Valleyview



This Montney gas pool has Current Production
of 127 boe/d and is connected to the Sunset "B" gas processing plant by a 12 kilometre pipeline with Longview holding
a 93% average working interest in the pool.



The Sproule Report assigns 5.6 bcf of gross
proved natural gas reserves and 1,012.1 Mbbls of gross proved crude oil and NGL reserves to Sunset/Valleyview. In addition, 10.5
bcf of gross probable natural gas reserves and 1,605.4 Mbbls of gross probable crude oil and NGL reserves have been assigned to
these properties.



31







Duvernay
and Nordegg Resource Play



The properties of Longview include a 100%
interest in 78,750 gross (123 net sections) acres of exploratory rights in and along the Sunset corridor, which are prospective
for development in the Upper Devonian Duvernay Formation shalesas well as 15,719 net acres
(61.4 net sections) for the Jurassic Nordegg Formation. A stratigraphic test well was drilled at the end of 2011 which cored both
the Nordegg and Duvernay intervals. These cores are being analysed to further assess the potential of these lands for additional
exploration. Longview believes that both the Duvernay and Nordegg lands are located within the oil generating window in this area
and Longview will continue to review and analyze this target to determine future exploratory activity. Longview's ownership of
oil and natural gas facilities in this area is available to provide immediate processing capacity should development proceed.



Skaro/Alexis,
Alberta



Skaro, Alberta



The Skaro property is located 50 kilometres
northeast of Edmonton, Alberta. This is an operated property in which Longview has a 100% working interest. Current Production
at Skaro is approximately 136 boe/d. Oil is gathered and processed at 100% operated facilities where clean oil is then trucked
out for sale. Production in this area is 17o API gravity oil which occurs at shallow depths of 900 metres. Oil is trapped
in pools within a large Cretaceous age, Ellerslie Formation, channel/valley trend in which numerous multi-well oil pools have accumulated.
The pools are separated by shale filled channels which provide the hydrocarbon trap and separation of pools. On the Skaro lands
there are two pools, the Basal Quartz (Ellerslie) "C" Pool which is currently developed with five horizontal wells and
the Basal Quartz (Ellerslie) "G" Pool which has one producing horizontal well that was tied-in by pipeline during 2010.



The Sproule Report assigns to the Skaro
area 255.0 Mbbls of gross proved crude oil and NGL reserves to this property. In addition, 106.4 Mbbls of gross probable crude
oil and NGL reserves have been assigned to this property.



Alexis,
Alberta



The Alexis property is located 50 kilometres
northwest of Edmonton, Alberta. Longview holds a 13.966% non-operated working interest in the Alexis Banff "A" pool unit
which produces slightly sour 22° API crude oil and natural gas from a siliclastic carbonate member within the Mississippian
Banff Formation. There are 37 wells within the unit which is developed at 1,400 metres of depth with both vertical and horizontal
producing wells and injection wells. Current Production at Alexis is 120 boe/d.



The Sproule Report assigns 1.1 bcf of gross
proved natural gas reserves and 362.5 Mbbls of gross proved crude oil and NGL reserves to the Alexis property. In addition, 0.7
bcf of gross probable natural gas reserves and 168.5 Mbbls of gross probable crude oil and NGL reserves have been assigned to this
property.



Saskatchewan



Southeast
Saskatchewan



This area consists of a number of individual
properties and lands located within the Williston Sedimentary Basin in the southeast quadrant of Saskatchewan. Existing production
at the major properties comes principally from the Ordovician Red River Formation, Devonian Winnipegosis Formation as well as from
the Mississippian Midale, Frobisher and Bakken Formations. Current Production from this area is approximately 1,927 boe/d and is
comprised mainly of low decline, high netback, light oil with an average API gravity of 30°.



32







Weyburn
and Steelman Area – Midale Formation Development



The Midale Formation is a Mississippian
carbonate reservoir and contains one of Canada's largest light oil pools with API gravities ranging from 32° to 40°. The
Midale Formation is comprised of two distinct fractured low permeability reservoirs which are the tight, high-porosity Marly zone
that overlies the low-porosity Vuggy zone. The latter zone has higher permeability, and is more extensively fractured vertically
than the Marly zone.



Longview has 68,017 gross undeveloped (55,628
net) acres of lands that are prospective for drilling in the Midale Formation and represents the largest opportunity base in the
Southeast Saskatchewan area. Longview holds direct ownership of the mineral title in approximately 63% of the net acres.



The assets in this area also include 69,770
gross (55,933 net) acres of land that are prospective in the Bakken and Three Forks Sanish Formations. Longview holds direct ownership
of the mineral title in approximately 64% of the net acres. There has been significant industry activity surrounding these lands
targeting light oil resource plays. Drilling potential will be evaluated in these formations as information from surrounding industry
activity comes into the public domain.



Wapella
Property



The Wapella property is located 200 kilometres
east of Regina, Saskatchewan with Current Production of approximately 724 boe/d of 25o API gravity oil with an average working
interest of 90%. Production is derived from the Cretaceous and Jurassic-age Shaunavon and Gravelbourg sandstone reservoirs located
at a depth of 800 metres. Additional infill drilling and stepouts have been identified in and around the existing production from
reservoirs.



Longview also has 18,793 gross (18,253
net) acres of undeveloped lands that are prospective in the Bakken Formation. Longview holds direct ownership of the mineral title
in approximately 82% of the net acres. Significant exploration potential exists on the undeveloped land base and recent activity
for Bakken target, to the east of Wapella, suggest that favourable geological potential in this horizon could extend westward onto
lands to be acquired by Longview.



The Sproule Report assigns 2,568.1 Mbbls
of gross proved crude oil and NGL reserves in Wapella. In addition, 1557.0 Mbbls of gross probable crude oil and NGL reserves have
been assigned to this area.



Lloydminster,
Saskatchewan Area



These properties lie east of the Saskatchewan/Alberta
border within the Lloydminster heavy oil producing area. Current Production from these properties of approximately 528 boe/d is
derived primarily from the Cretaceous Sparky and Waseca Formations and also from the Rex, Cummings and Dina Formations. Crude oil
gravities in these properties average 20o API and are all being produced conventionally at this time.



Eyehill,
Saskatchewan



The Eyehill property (100% working interest)
consists of 24 oil wells with Current Production of approximately 293 boe/d producing from a 20o API Sparky Formation sand
reservoir in which oil is trapped updip and laterally against shale filled channels. The Sparky oil pool is under waterflood pressure
maintenance from six injection wells and is showing positive production response to this injection.



Lashburn,
Saskatchewan



At Lashburn, in which Longview holds a
60% working interest, two thick Waseca channels are present as identified in vertical wells and on 3D seismic with Current Production
of approximately 235 boe/d of 21o API oil. Similar Waseca channels are being developed immediately south of the property by
a major oil company with SAGD (steam



33







assisted gravity drainage) technology which
could be utilized at the Lashburn property. As an alternative, this property may be developed through a combination of vertical
and horizontal drilling to increase production and enhance reserves.



The Sproule Report assigns 1,442.9 Mbbls
of gross proved crude oil and NGL reserves to the properties in the Lloydminster area. In addition, 2,719.7 Mbbls of gross probable
crude oil and NGL reserves have been assigned to this area.



Oil and Gas
Wells



The following table sets forth the number
and status of wells as at December 31, 2011 in which we have a working interest.



|             |  | Oil Wells |     |  | Natural Gas Wells | 
|------------ |  | --------- | --- |  | ----------------- | 
|             |  | Producing |     |  | Non-Producing     | 
|             |  | Gross     |     |  | Net               | 
|             |  |           |     |  |                   | 
|Alberta      |  |           | 612 |  |                   | 
|Saskatchewan |  |           | 268 |  |                   | 
|             |  |           |     |  |                   | 
|Total(1)(2)  |  |           | 880 |  |                   | 



Note:



| | (1) | Includes
                                                           wells of Longview (without reduction to reflect the Longview Non-Controlling
                                                           Interest).
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Properties
with no Attributed Reserves



The following table sets out our unproved
properties as at December 31, 2011.



|             |  | Gross Acres |         |  | Net Acres | 
|------------ |  | ----------- | ------- |  | --------- | 
|             |  |             |         |  |           | 
|Alberta      |  |             | 374,193 |  |           | 
|Saskatchewan |  |             | 119,178 |  |           | 
|Total(1)     |  |             | 493,371 |  |           | 



Note:



| | (1) | Includes
                                                           developed and undeveloped land holdings of Longview (without reduction
                                                           to reflect the Longview Non-Controlling Interest).
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In the year ended December 31, 2011, rights
to explore, develop and exploit 8,469 net acres of undeveloped land expired. We expect that rights to explore, develop and exploit
11,203 net acres of our undeveloped land holdings will expire by December 31, 2012. The land expirations do not consider our
2012 exploitation and development program that may result in extending or eliminating such potential expirations. We closely monitor
land expirations as compared to our development program with the strategy of minimizing undeveloped land expirations relating to
significant identified opportunities.



Forward Contracts



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



Advantage, including its subsidiary Longview,
has approved a hedging policy using, amongst others, costless collars and fixed price swaps to hedge up to 60% of its gross oil,
NGLs and natural gas production for a maximum period of three years. These hedging activities could expose the Corporation to losses
or gains. To the extent that the Corporation engages in risk management activities related to commodity prices, it will be subject
to credit risk



34







associated with the parties with which
it contracts. This credit risk will be mitigated by entering into contracts with only stable and creditworthy parties and through
the frequent review of the Corporation's exposure to these entities. See "Risk Factors".



Advantage's subsidiary, Longview, has the
following derivatives in place:





|Description of
        Derivative |  | Term                          |  | Volume       |  | Average Price                                              
|--------------------------------- |  | ----------------------------- |  | ------------ |  | -----------------------------------------------------------
|                                  |  |                               |  |              |  |                                                            
|Crude Oil                         |  |                               |  |              |  |                                                            
|Fixed price                       |  | January 2012 to December 2012 |  | 1,000 bbls/d |  | Cdn $97.10/bbl                                             
|                                  |  |                               |  |              |  |                                                            
|Collar                            |  | January 2012 to December 2012 |  | 1,000 bbls/d |  | Bought put Cdn $90.00/bbl
        Sold call Cdn $102.25/bbl
|Electricity                       |  |                               |  |              |  |                                                            
|Fixed price                       |  | January 2012 to December
2012 |  | 0.9 MW       |  | Cdn $77.88 MW/hr                                           





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 1,819 net producing and non-producing wells and 716 net abandoned wells. The approximate net cost to abandon
and reclaim all wells and facilities, discounted at 10%, totals $39.5 million ($310.6 million undiscounted), of which approximately
$9.2 million are included in the estimate of future net revenue ($75.7 million undiscounted). Abandonment and reclamation costs
undiscounted and expected to be paid over the next three years totals $12.3 million.



Tax Horizon



In 2011, 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 2017. See "Risk
Factors".



35







Capital Expenditures



The following tables summarize capital
expenditures (including capitalized general and administrative expenses) related to our activities for the year ended December
31, 2011:



|Capital Expenditures ($ thousands)(1)               |  | 2011 |        
|--------------------------------------------------- |  | ---- | -------
|                                                    |  |      |        
|Land and seismic                                    |  |      | 1,704  
|Drilling, completions and workovers                 |  |      | 199,170
|Well equipping and facilities                       |  |      | 52,857 
|Other                                               |  |      | 443    
|Total expenditures on property, plant and equipment |  |      | 254,174
|                                                    |  |      |        
|Expenditures on exploration and evaluation assets   |  |      | 3,006  
|Property dispositions                               |  |      | (1,099 
|Total capital expenditures                          |  |      | 256,081



Note:



| | (1) | Includes
                                                           capital expenditures related to Longview (without reduction to reflect
                                                           the Longview Non-Controlling Interest).
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Exploration
and Development Activities



The following table sets forth the gross
and net wells in which we participated during the year ended December 31, 2011:



|              |  | Exploratory |     |  | Development |  |     | Total | 
|------------- |  | ----------- | --- |  | ----------- |  | --- | ----- | 
|              |  | Gross       |     |  | Net         |  |     | Gross | 
|              |  |             |     |  |             |  |     |       | 
|Oil wells     |  |             | 1.0 |  |             |  | 1.0 |       | 
|Gas wells     |  |             | -   |  |             |  | -   |       | 
|Service wells |  |             | -   |  |             |  | -   |       | 
|Dry holes     |  |             | -   |  |             |  | -   |       | 
|Total(1)      |  |             | 1.0 |  |             |  | 1.0 |       | 



Note:



| | (1) | Includes
                                                           wells in which Longview participated (without reduction to reflect
                                                           the Longview Non-Controlling Interest).
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Subject to, among other things, the availability
of drilling rigs and weather that permits access to drill sites, in the first six months of 2012, we plan to drill, complete and
tie-in 24 net wells.



See "Other Oil and Gas Information
– Property Descriptions" for a description of the Corporation's exploration and development activities.



36







Production
Estimates



The following table sets out the volume
of our production estimated for the year ended December 31, 2011 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   |    
|Proved Producing               |  |                          | 3,828 |  |           |  | 3,278 |             |  |  | 582                 |  |  |         | 506
|Proved Developed Non-Producing |  |                          | 125   |  |           |  | 103   |             |  |  | 15                  |  |  |         | 13 
|Proved Undeveloped             |  |                          | 521   |  |           |  | 475   |             |  |  | 34                  |  |  |         | 30 
|Total Proved                   |  |                          | 4,473 |  |           |  | 3,856 |             |  |  | 631                 |  |  |         | 548
|Total Probable                 |  |                          | 623   |  |           |  | 535   |             |  |  | 124                 |  |  |         | 92 
|Total Proved Plus Probable(1)  |  |                          | 5,096 |  |           |  | 4,390 |             |  |  | 754                 |  |  |         | 640



Note:



| | (1) | Includes
                                                           Longview production (without reduction to reflect the Longview Non-Controlling
                                                           Interest).
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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 2011 |         |   | Year Ended | 
|----------------------------------------- |  | ------------------ | ------- | - | ---------- | 
|                                          |  | Mar. 31            |         |   | June 30    | 
|Average Daily Production                  |  |                    |         |   |            | 
|Crude Oil (bbls/d)                        |  |                    | 4,537   |   |            | 
|Gas (Mcf/d)                               |  |                    | 111,145 |   |            | 
|NGLs (bbls/d)                             |  |                    | 1,714   |   |            | 
|Combined (boe/d)                          |  |                    | 24,775  |   |            | 
|                                          |  |                    |         |   |            | 
|Average Net Production Prices Received(2) |  |                    |         |   |            | 
|Crude Oil ($/bbl)                         |  |                    | 81.34   |   |            | 
|Gas ($/Mcf)                               |  |                    | 3.72    |   |            | 
|NGLs ($/bbl)                              |  |                    | 59.71   |   |            | 
|Combined ($/boe)                          |  |                    | 35.71   |   |            | 
|                                          |  |                    |         |   |            | 
|Gain/(Loss) on Derivatives                |  |                    |         |   |            | 
|Crude Oil ($/bbl)                         |  |                    | (3.58   | ) |            | 
|Gas ($/Mcf)                               |  |                    | 0.83    |   |            | 
|Combined ($/boe)                          |  |                    | 3.07    |   |            | 
|                                          |  |                    |         |   |            | 
|Royalties Paid                            |  |                    |         |   |            | 
|Crude Oil ($/bbl)                         |  |                    | 13.71   |   |            | 
|Gas ($/Mcf)                               |  |                    | 0.32    |   |            | 
|NGLs ($/bbl)                              |  |                    | 16.80   |   |            | 
|Combined ($/boe)                          |  |                    | 5.12    |   |            | 
|                                          |  |                    |         |   |            | 
|Operating Expenses(3)(4)                  |  |                    |         |   |            | 
|Crude oil ($/bbl)                         |  |                    | 19.08   |   |            | 
|Natural gas ($/Mcf)                       |  |                    | 1.26    |   |            | 
|NGLs ($/bbl)                              |  |                    | 13.42   |   |            | 
|Combined ($/boe)                          |  |                    | 10.09   |   |            | 



37







|                    |  | Quarter Ended 2011 |       |  | Year Ended | 
|------------------- |  | ------------------ | ----- |  | ---------- | 
|                    |  | Mar. 31            |       |  | June 30    | 
|Netback Received(5) |  |                    |       |  |            | 
|Crude Oil ($/bbl)   |  |                    | 44.97 |  |            | 
|Gas ($/Mcf)         |  |                    | 2.97  |  |            | 
|NGLs ($/bbl)        |  |                    | 29.49 |  |            | 
|Combined ($/boe)    |  |                    | 23.57 |  |            | 



Notes:



| | (1) | Before
                                                           deduction of royalties.
| | --- | -----------------------------------------------------------------------------------------

| | (2) | This figure
                                                           includes all field operating expenses.
| | --- | -------------------------------------------------------------------------------------------------------------

| | (3) | 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.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (4) | 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.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (5) | Includes
                                                           Longview (without reduction to reflect the Longview Non-Controlling
                                                           Interest).
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



38







The following table indicates our approximate
average daily production from our important fields for the quarter ended December 31, 2011:



|                      |  | Natural Gas |         |  | NGLs     |  |       | Crude Oil |  |  | Total   | 
|--------------------- |  | ----------- | ------- |  | -------- |  | ----- | --------- |  |  | ------- | 
|Properties            |  | (Mcf/d)     |         |  | (bbls/d) |  |       | (bbls/d)  |  |  | (boe/d) | 
|                      |  |             |         |  |          |  |       |           |  |  |         | 
|Alberta               |  |             |         |  |          |  |       |           |  |  |         | 
|Glacier               |  |             | 91,405  |  |          |  | -     |           |  |  | -       | 
|Nevis                 |  |             | 5,634   |  |          |  | 412   |           |  |  | 869     | 
|Red Deer              |  |             | 9,160   |  |          |  | 98    |           |  |  | 65      | 
|Willesden Green       |  |             | 3,126   |  |          |  | 205   |           |  |  | 154     | 
|Lookout Butte         |  |             | 4,602   |  |          |  | 124   |           |  |  | 8       | 
|Medicine Hat          |  |             | 5,835   |  |          |  | -     |           |  |  | -       | 
|Westerose             |  |             | 2,564   |  |          |  | 190   |           |  |  | 422     | 
|Brazeau/Ferrier       |  |             | 2,958   |  |          |  | 111   |           |  |  | 78      | 
|Wainwright            |  |             | 2,685   |  |          |  | -     |           |  |  | 5       | 
|North Eastern Alberta |  |             | 1,643   |  |          |  | -     |           |  |  | -       | 
|Crossfield            |  |             | 1,622   |  |          |  | 123   |           |  |  | 80      | 
|Skaro/Alexis          |  |             | 186     |  |          |  | -     |           |  |  | 225     | 
|Sunset                |  |             | 1,574   |  |          |  | 43    |           |  |  | 350     | 
|                      |  |             | 132,994 |  |          |  | 1,306 |           |  |  | 2,256   | 
|Saskatchewan          |  |             |         |  |          |  |       |           |  |  |         | 
|Southeast             |  |             | 121     |  |          |  | 2     |           |  |  | 1,905   | 
|Lloydminster          |  |             | 106     |  |          |  | -     |           |  |  | 511     | 
|                      |  |             | 227     |  |          |  | 2     |           |  |  | 2,416   | 
|Other                 |  |             | 4,259   |  |          |  | 8     |           |  |  | 510     | 
|Total                 |  |             | 137,480 |  |          |  | 1,316 |           |  |  | 5,182   | 



Note:



| | (1) | Includes
                                                           Longview (without reduction to reflect the Longview Non-Controlling
                                                           Interest).
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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.
NGL contracts are renegotiated annually and the contracts run for one year and are not cancellable for that term. Approximately
3.5% of our natural gas production is sold to aggregators who accumulate production from various producers and market the gas on
behalf of the group. Such contracts are reserve specific and continue for the life of production from the specified reserves.



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 netbacks on production volumes. See "Other Oil and Gas Information – Forward
Contracts" for our current hedging program.



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.



39







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.



AOG’s Health and Safety Management
Program is recognized by Alberta Occupational Health and Safety, Alberta Workers Compensation Board and the Alberta Association
of Safety Partnerships and as such AOG has received Certificates of Recognition from the above agencies.



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.



The Corporation maintains and will maintain
a safe and environmentally responsible work place and provide training, equipment and procedures to all individuals in adhering
to our policies. The Corporation 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.



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.



40











|Name, Province and
        Country of Residence     |  | Position Held and
        Period Served as a
        Director or
        Officer(4)(5)                            |  | Principal Occupations During Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|--------------------------------------------------- |  | ----------------------------------------------------------------------------------------------------------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                                    |  |                                                                                                                   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Andy J. Mah
        Alberta, Canada                 |  | President since April 21, 2011, Chief Executive Officer since January 27, 2009 and a Director since June 23, 2006 |  | President since April 21, 2011. Chief Executive Officer since January 27, 2009.  Chief Operating Officer of Longview since December 15, 2010. 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.                                                                                                                                                                                                                                                                                                                                                                                                                
|                                                    |  |                                                                                                                   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Kelly I. Drader
        Alberta, Canada             |  | Chief Financial Officer since January 27, 2009 and Director since May 24, 2001                                    |  | Chief Financial Officer of AOG since January 27, 2009. President of AOG from January 27, 2009 to April 21, 2011. President and Chief Executive Officer of Longview since December 15, 2010. 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                                                                                      |  | Mr. Howard is currently a private investor and company director in the Canadian oil and gas sector. He is a Professional Engineer who has had an active career spanning 40 years, including 20 years as a President and CEO of: Barrington Petroleum Ltd., Seagull Energy Canada Ltd., Novalta Resources Ltd and Aberford Resources Corp. Since 2000, Mr. Howard has been a Board member of seven reporting issuers including: Advantage /Advantage Energy Income Fund/Ketch Resources Trust; Rockyview Energy Inc.(Chairman)/APF Energy Trust; and Bear Ridge Resources Inc./Bear Creek Energy Ltd. Also since the year 2000, he has been an investor in and director of 10 widely held private non-reporting issuers.                                                                                                                                                                                                                              
|                                                    |  |                                                                                                                   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Ronald A. McIntosh(1)(3)(8)
        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. Mr. McIntosh has extensive experience in the energy business. His previous roles included President and Chief Executive Officer of Navigo Energy, Chief Operating Officer of Gulf Canada, Vice President Exploration and International of PetroCanada and Chief Operating Officer of Amerada Hess Canada.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|                                                    |  |                                                                                                                   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Stephen E. Balog(1)(3)
        Alberta, Canada      |  | Director since August 16, 2007                                                                                    |  | President, West Butte Management Inc. and Principal of Alconsult International Ltd., both of which are private consulting companies that provide technical and business advisory services to oil and gas operators. Prior thereto, President and 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. Mr. Sharpe is, and has been, a director of Longview since April 27, 2010. Until January, 2012, he was also Chairman of Prime Restaurants Inc. Since December, 2011, he is also a director of C.A. Bancorp. Inc. From October 2009 to March 2010, Mr. Sharpe was Chairman and Chief Executive Officer of Prime Restaurants Royalty Income Fund. Until July, 2009, he was 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 ("Kroll"), New York. Prior to his joining Kroll, Mr. Sharpe was a senior partner with Davies, Ward & Beck in Toronto.





41









|Name, Province and
        Country of Residence |  | Position Held and
        Period Served as a
        Director or
        Officer(4)(5) |  | Principal Occupations During Past Five Years                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|----------------------------------------------- |  | -------------------------------------------------------------------------------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                                |  |                                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Sheila O'Brien(2) (3)
        Alberta, Canada   |  | Director since March 21, 2007                                                          |  | Ms. O’Brien has over 35 year’s experience in the oil and gas, pipeline and petrochemicals sector, in Canada the USA, Europe and South America. She has held leadership positions in human resources, public affairs, health safety and the environment, and government and investor relations. In her roles as a senior executive with NOVA corporation, she led the team that designed an innovative workplace restructuring program that was designated a Worldwide Best Practice by Watson Wyatt consultancy. Ms. O'Brien is the author of two books, "An Extraordinary West" and  "Catching a Rising Tide – an energy vision for Canada" published by the Canada West Foundation.  She was inducted in the Order of Canada in 1998, and received the Jubilee Medal for public service in 2012.                                 
|                                                |  |                                                                                        |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|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.  Senior Vice President of Longview since May 13, 2011. 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. Chief Financial Officer of Longview since March 4, 2010. 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 of AOG since June 23, 2006.  Vice-President, Exploitation of Longview since May 13, 2011. 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, Geosciences and Land of AOG since February 14, 2005. Vice President, Geosciences and Land of Longview since May 13, 2011. Prior thereto, Manager, Geology and Geophysics with AOG since May 23, 2001. 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 at the Calgary based law firm of Burnet, Duckworth & Palmer LLP and has practiced corporate and securities law since 1990. He has served as a director or officer of a number of publicly listed issuers and currently serves as a Director of Madalena Ventures Inc. and Renegade Petroleum Ltd. and as Corporate Secretary for Pinecrest Energy Inc., TriOil Resources Ltd. and Longview Oil Corp. in addition to being a Director or Corporate Secretary for six private issuers.                                                                                                                                                                                                                                                                                                                                       











42







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.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (8) | Mr. McIntosh
                                                           is a director of Fortress Energy Inc. ("Fortress").
                                                           On March 2, 2011, the Court of Queen’s Bench of Alberta granted
                                                           an order (the "Order") under the Companies’
                                                           Creditors Arrangement Act (Canada) ("CCAA") staying
                                                           all claims and actions against Fortress and its assets and allowing
                                                           Fortress to prepare a plan of arrangement for its creditors if necessary.
                                                           Fortress took such step in order to enable Fortress to challenge a
                                                           reassessment issued by the Canada Revenue Agency ("CRA").
                                                           As a result of the reassessment, if Fortress had not taken any action,
                                                           it would have been compelled to immediately remit one half of the reassessment
                                                           to the CRA and Fortress did not have the necessary liquid funds to
                                                           remit, although Fortress had assets in excess of its liabilities with
                                                           sufficient liquid assets to pay all other liabilities and trade payables.
                                                           Fortress believed that the CRA’s position was not sustainable
                                                           and vigorously disputed the CRA’s claim. Fortress filed a Notice
                                                           of Objection to the reassessment and on October 20, 2011 announced
                                                           that its Notice of Objection was successful, CRA having confirmed there
                                                           were no taxes payable. As the CRA claim had been vacated and no taxes
                                                           or penalties were owing Fortress no longer required the protection
                                                           of the Order under the CCAA and on October 28,2011 the Order was removed.
                                                           On March 3, 2011 the TSX suspended trading in the securities of Fortress
                                                           due to Fortress having been granted a stay under the CCAA. In addition
                                                           the securities regulatory authorities in Alberta, Ontario and Quebec
                                                           issued a cease trade order with respect to Fortress for failure to
                                                           file its annual financial statements for the year ended December 31,
                                                           2010 by March 31, 2011. The delay in filing was due to Fortress being
                                                           granted the CCAA order on March 2, 2011 and the resulting additional
                                                           time required by its auditors to deliver their audit opinion. The required
                                                           financial statements and other continuous disclosure documents were
                                                           filed on April 29, 2011 and the cease trade order was subsequently
                                                           removed. On September 1, 2010 Fortress closed the sale of substantially
                                                           all of its oil and gas assets. As a result of the sale Fortress was
                                                           delisted from the TSX on March 30, 2011 as it no longer met minimum
                                                           listing requirements.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



As at March 23, 2012 the directors
and executive officers of AOG, as a group, beneficially owned, directly or indirectly, or exercised control or direction over,
1,944,707 Common Shares, or approximately 1.2% of the issued and outstanding Common Shares.



Cease Trade Orders,
Bankruptcies, Penalties or Sanctions



Other than as disclosed above:



| | (a) | no director or executive officer of AOG has, within the last ten years prior to the date of this
annual information form, 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 was issued after the
director or executive officer 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;
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (b) | no director or executive officer of AOG or security holder holding a sufficient number of securities
of AOG to affect materially the control of AOG is, as at the date of this annual information form, or has, within the last ten
years prior to the date of this annual information form, 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;
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



43







| | (c) | no director or executive officer of AOG 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; and
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (d) | no director or executive officer of AOG 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.



Certain officers and directors of the Corporation
also form part of the management of Longview including Kelly Drader, the President and Chief Executive Officer of Longview, Craig
Blackwood, the Chief Financial Officer of Longview, Andy Mah, the Chief Operating Officer of Longview, Patrick Cairns, the Senior
Vice President of Longview, Neil Bokenfohr, the Vice President, Exploitation of Longview, Weldon Kary, the Vice President, Geosciences
and Land of Longview, Jay P. Reid, the Corporate Secretary of Longview, and Steven Sharpe, a director of each of the Corporation
and Longview. As a result, there is the potential for these individuals to encounter conflicts of interests in the event that the
interests of the Corporation and Longview diverge. See also "Interest of Management and Others in Material Transactions".



DIVIDEND
POLICY



Dividend Policy of the Corporation



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".



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 28               |  | $                      | 0.04 |  |             
|Total:                    |  | $                      | 0.12 |  |             



Note:



| | (1) | On March
                                                           18, 2009 we announced that monthly distributions had 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". We have not paid any dividends
                                                           or distributions on the Common Shares.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



44







Dividend Policy of Longview



Longview has established a policy of declaring
regular monthly cash dividends since the completion of the Longview Offering and the Longview Transaction. The payment and the
amount of dividends declared in any month is subject to the discretion of the board of directors of Longview and will depend on
the board of director's assessment of Longview's outlook for growth, capital expenditure requirements, funds from operations, potential
acquisition opportunities, debt position and other conditions that the board of directors of Longview may consider relevant at
such future time, including applicable restrictions that may be imposed under Longview's credit facilities and on the ability of
Longview to pay dividends upon the satisfaction of the liquidity and solvency tests imposed by the ABCA for the declaration and
payment of dividends. The amount of future cash dividends, if any, may also 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.



The following is a summary of the dividends
declared and paid by Longview for the most recently completed financial year.



|For the 2011 Period Ended |  | Dividend per Common Share |      |  | Payment Date
|------------------------- |  | ------------------------- | ---- |  | ------------
|                          |  |                           |      |  |             
|May 31                    |  | $                         | 0.05 |  |             
|June 30                   |  | $                         | 0.05 |  |             
|July 31                   |  | $                         | 0.05 |  |             
|August 31                 |  | $                         | 0.05 |  |             
|September 30              |  | $                         | 0.05 |  |             
|October 31                |  | $                         | 0.05 |  |             
|November 30               |  | $                         | 0.05 |  |             
|December 31               |  | $                         | 0.05 |  |             
|Total:                    |  | $                         | 0.40 |  |             



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, 2011, there
were 166,304,040 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.



45







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.



5.00% Debentures



The 5.00% Debentures pay interest semi-annually
and are convertible at the option of the holder into Common Shares at the conversion price per Common Share noted below plus accrued
and unpaid interest. The details of the 5.00% Debentures including the balance outstanding as at December 31, 2011 are as follows:



|                 |  | 5.00%        
|---------------- |  | -------------
|Trading symbol   |  | AAV.DB.H     
|Issue date       |  | Dec. 31, 2009
|Maturity date    |  | Jan. 30, 2015
|Conversion price |  | $8.60        
|Outstanding      |  | $86,250,000  



The 5.00% Debentures are redeemable prior
to their maturity date, at the option of the Corporation, upon providing appropriate days advance notification as per the terms
of the debenture indenture. The redemption price for the 5.00% Debentures is $1,000, plus accrued and unpaid interest, and are
redeemable after January 31, 2013 and on or before January 30, 2015, provided that the Current Market Price of the Common Shares
exceeds 125% of conversion price noted above.



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 for the periods indicated.



46







|Period               |  | High |      |  | Low |  |      | Volume | 
|-------------------- |  | ---- | ---- |  | --- |  | ---- | ------ | 
|                     |  | ($)  |      |  | ($) |  |      |        | 
|TSX Trading          |  |      |      |  |     |  |      |        | 
|2011                 |  |      |      |  |     |  |      |        | 
|January              |  |      | 7.47 |  |     |  | 6.61 |        | 
|February             |  |      | 7.83 |  |     |  | 7.33 |        | 
|March                |  |      | 9.00 |  |     |  | 7.40 |        | 
|April                |  |      | 8.90 |  |     |  | 7.84 |        | 
|May                  |  |      | 8.17 |  |     |  | 7.33 |        | 
|June                 |  |      | 8.51 |  |     |  | 7.35 |        | 
|July                 |  |      | 7.85 |  |     |  | 6.59 |        | 
|August               |  |      | 6.82 |  |     |  | 5.10 |        | 
|September            |  |      | 5.76 |  |     |  | 3.82 |        | 
|October              |  |      | 5.49 |  |     |  | 3.79 |        | 
|November             |  |      | 5.57 |  |     |  | 4.43 |        | 
|December             |  |      | 4.92 |  |     |  | 3.82 |        | 
|                     |  |      |      |  |     |  |      |        | 
|2012                 |  |      |      |  |     |  |      |        | 
|January              |  |      | 4.46 |  |     |  | 3.35 |        | 
|February             |  |      | 4.15 |  |     |  | 3.51 |        | 
|March (1 to 22)      |  |      | 3.93 |  |     |  | 3.53 |        | 
|                     |  |      |      |  |     |  |      |        | 
|NYSE Trading (U.S.$) |  |      |      |  |     |  |      |        | 
|2011                 |  |      |      |  |     |  |      |        | 
|January              |  |      | 7.45 |  |     |  | 6.65 |        | 
|February             |  |      | 7.94 |  |     |  | 7.38 |        | 
|March                |  |      | 9.22 |  |     |  | 7.49 |        | 
|April                |  |      | 9.29 |  |     |  | 8.14 |        | 
|May                  |  |      | 8.56 |  |     |  | 7.57 |        | 
|June                 |  |      | 8.68 |  |     |  | 7.53 |        | 
|July                 |  |      | 8.17 |  |     |  | 6.90 |        | 
|August               |  |      | 7.19 |  |     |  | 5.15 |        | 
|September            |  |      | 5.90 |  |     |  | 3.83 |        | 
|October              |  |      | 5.52 |  |     |  | 3.57 |        | 
|November             |  |      | 5.50 |  |     |  | 4.22 |        | 
|December             |  |      | 4.86 |  |     |  | 3.68 |        | 
|                     |  |      |      |  |     |  |      |        | 
|2012                 |  |      |      |  |     |  |      |        | 
|January              |  |      | 4.39 |  |     |  | 3.32 |        | 
|February             |  |      | 4.17 |  |     |  | 3.52 |        | 
|March (1 to 22)      |  |      | 3.98 |  |     |  | 3.56 |        | 



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.



47







|Period          |  | High |        |  | Low |  |        | Volume | 
|--------------- |  | ---- | ------ |  | --- |  | ------ | ------ | 
|                |  | ($)  |        |  | ($) |  |        |        | 
|2011            |  |      |        |  |     |  |        |        | 
|January         |  |      | 108.00 |  |     |  | 104.00 |        | 
|February        |  |      | 112.00 |  |     |  | 108.44 |        | 
|March           |  |      | 121.00 |  |     |  | 109.50 |        | 
|April           |  |      | 120.00 |  |     |  | 109.00 |        | 
|May             |  |      | 115.00 |  |     |  | 111.00 |        | 
|June            |  |      | 115.00 |  |     |  | 109.24 |        | 
|July            |  |      | 115.90 |  |     |  | 104.69 |        | 
|August          |  |      | 104.13 |  |     |  | 97.00  |        | 
|September       |  |      | 99.00  |  |     |  | 89.51  |        | 
|October         |  |      | 96.99  |  |     |  | 89.00  |        | 
|November        |  |      | 97.00  |  |     |  | 92.68  |        | 
|December        |  |      | 97.00  |  |     |  | 93.75  |        | 
|                |  |      |        |  |     |  |        |        | 
|2012            |  |      |        |  |     |  |        |        | 
|January         |  |      | 98.99  |  |     |  | 95.00  |        | 
|February        |  |      | 98.00  |  |     |  | 97.00  |        | 
|March (1 to 22) |  |      | 98.10  |  |     |  | 97.02  |        | 



Prior Sales



During the year ended December 31, 2011,
the Corporation granted an aggregate of 1,443,956 restricted shares with a weighted average price of $7.78.



ESCROWED
SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER



There are presently no AOG securities held
in escrow or subject to contractual restrictions on transfer.



LEGAL
PROCEEDINGS



There are no outstanding legal proceedings
and Advantage and its subsidiaries were not involved in any legal proceedings during the year ended December 31, 2011, which involved
claims in excess of 10% of the Corporation's current asset value to which Advantage or its subsidiaries were a party or in respect
of which any of its properties are subject, nor are there any such proceedings known to be contemplated.



REGULATORY
ACTIONS



During the year ended December 31, 2011
there were: (i) no penalties or sanctions imposed against AOG or its subsidiaries 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 AOG
or its subsidiaries that would likely be considered important to a reasonable investor in making an investment decision; and (iii)
no settlement agreements AOG or its subsidiaries entered into before a court relating to a securities legislation or with a securities
regulatory authority.



INTEREST
OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS



Other than as disclosed below, there were
no material interests, direct or indirect, of directors and executive officers of AOG or its subsidiaries or nominees for director
of AOG or its subsidiaries, 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 the year ended December 31, 2011 or in any proposed
transaction which has materially affected or would materially affect AOG or its subsidiaries.



Steven Sharpe, a director of AOG, is a
director of Longview. In addition, concurrent with closing of the Longview Offering, AOG entered into the TSA pursuant to which
AOG provides the necessary personnel and technical services to manage Longview's business. The officers of Longview are Kelly Drader
(President and Chief Executive Officer), Craig Blackwood (Chief Financial Officer), Andy Mah (Chief Operating Officer), Patrick
Cairns (Senior



48







Vice President), Neil Bokenfohr (Vice President,
Exploitation) and Weldon Kary (Vice President, Geosciences and Land), each of which are executive officers of AOG. The officers
of Longview provide services to Longview under the TSA but will remain as employees of Advantage. See "General Development
of the Business – 2011".



MATERIAL
CONTRACTS



Material Contracts
of AOG



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.



Material Contracts of Longview



Except for contracts entered into in the
ordinary course of business the only agreements which are material to Longview are the agreement for the Longview credit facility,
the TSA, the governance agreement between AOG and Longview (the "Governance Agreement") and the registration rights
agreement between AOG and Longview (the "Registration Rights Agreement"), copies of which agreement are available
on Longview's SEDAR profile at www.sedar.com and the terms of which are summarized below.



Longview Credit Facilities



In connection with the Longview Transaction,
on April 14, 2011, Longview entered into a credit agreement with a syndicate of financial lenders for an extendible revolving credit
facility in the maximum principal amount of $180 million as well as an operating credit agreement with a Canadian financial institution
in the maximum principal amount of $20 million. The Longview Credit Facilities are collateralized by a floating charge demand debenture
of $1 billion over Longview's assets. Various borrowing options are available under the Longview Credit Facilities, including prime
rate loans, bankers’ acceptances, U.S. base rate loans and LIBOR loans. The amounts available to Longview from time to time
under the Longview Credit Facilities are based upon the borrowing base determined by the financial lenders which is re-determined
by the lenders on an annual basis after the receipt of the independent engineering report and such other information as required
by the lenders. The next redetermination of the borrowing base is anticipated to occur in April of 2012. The borrowing base constitutes
a revolving facility for a 364 day term which is extendible for a further 364 day revolving period, at the option of the lenders.



Technical Services Agreement



Longview entered into the Technical Services
Agreement with Advantage on April 14, 2011. Under the Technical Services Agreement, Advantage provides the necessary personnel
and technical services to manage Longview's business and Longview reimburses Advantage on a monthly basis for its share of administration
charges equal to: (i) its proportionate share of Advantage's general and administrative costs, based upon its level of oil and
natural gas production relative to the combined level of oil and natural gas production for Advantage and Longview but such general
and administrative costs do not include direct costs attributable to Advantage, including, but not limited to, fees payable to
the board of directors of Advantage, and fees associated with Advantage being a public company (including, but not limited to,
expenses associated with ongoing financial reporting and disclosure, listing fees, legal fees, audit fees, director fees and costs
related to ongoing investor relations and annual meetings); plus (ii) direct general and administrative costs for engineering,
acquisition, legal and other professional services; less (iii) operating and capital overhead recoveries directly attributable
to the Acquired Assets. As of December 31, 2011, Longview has paid $3.8 million pursuant to the Technical Services Agreement.



The Technical Services Agreement became
effective upon the completion of the Acquisition of the Acquired Assets and will continue for an initial period of one year, ending
on April 14, 2012. The term of the Technical Services Agreement will automatically renew for an additional one year term on each
anniversary date of the agreement. Following the first year of the operation of the Technical Services Agreement, either party
may terminate the Technical Services Agreement by providing 120 days written notice to the other party.



49







Registration Rights Agreement



Longview entered into the Registration
Rights Agreement with Advantage on April 14, 2011. The Registration Rights Agreement provides that for a period commencing
12 months after the date a receipt has been issued for the final prospectus under applicable securities legislation in Canada for
the Offering (April 6, 2011) and expiring on the earlier of: (i) a date that is seven years from the date of the Registration Rights
Agreement; or (ii) the date that is three months after the date that Advantage ceases to be the beneficial holder of more than
10% of the outstanding common shares of Longview, Advantage may require Longview to prepare, file and obtain a receipt for a final
prospectus under applicable securities legislation in Canada qualifying the distribution of some or all of the common shares or
other securities of Longview held by Advantage. Such right is subject to certain restrictions. In addition, during the aforementioned
period, Advantage has the right to receive prompt notice should Longview propose to file a prospectus in Canada pursuant to an
offering of Longview's securities and Advantage may include some or all of the common shares or other securities of Longview held
by Advantage for distribution pursuant to the said offering. Such right is subject to certain restrictions.



Governance Agreement



The Governance Agreement was also entered
into on April 14, 2011 pursuant to which Advantage agreed that until the earlier of: (i) the date that Advantage ceases to be the
beneficial owner of more than 50% of the outstanding common shares of Longview; and (ii) the date that Advantage and Longview otherwise
agree to in writing, Advantage will vote its common shares of Longview in such a manner so as to ensure that the board of directors
of Longview is comprised of a majority of independent directors. Pursuant to the Governance Agreement, Longview will agree to include
in any slate or individual list of directors proposed for election at a meeting of shareholders such independent directors as may
be nominated or put forward by Advantage. Advantage's agreement to vote its common shares of Longview to ensure that the majority
of the directors of Longview are independent, will not apply in the circumstances where a dissident slate or list of directors
is being proposed by a third party.



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 Continuous
Disclosure Obligations 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 relevant legislation and requirements of the Public Company Accounting Oversight Board (PCAOB).



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.



50







AUDIT
COMMITTEE INFORMATION



Composition of the
Audit Committee



The audit committee (the "Audit
Committee") is comprised of Messrs. Paul Haggis, Stephen Balog, 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. and a Principal of Alconsult International Ltd., both of which are private consulting companies that provide technical and business advisory services to oil and gas operators.  Prior thereto, Mr. Balog was President and 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 served on the Petroleum Advisory Committee, Alberta Securities Commission from 2009-2011 and has a Bachelor of Science, Chemical Engineering.                                                                                                                                                                                                                                                                                                                                                                                            
|                                                |  |             |  |                              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|Carol D. Pennycook
        Ontario, Canada      |  | Yes         |  | Yes                          |  | Ms. Pennycook is a partner at the Toronto offices of Davies Ward Phillips & Vineberg, LLP, a national law firm.  Ms. Pennycook received her LLB in 1979 and has been a partner since 1986.  A significant portion of Ms. Pennycook's practice involves financing transactions.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    







Pre-Approval of
Policies and Procedures



We have adopted policies 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.



51







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;
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------------



| | 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.



52







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.
| | -- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 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.
| | -- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



53







| | 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.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



54







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.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------------------------



| | 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;
| | --- | -------------------------------------------------------------------------------------------------------------------------------------



55







| | (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.
| | --- | ----------------------------------------------------------------------------------------



56







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.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 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.



57







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.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



AUDIT
SERVICE FEES



Auditor Services
Fees



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



|Type of Service Provided                                     |  | 2010 |         |     | 2011 |  
|------------------------------------------------------------ |  | ---- | ------- | --- | ---- | -
|                                                             |  |      |         |     |      |  
|Audit Fees                                                   |  | $    | 645,000 |     |      | $
|Audit-Related Fees                                           |  |      | 251,350 | (1) |      |  
|Tax Fees (these services included general tax consultations) |  |      | -       |     |      |  



Note:



| | (1) | Includes
                                                           work related to prospectus for the Longview Transaction.
| | --- | ----------------------------------------------------------------------------------------------------------------------------



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 and upgrading, 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 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 in western Canada.



58







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, 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.



Natural Gas



The price of the vast majority of natural
gas produced in western Canada is now determined through highly liquid market hubs such as the Alberta "NIT" (Nova Inventory
Transfer) hub rather than through direct 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.



The governments of Alberta 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.



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. 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 the total supply of goods of the party maintaining the restriction as compared to 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 measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply. All three signatory countries
are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative
restriction is prohibited. The signatory countries are also prohibited from imposing a minimum or maximum import price requirement
except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA requires energy regulators
to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes
will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution
arrangements, all of which are important for Canadian oil and natural gas exports.



59







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 oil sands projects, 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.



Royalties are currently paid pursuant to
"The New Royalty Framework" (implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008)
and the "Alberta Royalty Framework", which was implemented in 2010.



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. Effective January 1, 2011, the maximum royalty payable under the royalty regime was set at 40%. The royalty
curve for conventional oil announced on May 27, 2010 amends the price component of the conventional oil royalty formula to moderate
the increase in the royalty rate at prices higher than $535/m3 compared to the previous royalty curve.



Royalty rates for natural gas under the
royalty regime are similarly determined using a single sliding rate formula incorporating separate variables to account for production
rates and market prices. Effective January 1, 2011, the maximum royalty payable under the royalty regime was set at 36%. The royalty
curve for natural gas announced on May 27, 2010 amends the price component of the natural gas royalty formula to moderate the increase
in the royalty rate at prices higher than $5.25/GJ compared to the previous royalty curve.



Oil sands projects are also subject to
the Alberta's royalty regime. Prior to payout of an oil sands project, 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, determined using the average monthly
price, expressed in Canadian dollars, for WTI crude oil and Cushing, Oklahoma: 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. In addition, concurrently
with the implementation of the New Royalty Framework, the Government of Alberta renegotiated existing contracts with certain oil
sands producers that were not compatible with the current royalty regime.



60







Producers of oil and natural gas from freehold
lands in Alberta are required to pay annual freehold production taxes. The level of the freehold production tax is based on the
volume of monthly production and a specified rate of tax for both oil and gas.



The Innovative Energy Technologies Program
(the "IETP"), which is currently in place, has the stated objectives of increasing recovery from oil and gas deposits,
finding technical solutions to the gas over bitumen issue, improving the recovery of bitumen by in-situ and mining techniques and
improving the recovery of natural gas from coal seams. The IETP provides royalty adjustments to specific pilot and demonstration
projects that utilize new or innovative technologies to increase recovery from existing reserves.



The Government of Alberta currently has
in place two royalty programs, both of which commenced in 2008 and are 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 May 27, 2010, the natural
gas deep drilling program was amended, retroactive to May 1, 2010, by reducing the minimum qualifying depth to 2,000 metres, removing
a supplemental benefit of $875,000 for wells exceeding 4,000 metres that are spudded subsequent to that date, and including wells
drilled into pools drilled prior to 1985, among other changes.



On November 19, 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 five-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 program, companies drilling new natural gas or conventional
deep oil 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 royalty regime. These options expired on February 15, 2011 and on January 1, 2014, all producers
operating under the transitional royalty rates will automatically become subject to the royalty regime. The revised royalty curves
for conventional oil and natural gas will not be applied to production from wells operating under the transitional royalty rates.



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. One aspect of the
program was a drilling royalty credit program which provided up to a $200 per metre royalty credit for new wells. The drilling
credit program applied to wells that were drilled between April 1, 2009 and March 31, 2010 and has not been extended for wells
drilled after March 31, 2010. Another aspect of the program was a new well royalty program which provided for a maximum 5% royalty
rate for eligible new wells for the first twelve (12) productive months or until the regulated "volume cap" was reached.
The New Well Royalty Regulation, providing for the permanent implementation of this incentive program, was approved by an
Order-in-Council on March 17, 2011.



In addition to the foregoing, the Government
of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development
of unconventional resources (the "Emerging Resource and Technologies Initiative"). Specifically:



| | · | Coalbed methane wells will receive a maximum royalty rate of 5% for 36 producing months on up to
750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Shale gas wells will receive a maximum royalty rate of 5% for 36 producing months with no limitation
on production volume, retroactive to wells that began producing on or after May 1, 2010;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Horizontal gas wells will receive a maximum royalty rate of 5% for 18 producing months on up to
500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | · | Horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty
rate of 5% with volume and production month limits set according to the depth of the well (including the horizontal distance),
retroactive to wells that commenced drilling on or after May 1, 2010.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



61







The Emerging Resource and Technologies
Initiative will be reviewed in 2014, and the Government of Alberta has committed to providing industry with three years notice
at that time if it decides to discontinue the program.



Saskatchewan



In Saskatchewan, the amount payable as
Crown royalty or freehold production tax 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 Crown royalty or
freehold production tax in respect of natural gas production is determined by a sliding scale based on the actual price received,
the quantity produced in a given month, the type of natural gas, and the vintage of the natural gas. Like conventional oil, natural
gas may be 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.



On December 9, 2010, the Government of
Saskatchewan enacted the Freehold Oil and Gas Production Tax Act, 2010 replacing the existing Freehold Oil and Gas Production
Tax Act with the intention to facilitate more efficient payment of freehold production taxes by industry. No regulations have
been passed with respect to the calculation of freehold production taxes under the new legislation, although several regulations
remain in force under the previous legislation.



62







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
provides 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 Incentive Volumes for Horizontal Gas Wells drilled on or after June 1, 2010 and
before April 1, 2013 providing reduced Crown royalty and freehold tax rates on incentive volumes of 25,000,000 m3 for horizontal
gas wells;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | 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;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | 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;
and
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | · | Royalty/Tax Regime for High Water-Cut Oil Wells granting "third tier oil" royalty/tax
rates to incremental high water-cut oil production resulting from qualifying investments made to rejuvenate eligible oil wells
and/or associated facilities.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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 of Canada's plan to reintroduce full deductibility of provincial resource royalties for corporate income
tax purposes.



63







On June 22, 2011, the Government of Saskatchewan
released the Upstream Petroleum Industry Associated Gas Conservation Standards which are designed to reduce emissions resulting
for the flaring and venting of associated gas (the "Associated Natural Gas Standards"). The Associated Natural
Gas Standards were jointly developed with industry and the implementation of such standards is set to commence on July 1, 2012
for new wells and facilities licensed on or after such date, and to apply to existing licensed wells and facilities on July 1,
2015.



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, 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 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.



Alberta also has a policy of "shallow
rights reversion" which provides 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. Leases and licences that were granted prior to January 1, 2009 but continued after that date are not
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. The order in which these
agreements will receive reversion notices will depend on their vintage and location, and the Government of Alberta had anticipated
that the receipt of reversion notices for older leases and licenses would commence in April 2011. However, on April 14, 2011, the
Government of Alberta announced it was deferring serving shallow rights reversion notices and will revisit the decision in spring
2012.



Environmental Regulation



The oil and natural gas industry is currently
subject to environmental regulations pursuant to a variety of provincial and federal legislation, all of which is subject to governmental
review and revision from time to time. 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.



64







The Alberta Land Stewardship Act
(the "ALSA") was proclaimed in force in Alberta on October 1, 2009 and provides the legislative authority for
the Government of Alberta to implement the policies contained in the ALUF. Regional plans established pursuant to the ALSA will
be deemed to be legislative instruments equivalent to regulations and will be 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, leases, licenses, approvals and authorizations
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.



On August 29, 2011 the Government of Alberta
released a revised draft of the Lower Athabasca Regional Plan (the "Revised LARP") updating its prior draft of
April 5, 2011 (the "Draft LARP"). The Revised LARP, while establishing several conservation areas of the Athabasca
region, has changed the boundaries of certain conservation areas outlined in the Draft LARP with the result that fewer oil sands
leases appear to be impacted. Consistent with the Draft LARP, as the intention of the Revised LARP is to manage the areas to minimize
or prevent new land disturbance, activities associated with oil sands development are considered incompatible with the intent to
manage such conservation areas. However, references to the cancellation of existing tenures have been removed from the Revised
LARP and the Revised LARP now contemplates that the conservation areas will be created pursuant to existing legislation rather
than the previously contemplated regulations. Existing conventional petroleum and natural gas rights will not be affected, although
the Revised LARP raises some question as to whether new conventional leases and licenses will be granted in the conservation areas
in the future. The planning process is also underway for a regional plan for the South Saskatchewan Region.



Climate Change Regulation



Federal



In December 2002, the Government of Canada
ratified the Kyoto Protocol ("Kyoto Protocol"), which requires a reduction in greenhouse gas ("GHG")
emissions by signatory countries between 2008 and 2012. The Kyoto Protocol officially came into force on February 16, 2005 although
on December 12, 2011 Canada formally withdrew from the Kyoto Protocol.



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 GHGs 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"). 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 apply 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.



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 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





65







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.



66







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 governed 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:



| | (a) | 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 per tonne of CO2 equivalent
for the 2010 to 2012 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 GHG 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.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (b) | 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.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (c) | Under the Updated Action Plan, regulated entities were 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. However, with the recent withdrawal from the Kyoto Protocol, the future use of this mechanism may
not occur.
| | --- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (d) | 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.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



From December 7 to 18, 2009, government
leaders and representatives met in Copenhagen, Denmark and agreed to the Copenhagen Accord, which 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. Another meeting of government leaders and representatives in 2010 resulted in the Cancun Agreements wherein developed
countries committed to additional measures to help developing countries deal with climate change. Neither the Copenhagen Accord
nor the Cancun Agreements establish binding GHG emissions reduction targets. In response to the Copenhagen Accord, the Government
of Canada indicated that it will seek to achieve a 17% reduction in GHG emissions from 2005 levels by 2020.



Although draft regulations for the implementation
of the Updated Action Plan were intended to become binding on January 1, 2010, only draft regulations pertaining to carbon dioxide
emissions from coal-fired generation of electricity have been proposed to date. Further, representatives of the Government of Canada
have 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 GHG emissions regulation. As a result, it is unclear to what extent, if any;
the proposals contained in the Updated Action Plan will be implemented.



67







The United States Environmental Protection
Agency (the "EPA") has indicated its intention to impose GHG emissions standards for fossil fuel-fired power plants
by specifying that it will issue final regulations by May 26, 2012, and with respect to refineries, specifying that it will issue
proposed regulations by December 10, 2011 and finalized regulations by November 10, 2012. The EPA did not meet the December 10,
2011 deadline and it is unclear whether the EPA will also miss the finalized regulations deadline.



Alberta



Alberta enacted the Climate Change and
Emissions Management Act (the "CCEMA") on December 4, 2003, amending it through the Climate Change and
Emissions Management Amendment Act which received royal assent 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 GHGs a year are subject to compliance with the CCEMA. Similar to the Updated Action Plan, the CCEMA and the associated
Specified Gas Emitters Regulation make a distinction between "Established Facilities" and "New Facilities".
Established Facilities are defined as facilities that completed their first year of commercial operation prior to January 1, 2000
or that have completed eight or more years of commercial operation. Established Facilities are required to reduce their emissions
intensity to 88% of their baseline for 2008 and subsequent years, with their baseline being established by the average of the ratio
of the total annual emissions to production for the years 2003 to 2005. New Facilities are defined as facilities that completed
their first year of commercial operation on December 31, 2000, or a subsequent year, and have completed less than eight years of
commercial operation, or are designated as New Facilities in accordance with the Specified Gas Emitters Regulation. New
Facilities are required to reduce their emissions intensity by 2% from baseline in the fourth year of commercial operation, 4%
of baseline in the fifth year, 6% of baseline in the sixth year, 8% of baseline in the seventh year, and 10% of baseline in the
eighth year. Unlike the Updated Action Plan, the CCEMA does not contain any provision for continuous annual improvements in emissions
intensity reductions beyond those stated above.



The CCEMA contains compliance mechanisms
that are similar to 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.



On December 2, 2010, the Government of
Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010, which deemed the pore space underlying all land
in Alberta to be, and to have always been, the property of the Crown and provided for the assumption of long-term liability for
carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.



Advantage does not have a working interest
in any facility that is expected to exceed emissions thresholds.



Saskatchewan



On May 11, 2009, the Government of Saskatchewan
announced The Management and Reduction of Greenhouse Gases Act (the "MRGGA") to regulate GHG emissions
in the province. The MRGGA received Royal Assent on May 20, 2010 and will come into force on proclamation. Regulations under the
MRGGA have also yet to be proclaimed, but draft versions indicate that Saskatchewan will adopt the goal of a 20% reduction in GHG
emissions from 2006 levels by 2020 and permit the use of pre-certified investment credits, early action credits 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.



68







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.



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 natural 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 natural gas acquisition, development and exploration activities.
Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Corporation. These factors
include economic conditions, in the United States, Canada and Europe, the actions of Organization of the Petroleum Exporting Countries
("OPEC"), governmental regulation, political stability in the Middle East, Northern Africa and elsewhere, the
foreign supply of oil and natural 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 natural 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.



Oil and natural gas 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 sanctions imposed on certain oil producing nations by other
countries and the ongoing credit and liquidity concerns. Volatile oil and natural gas prices make it difficult to estimate the
value of producing properties for acquisitions and often cause disruption in the market for oil and natural 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.



69







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 therein. 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, completing (including hydraulic fracturing), operating and other costs.
Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. 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.



Oil and natural gas exploration, development
and production operations are subject to all the risks and hazards typically associated with such operations, including fire, explosion,
blowouts, cratering, sour gas releases, spills or other environmental hazards, 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. 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. In accordance with industry practice,
the Corporation is not fully insured against all risks, nor are all risks insurable. Although the Corporation maintains liability
insurance in an amount that it considers consistent with industry practice, the nature of certain risks is such that liabilities
could exceed policy limits or not be covered, in either event the Corporation could incur significant costs.



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 natural 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





70







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.



71







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 natural 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.



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.



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 availability of, and the ability to acquire, water supplies needed for drilling and hydraulic
fracturing, or the Corporation's ability to dispose of water used or removed from strata at a reasonable cost and within applicable
environmental regulations;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | · | 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.
| | - | -------------------------------------------------------------------------------------------------------------



72







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.



Seasonality



The level of activity in the Canadian oil
and natural 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 natural 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.



Gathering and Processing Facilities
and Pipeline Systems



The Corporation delivers its products through
gathering, processing and pipeline systems some of which it does not own. The amount of oil and natural gas that the Corporation
can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline
systems. The lack of availability of capacity in any of the gathering, processing and pipeline systems, and in particular the processing
facilities, could result in the Corporation’s inability to realize the full economic potential of its production or in a
reduction of the price offered for the Corporation’s production. Any significant change in market factors or other conditions
affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities
could harm the Corporation's business and, in turn, the Corporation’s financial condition, results of operations and cash
flows.



A portion of the Corporation's production
may, from time to time, be processed through facilities owned by third parties and over which the Corporation does not have control.
From time to time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or
as a result of unexpected events. A discontinuation or decrease of operations could materially adversely affect the Corporation's
ability to process its production and to deliver the same for sale.



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 and development 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.



Credit Facility
Arrangements



The
Corporation currently has a credit facility and the amount authorized thereunder is dependent on the borrowing base determined
by its lenders. The Corporation is required to comply with covenants under its credit facility which may, in certain cases, include
certain financial ratio tests, which from time to time either affect the availability, or price, of additional funding and in the
event that the Corporation does not comply therewith the Corporation's access to capital could be restricted or repayment could
be required. The failure of the Corporation to comply with such covenants, which may be affected by events beyond the Corporation's
control, could result in the default under the Corporation's credit facility which could result in the Corporation being required
to repay amounts owing thereunder. Even if the Corporation is able to obtain new financing, it may not be on commercially reasonable
terms or terms that are acceptable to the Corporation. If the Corporation is unable to repay amounts owing, the lenders



73







under
the credit facility could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.
The acceleration of the Corporation's indebtedness under one agreement may permit acceleration of indebtedness under other agreements
that contain cross default or cross-acceleration provisions. In addition, the Corporation's credit facility may, from time to time,
impose operating and financial restrictions on the Corporation that could include restrictions on, the payment of dividends, repurchase
or making of other distributions with respect to the Corporation's securities, incurring of additional indebtedness, provision
of guarantees, the assumption of loans, making of capital expenditures, entering into of amalgamations, mergers, take-over bids
or disposition of assets, among others.



The
Corporation's borrowing base is determined and re-determined by the Corporation's lenders based on the Corporation's reserves,
commodity prices, applicable discount rate and other factors as determined by the Corporation's lenders. A material decline in
commodity prices could reduce the Corporation's borrowing base, therefore reducing the funds available to the Corporation under
the credit facility which could result in a portion, or all, of the Corporation's bank indebtedness be required to be repaid.



Hydraulic Fracturing



Hydraulic fracturing involves the injection
of water, sand and small amounts of additives under pressure into rock formations to stimulate hydrocarbon (oil and natural gas)
production. The use of hydraulic fracturing is being used to produce commercial quantities of oil and natural gas from reservoirs
that were previously unproductive. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead
to operational delays, increased operating costs or third party or governmental claims, and could increase the Corporation's costs
of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations which
are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of
oil and natural gas that the Corporation is ultimately able to produce from its reserves.



Global Financial
Crisis



Recent market events and conditions, including
disruptions in the international credit markets and other financial systems and the American and European sovereign debt levels
have caused significant volatility in commodity prices. These conditions have caused a decrease in confidence in the global credit
and financial markets and have created 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. This volatility may in the
future affect the Corporation's ability to obtain equity or debt financing on acceptable terms.



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, to the extent that the Corporation engages in price risk management activities to protect itself from
commodity price declines, it may also be prevented from realizing the full benefits of price increases above the levels of the
derivative instruments used to manage price risk. In addition, the Corporation’s hedging arrangements may expose it to the
risk of financial loss in certain circumstances, including instances in which:



| | · | production falls short of the hedged volumes;
| | - | ---------------------------------------------



| | · | there is a widening of price-basis differentials between delivery points for production and the
delivery point assumed in the hedge arrangement;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------



| | · | the counterparties to the hedging arrangements or other price risk management contracts fail to
perform under those arrangements; or
| | - | ------------------------------------------------------------------------------------------------------------------------------------





74







| | · | a sudden unexpected event materially impacts oil and natural gas prices.
| | - | ------------------------------------------------------------------------



75







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.



Variations in Foreign
Exchange Rates and Interest Rates



World oil and natural 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.



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.



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.



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 exploration and production activities, prices, 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 crude
oil and natural gas and increase the Corporation's costs, either 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 natural 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.



76







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, certain 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.



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.



Tax Horizon



It is expected, based upon current legislation,
the projections contained in the Sproule Report and various other assumptions that no cash income taxes are to be paid by the Corporation
prior to 2017. A lower level of capital expenditures than those contained in the Sproule Report or should the assumptions used
by the Corporation prove to be inaccurate, the Corporation may be required to pay cash income taxes sooner than anticipated, which
will reduce cash flow available to 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.



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. There may be valid challenges
to title, or proposed legislative changes which affect title, to the oil and natural gas properties the Corporation controls that,
if successful or made into law, could impair the Corporation’s activities on them and result in a reduction of the revenue
received by the Corporation.



77







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 considers 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 businesses 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 may be 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.



In addition, acquisitions of oil and gas
properties or companies are based in large part on engineering, environmental and economic assessments made by the acquiror, independent
engineers and consultants. These assessments include a series of assumptions regarding such factors as recoverability and marketability
of oil and natural gas, environmental restrictions and prohibitions regarding releases and emissions of various substances, future
prices of oil and gas, future operating costs, future capital expenditures and royalties and other government levies which will
be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond the control of the
Corporation. All such assessments involve a measure of geologic, engineering, environmental and regulatory uncertainty that could
result in lower production and reserves or higher operating or capital expenditures than anticipated. Although select title and
environmental reviews are conducted prior to any purchase of resource assets, such reviews cannot guarantee that any unforeseen
defects in the chain of title will not arise to defeat the Corporation's title to certain assets or that environmental defects,
liabilities or deficiencies do not exist or are greater than anticipated. Such deficiencies or defects could adversely affect the
value of the assets acquired and the Corporation's securities.



Climate Change



The Corporation's exploration and production
facilities and other operations and activities emit greenhouse gases and require the Corporation to comply with greenhouse gas
emissions legislation in Alberta or that may be enacted in other provinces. The Corporation may also be required comply with the
regulatory scheme for greenhouse gas emissions ultimately adopted by the federal government, which regulations are expected to
be consistent 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 regulated
by 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".



78







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,
North Africa 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 does not have insurance to protect against the risk from terrorism.



Aboriginal Claims



Aboriginal peoples have claimed aboriginal
title and rights to portions of western 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.



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.
As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales,
the Corporation's ability to do so is dependent on, among other factors, the overall state of the capital markets, the Corporation’s
credit rating (if applicable), interest rates, tax burden due to new tax laws and investor appetite for investments in the energy
industry and the Corporation's securities in particular. Further, if the Corporation's revenues or reserves decline, it may not
have access to the capital necessary to undertake or complete future drilling programs. 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 and from time to time, the Corporation may require additional
financing in order to carry out its oil and natural gas acquisition, exploration and development activities. As a result of the
global economic volatility, the Corporation, along with many other oil and natural gas entities, may, from time to time, have restricted
access to capital and increased borrowing costs. 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. To the extent
that external sources of capital become limited or unavailable or available on onerous terms, the Corporation's ability to make
capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and
results of operations may be materially and adversely affected as a result. In addition, the future development of the Corporation's
petroleum properties may require additional financing and there are no assurances that such financing will be available or, if
available, will be available upon acceptable terms. Failure to obtain any financing necessary for the Corporation's capital expenditure
plans may result in a delay in development or production on the Corporation’s properties.



79







Issuance of Debt



From time to time the Corporation may enter
into transactions to acquire assets or 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 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.



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.



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.



Market Price of Common Shares



The trading price of securities of oil
and natural gas issuers is subject to substantial volatility. This volatility is often based on factors both related and unrelated
to the financial performance or prospects of the issuers involved. The market price of the Common Shares could be subject to significant
fluctuations in response to variations in the Corporation's operating results, financial condition, liquidity and other internal
factors. Factors that could affect the market price of the Common Share that are unrelated to the Corporation's performance include
domestic and global commodity prices and market perceptions of the attractiveness of particular industries. The price at which
the Common Shares will trade cannot be accurately predicted.



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.



80







Conflicts of Interest



Circumstances may arise where members of
the board of directors of the Corporation are directors or officers of corporations which are in competition to the interests of
the Corporation. No assurances can be given that opportunities identified by such board members will be provided to the Corporation.



Certain directors of the Corporation are
also directors of other oil and natural 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 "Directors
and Executive Officers – Conflicts of Interest".



Dividends



The Corporation has not paid any dividends
on its outstanding shares. The amount of future cash dividends paid by the Corporation, if any, will be subject to the discretion
of the board of directors of the Corporation and will depend on a variety of factors and conditions existing from time to time,
including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating
costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate
law for the declaration and payment of dividends. See "Dividend Policy".



Internal Controls



Effective internal controls are necessary
for the Corporation to provide reliable financial reports and to help prevent fraud. Although the Corporation will undertake a
number of procedures in order to help ensure the reliability of its financial reports, including those imposed on it under Canadian
securities laws, the Corporation cannot be certain that such measures will ensure that the Corporation will maintain adequate control
over financial processes and reporting. Failure to implement required new or improved controls, or difficulties encountered in
their implementation, could harm the Corporation's results of operations or cause it to fail to meet its reporting obligations.
If the Corporation or its independent auditors discover a material weakness, the disclosure of that fact, even if quickly remedied,
could reduce the market's confidence in the Corporation's financial statements and harm the trading price of the Common Shares.



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 non-compliance with the applicable NYSE
Rules; (iii) submit an executed Section 303A annual written affirmation to the NYSE, as well as an Section 303A 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 under NYSE listing standards. AOG has reviewed the
NYSE listing standards followed by U.S. domestic issuers listed under the NYSE 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 and the Corporation’s website at www.advantageog.com.



81







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, 2011.



82







SCHEDULE
"A"



REPORT
OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

(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, 2011, 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 the board of directors 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
of the board of directors of AOG 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.



|(signed)"Andy Mah"                    | (signed) "Kelly I. Drader"
|------------------------------------- | --------------------------
|Andy Mah                              | Kelly I. Drader           
|President and Chief Executive Officer | Chief Financial Officer   
|                                      |                           
|                                      |                           
|(signed) "Ronald A. McIntosh"         | (signed) "John Howard"    
|Ronald A. McIntosh                    | John Howard               
|Director                              | Director                  
|                                      |                           
|March 23, 2012                        |                           











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, 2011. The reserves data are estimates
of proved reserves and probable reserves and related future net revenue as at December 31, 2011, 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 (before deduction of income taxes)
attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of
10 percent, included in the reserves data of the Company and Longview Oil Corp. evaluated by us as of December 31, 2011, 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                 |  |                                                                                    |  | Location of               |  | Net Present Value of Future Net Revenue Before Income Taxes (10% Discount Rate)
|------------------------------------- |  | ---------------------------------------------------------------------------------- |  | ------------------------- |  | -------------------------------------------------------------------------------
|Reserves Evaluator or
        Auditor |  | Description and Preparation Date
        of Evaluation Report                      |  | Reserves
        (County) |  | Audited
        (M$)                                                           
|                                      |  |                                                                                    |  |                           |  |                                                                                
|Sproule Associates Limited            |  | Evaluation of the P&NG Reserves of Advantage Oil & Gas Ltd. and Longview Oil Corp. |  | Canada                    |  |                                                                                
|                                      |  |                                                                                    |  |                           |  |                                                                                
|                                      |  | As of December 31, 2011, prepared                                                  |  |                           |  |                                                                                
|                                      |  | October 2011 to February 2012                                                      |  |                           |  | nil                                                                            
|Total                                 |  |                                                                                    |  |                           |  | nil                                                                            





| | 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, consistently applied. We express no opinion on the reserves data that we
reviewed but did not audit or evaluate.
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| | 7. | Because the reserves data are based on judgements regarding future events, actual results will
vary and the variations may be material.
| | -- | ---------------------------------------------------------------------------------------------------------------------------------------











Executed
as to our report referred to above:



|Sproule Associates Limited | Original Signed by Cameron P. Six, P. Eng.        
|-------------------------- | --------------------------------------------------
|Calgary, Alberta           | Cameron P. Six, P. Eng.                           
|March 9, 2012              | Vice President, Engineering and Partner           
|                           |                                                   
|                           | Original Signed by Lucia M. Precul, P. Eng        
|                           | Lucia M. Precul, P.Eng                            
|                           | Senior Petroleum Engineer and Partner             
|                           |                                                   
|                           | Original Signed by Tanja M. Hale, P. Eng          
|                           | Tanja M. Hale, P. Eng.                            
|                           | Senior Petroleum Engineer and Associate           
|                           |                                                   
|                           | Original Signed by Brent A. Hawkwood, C.E.T..     
|                           | Brent A. Hawkwood, C.E.T.                         
|                           | Senior Petroleum Technologist and Partner         
|                           |                                                   
|                           | Original Signed by Alec Kovaltchouk, P. Geol      
|                           | Alec Kovaltchouk, P. Geol.                        
|                           | Manager, Geoscience and Partner                   
|                           |                                                   
|                           | Original Signed by Harry J. Helwerda, P. Eng., FEC
|                           | Harry J. Helwerda, P. Eng., FEC                   
|                           | Executive Vice-President and Director             





2