Exhibit 1.1

ANNUAL INFORMATION FORM

(Except as otherwise noted the

information herein is given

as at December 31, 2012)

March 21, 2013

TABLE OF CONTENTS

Page

ABBREVIATIONS	1
CONVERSIONS	1
DEFINITIONS	2
GLOSSARY OF TECHNICAL TERMS	4
CURRENCY	7
NOTICE REGARDING PRIOR ESTIMATES OF CONTINGENT RESOURCES	7
FORWARD-LOOKING INFORMATION	7
SHARE CONSOLIDATION	10
SONDE RESOURCES CORP.	10
GENERAL DEVELOPMENT OF THE BUSINESS	12
DESCRIPTION OF THE BUSINESS	14
PRINCIPAL PROPERTIES	15
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	19
RISK FACTORS	31
INDUSTRY CONDITIONS	41
DIVIDENDS	42
DESCRIPTION OF SHARE CAPITAL	42
MARKET FOR SECURITIES	43
PRIOR SALES	43
ESCROWED SECURITIES	43
DIRECTORS AND OFFICERS	44
AUDIT COMMITTEE	46
LEGAL AND REGULATORY PROCEEDINGS	47
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	48
TRANSFER AGENT AND REGISTRAR	48
MATERIAL CONTRACTS	48
INTERESTS OF EXPERTS	48
ADDITIONAL INFORMATION	48
APPENDIX "A"  REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR	A1
APPENDIX "B"  REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE	B1
APPENDIX "C"  CHARTER OF THE AUDIT COMMITTEE OF SONDE RESOURCES CORP.	C1

-i-

ABBREVIATIONS

In this Annual Information Form, the following abbreviations have the meanings set forth below.

Oil, Natural Gas Liquids and Natural Gas
bbl	barrel
Mbbl	thousand barrels
bbl/d	barrel or barrels per day
Mcf	thousand cubic feet
MMcf	million cubic feet
Mcf/d	thousand cubic feet per day
MMcf/d	million cubic feet per day
MMBtu	million British Thermal Units
Other
AECO	a natural gas storage facility located at Suffield, Alberta
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28 °API or higher is generally referred to as light crude oil
BOE	barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 Mcf of natural gas. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf to 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
BOE/d	barrels of oil equivalent per day
m3	cubic metres
MBOE	1,000 barrels of oil equivalent
M$	thousands of dollars
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
3D	three dimensional seismic

CONVERSIONS

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	1,000 m3 of gas	0.028
1,000 m3 of gas	Mcf	35.493
bbl	m3 of oil	0.158
m3 of oil	bbl	6.290
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
GJ	MMBtu	0.950

- 2 -

DEFINITIONS

In this Annual Information Form, the following words and phrases have the meanings specified below, unless the context otherwise requires.

"ABCA" means the Business Corporations Act (Alberta), including the regulations promulgated thereunder, as amended from time to time.

"Board" means the board of directors of the Company.

"Crown Lands" means leases granted by a Canadian Provincial authority.

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook.

"Common Shares" means the common shares in the capital of the Company.

"Company" or "Sonde" means Sonde Resources Corp. and all of its subsidiaries, unless the context otherwise requires.

"EPSA" means the Exploration and Production Sharing Agreement dated August 27, 2008 between the Company and Joint Oil as amended on December 24, 2012.

“Farm-Out Agreement” means the agreement relating to the Farm-Out and carried interest of 66.67% of the Joint Oil Block in offshore North Africa by Viking.

“FirstEnergy” means FirstEnergy Capital Corp, the financial advisor for the Western Canadian Strategic Alternatives Process.

"FPSO" means a floating production storage and offloading vessel which is used by the offshore oil and gas industry for the processing of hydrocarbons and storage of crude oil.

"GLJ" means GLJ Petroleum Consultants Ltd.

"GLJ Report" means the report dated February 19, 2013 prepared by GLJ evaluating the oil, NGL and natural gas reserves attributable to the properties of the Company effective December 31, 2012.

"Joint Oil" means the Joint Exploration, Production, and Petroleum Services Company that is owned equally by the Tunisian government via Enterprise Tunisienne d'Activities Petrolicres and the Libyan government via Libya Oil Holdings.

"Joint Oil Block" means the area covering approximately 310,799 hectares (768,000 acres) located approximately 121 kilometres (75 miles) offshore the Mediterranean Gulf of Gabes as described in and subject to the terms of the EPSA.

"Joint Oil JOA" means the joint operating agreement relating to the Joint Oil Block.

"LNG Project" means the proposed development of a LNG regasification project in U.S. federal waters offshore New Jersey.

"Mariner Block" means the "Mariner" Block, covering approximately 11,246 hectares (27,790 acres) located approximately 9 kilometres (5.6 miles) northeast of Sable Island, offshore Nova Scotia as described in and subject to the terms of the Mariner Exploration License 2409.

"Mariner Swap Agreement" means the "Mariner" Block swap agreement dated August 27, 2008 between the Company and Joint Oil in respect of the Mariner Block.

"MG Block" means the "Mayaro/Guayaguayare" Block, covering approximately 23,522 hectares (58,080 acres) located approximately 6.4 kilometres (4 miles) off the east coast of Trinidad in the Columbus Basin as described in and subject to the terms of the Exploration and Production License.

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

- 3 -

"NI 51-102" means National Instrument 51-102, Continuous Disclosure Obligations.

"Niko" means Niko Resources Ltd.

"Niko Sale Agreement" means the Sale Agreement dated December 21, 2010 between the Company and Niko in respect of the purchase of the Company’s interests in Block 5(c) and the assumption of certain liabilities in respect of the MG Block by Niko.

"NYSE MKT" means NYSE MKT LLC.

"OPEC" means the Organization of the Petroleum Exporting Countries.

"Options" means the options to acquire Common Shares issued under the stock option plan of the Company.

"Preferred Shares" means the preferred shares in the capital of the Company.

"Rights Plan" means the shareholder rights plan of the Company.

"Rights Plan Agreement" means the Shareholder Rights Plan Agreement dated June 3, 2010 between the Company and Valiant Trust Company.

"Sahara" means Canadian Sahara Inc.

"Series A Preferred Shares" means the Series A, 5% U.S. cumulative redeemable preferred shares in the capital of the Company.

"Series B Preferred Shares" means the Series B, 5% U.S. cumulative redeemable preferred shares in the capital of the Company.

"Shareholders" means the holders of Common Shares and "Shareholder" means any one of them.

"TSX" means the Toronto Stock Exchange.

 "UN" means the United Nations.

"Unit plan of development" or "UPOD"means the proposed unit area around the Zarat Field contained partially in the Joint Oil Block and partially in the Zarat license operated by PA Resources.  The proposed UPOD contemplates a cost sharing and division of production with a redetermination after the last development well has been drilled and a further reserve evaluation is performed.  The allocation of costs and production will be adjusted based on the results of the reserve evaluation.

"Update" means the 'Turning the Corner:  Regulatory Framework for Industrial Greenhouse Gas Emissions' paper released by the Government of Canada on March 10, 2008.

"U.S." or "United States" means the United States of America, its territories and possessions, any state of the United States, and the District of Columbia.

“Viking Energy North Africa Limited” or “Viking” means the private company that entered into a Farm-Out Agreement dated December 27, 2012 in which the company farmed out 66.67% of its interest in the Joint Oil Block.

"Viking Farm-Out" means the transfer of an undivided interest in the Company's rights and obligations under the EPSA to Viking, in exchange for cash payments, the assumption of certain drilling and seismic obligations and the granting of a corporate guarantee as a backstop to the Company's obligations under the EPSA.

“Western Canada Strategic Alternatives Process” means the process initiated by the Board to explore and evaluate potential strategic alternatives with regard to the Company’s Western Canadian production and exploratory acreage, with a view to enhancing shareholder value.

- 4 -

"Zarat Field" means a portion of the Joint Oil Block surrounding the Zarat North 1 well, combined with an adjacent license owned by a third party.

GLOSSARY OF TECHNICAL TERMS

In this Annual Information Form, the following technical terms and acronyms have the meanings specified below.

“CGU” means cash generating unit, a property grouping used for financial accounting purposes.

"CBM" means coal based methane.

"crude oil" or "oil" as described in the COGE Handbook means a mixture consisting mainly of pentanes and heavier hydrocarbons that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non-hydrocarbons but does not include liquids obtained from the processing of natural gas.

"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 the 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, to the extent necessary in developing the reserves;

(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 the wellhead assembly;

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

(d) provide improved recovery systems.

"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 certainty.

"development well" means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

"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 (sometimes referred to in part as "prospecting costs") 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 sometimes referred to as "geological and geophysical costs");

- 5 -

(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.

"exploratory well" means a well that is not a development well, a service well or a stratigraphic test well.

"field" means a defined geographical area consisting of one or more pools.

"future net revenue" means the estimated net amount to be received with respect to the development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using constant prices or forecast prices and costs.

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

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

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

“GHG” means greenhouse gas.

"gross" means:

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

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

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

"LNG" means liquefied natural gas.

"natural gas" as described in the COGE Handbook, means a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds.

"natural gas liquids" or "NGL" as described in the COGE Handbook, means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.

"net" means:

(a) in relation to the Company's interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus its royalty interests in production or reserves;

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

(c) in relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company.

"non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.

- 6 -

"operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.

"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.

"production" means the cumulative quantity of petroleum that has been recovered at a given date.

"property" includes:

(a) fee ownership or a lease, concession, agreement, permit, license or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;

(b) royalty interests, production payments payable in oil or gas, and other non-operating interests in properties operated by others; and

(c) an agreement with a foreign government or authority under which the Company participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).

but does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas.

"proved property" means a property or part of a property to which reserves have been specifically attributed.

"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, from a given date forward, based on: (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

"reservoir" means a porous and permeable subsurface rock formation that contains a separate accumulation of petroleum that is confined by impermeable rock or water barriers and is characterized by a single pressure system.

"service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion.

"undeveloped reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., 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, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

"unproved property" means a property or part of a property to which no reserves have been specifically attributed.

- 7 -

"well abandonment costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. They do not include costs of abandoning the gathering system or reclaiming the well site.

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.

CURRENCY

All dollar amounts set forth in this Annual Information Form are expressed in Canadian dollars, except where otherwise indicated. References to Canadian dollars or "$" are to the currency of Canada and references to U.S. dollars or "US$" are to the currency of the United States.

The following table sets forth: (i) the exchange rate in effect at the end of each of the periods indicated; (ii) the average of exchange rates in effect on the first business day of each month during such periods; and (iii) the high and low exchange rates during each such periods, in each case based on the Bank of Canada noon buying rate for one Canadian dollar as expressed in U.S. dollars.

	Year ended December 31
	2012	2011	2010
Rate at end of period	US$1.0051	US$0.9833	US$1.0054
Average rate during period	US$1.0006	US$1.0111	US$0.9674
High	US$0.9618	US$0.9480	US$0.9278
Low	US$1.0327	US$1.0607	US$1.0054

NOTICE REGARDING PRIOR ESTIMATES OF CONTINGENT RESOURCES

Sonde's Annual Information Form for the year ended December 31, 2011 (the "Prior AIF") contained estimates of contingent resources based upon a report prepared by Ryder Scott Company, independent qualified petroleum consultants, effective November 1, 2011 (the "Contingent Resource Report").  The Farm-Out to Viking has provided a new plan of development for the Zarat Field that features a gas recycling plan with four producing wells with subsea tieback to a FPSO vessel.  Produced gas will be re-injected for the first five to seven years allowing for an accelerated development for the oil/condensate.  The original plan of development contemplated for the Zarat Field and forming the basis of the assignment of contingent resources by Ryder Scott Company envisioned the concurrent production of the oil leg and the gas cap using six horizontal producing wells and one water disposal well.  As a result of these changes, the estimates of contingent resources contained in the Contingent Resource Report may change and these changes could be material.  Ryder Scott has not yet completed an updated evaluation of contingent resources to date associated with this new plan of development for the Zarat Field.  Prospective investors should not rely upon the information contained in the Prior AIF with respect to the Contingent Resource Report.

FORWARD-LOOKING INFORMATION

Certain information included in this Annual Information Form and the documents incorporated by reference herein constitutes forward-looking information under applicable securities legislation. Such forward-looking information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking information typically contains statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this Annual Information Form and the documents incorporated by reference herein include, but is not limited to, information with respect to:

· the satisfaction of various conditions relating to the Viking Farm-Out and the closing of the Farm-Out Agreement;

- 8 -

· the proposed unitization of the Zarat Field and development of an amended Zarat Field Unit Plan of Development;

· the results of the Western Canada Strategic Alternatives process and the impact that it may have on sources of funding for future exploration and development activities;

· volume and product mix of the Company's oil and gas production and estimates of future production;

· future oil and gas prices and interest rates;

· future liquidity, creditworthiness and financial capacity;

· volumes and estimated value of the Company's oil and gas reserves;

· planned exploration and development activities;

· future results from operations and operating metrics;

· the life of each of the Company's reserves;

· future interest rates;

· future costs, expenses and royalty rates;

· future development, exploration and other expenditures;

· possible use of derivative financial instruments as part of the Company's commodity risk management programs;

· the amount and timing of future asset retirement obligations;

· the Company's tax pools;

· the Farm-Out Agreement;

· the Company's ability to raise capital and to continually add to reserves through acquisitions, exploration and development;

· the  Company's ability to satisfy certain contractual obligations;

· future economic conditions; and

· the impact of governmental controls, regulations and applicable royalty rates on the Company's operations.

Furthermore, information relating to "reserves" are deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves  described can be recovered and profitable in the future. The assumptions relating to the reserves of the Company are discussed under "Statement of Reserves Data and Other Oil and Gas Information".

Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this Annual Information Form and the documents incorporated by reference herein, assumptions have been made regarding and are implicit in, among other things:

· the satisfaction of the conditions to closing of the Farm-Out Agreement with Viking, including receipt of all governmental approvals;

· the ability to reach agreement on all terms relating to unitization of the Zarat Field and UPOD for the Zarat Field;

· Farm-Out Agreement;

- 9 -

· field production rates and decline rates;

· the ability of the Company to secure adequate product transportation and natural gas processing facilities;

· the impact of increasing competition in or near the Company's properties;

· the timely receipt of any required regulatory approvals and permits;

· access to available sources of capital;

· the ability of the Company to hire and retain qualified management, staff, equipment and services in a timely and cost efficient manner to develop its business;

· the Company's ability to operate the properties in a safe, efficient and effective manner;

· the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration;

· the timing and costs of pipeline, storage and facility construction and expansion;

· future oil and natural gas prices as well as the Western Canadian basis differentials between West Texas Intermediate crude oil prices and Henry Hub natural gas prices in the United States;

· currency, exchange and interest rates;

· the regulatory framework regarding royalties, taxes and environmental matters; and

· the ability of the Company to successfully market its oil and natural gas products.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used.

By its nature, forward-looking information is subject to a number of risks and uncertainties, which could cause actual results or other expectations to differ materially from those anticipated, including those material risks set forth under "Risk Factors" in this Annual Information Form, "Risk Management" in the financial statements of the Company for the year ended December 31, 2012 and "Risk Management" and "Risk Assessment" in the management discussion and analysis of the Company for the year ended December 31, 2012. The Company is exposed to a number of operational risks inherent in exploiting, developing, producing and marketing crude oil and natural gas. These risks include but are not limited to:

· the unsettled and volatile political and security conditions in Tunisia and Libya;

· commercial risks related to the closing, and if closed, the implementation of the Viking Farm-Out;

· the outcome of the Company’s Western Canada Strategic Alternatives Process;

· sufficient liquidity for future operations;

· cost of capital risk to carry out the Company's operations;

· economic risk of finding and producing reserves at a reasonable cost;

· uncertainty of estimates of reserves, production rates, costs and expenses and royalty rates;

· financial risk of marketing oil and natural gas at an acceptable price given market conditions;

· fluctuations in commodity prices, foreign exchange and interest rates;

· operational matters related to non-operated properties;

· delays in business operations, pipeline or facility restrictions, blowouts;

· debt service and indebtedness may affect the market price of the Common Shares;

- 10 -

· the continued availability of adequate debt and equity financing and cash flow to fund planned expenditures;

· unforeseen title defects;

· aboriginal land claims;

· increased competition and the lack of availability of qualified personnel or management or the loss of key personnel;

· ability to attract key personnel;

· uncertainty of government policy changes;

· the risk of carrying out operations with minimal environmental impact;

· operational hazards and availability of insurance;

· industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced;

· general economic, market and business conditions;

· competitive action by other companies;

· the ability of suppliers to meet commitments;

· stock market volatility;

· obtaining required approvals of regulatory authorities; and

· creditworthiness of counterparties.

The forward-looking information contained in this Annual Information Form and the documents incorporated by reference herein are made as of the date of such documents and the Company undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by applicable securities laws. The forward-looking information contained in this Annual Information Form and the documents incorporated by reference herein are expressly qualified by this cautionary statement.

SHARE CONSOLIDATION

On June 3, 2010, the Company consolidated the Common Shares on a five-for-one basis. As such, unless otherwise specifically stated, information contained herein in respect of the Company's share capital which is: (i) as of a date that is prior to June 3, 2010, is presented on a pre-consolidation basis; and (ii) as of a date that is on or after June 3, 2010, is presented on a post-consolidation basis.

SONDE RESOURCES CORP.

General

The Company was incorporated pursuant to the provisions of the ABCA as "297272 Alberta Ltd." on March 21, 1983. Subsequently, the articles of the Company have been amended as follows:

· on April 17, 1993 to change the name of the Company to "KapaIua Gold Mines Ltd." and to remove the private company restrictions;

· on November 16, 1993 to change the name of the Company to "Prize-Energy Inc." and to consolidate the issued and outstanding Common Shares on a one-for-five basis;

· on January 19, 1999 to permit the appointment of additional directors between annual meetings of Shareholders and to restate the articles in a consolidated form;

- 11 -

· on August 24, 2000 to change the name of the Company to "Canadian Superior Energy Inc." and toconsolidate the issued and outstanding Common Shares on a one-for-two basis;

· on January 31, 2006 to add the Series A Preferred Shares to the authorized share capital of the Company;

· on February 3, 2010 to add the Series B Preferred Shares to the authorized share capital of the Company;

· on June 3, 2010 to change the name of the Company to "Sonde Resources Corp." and to consolidate the issued and outstanding Common Shares on a one-for-five basis;  and

· on January 1, 2012 the Company amalgamated with its wholly-owned subsidiaries, Seeker Petroleum Ltd., Sonde Resources Trinidad and Tobago Ltd. and Challenger Energy Corp.

The Company is a reporting issuer, or the equivalent, in the provinces of British Columbia, Alberta, Saskatchewan, Ontario, Quebec, Manitoba, Nova Scotia and Newfoundland. The Common Shares are listed and posted for trading on the TSX and the NYSE MKT under the symbol "SOQ".

The head office of the Company is located at 3200, 500 – 4th Avenue S.W., Calgary, Alberta, T2P 2V6 and its registered office is located at 3700, 400 – 3rd Avenue S.W., Calgary, Alberta, T2P 4H2. In addition, the Company has offices located in Drumheller, Alberta, and Tunis, Tunisia.

Inter-Corporate Relationships

The following diagram sets for the intercorporate relationship among the Company and each of its direct and indirect subsidiaries.  The percentage of votes attaching to all voting securities of the subsidiary beneficially owned, or controlled or directed, directly or indirectly, by the Company as at December 31, 2012, as well as the jurisdiction where the subsidiary was incorporated, continued, formed or organized, as the case may be, is set forth below.

- 12 -

GENERAL DEVELOPMENT OF THE BUSINESS

General

The Company is engaged in the exploration for, and acquisition, development and production of, petroleum and natural gas with operations in Western Canada and North Africa. See "Statement of Reserves Data and Other Oil and Gas Information." The Company also reviews new drilling opportunities and potential acquisitions, both domestic and international, to supplement its exploration and development activities.

Three Year History

The following is a description of the general development of the business of the Company over the last three financial years. For a description of the business of the Company, see "Description of the Business".

2010

On January 19, 2010, the Company completed a private placement of 114,424,238 Common Shares at a price of $0.52 per Common Share for gross proceeds of approximately $59.5 million.

On February 3, 2010, the Company converted the entire issued and outstanding Series A Preferred Shares in the aggregate principal amount of US$15,000,000 owned by West Coast Opportunity Fund, LLC for an equal number of Series B Preferred Shares and 2,500,000 Common Share purchase warrants. Each Common Share purchase warrant entitled the holder to purchase one Common Share until December 31, 2011 at a price of US$0.65 per Common Share.  The Common Share purchase warrants expired unexercised.  For a description of the Series A Preferred Shares and the Series B Preferred Shares, see "Description of Share Capital - Series A Preferred Shares" and "Description of Share Capital - Series B Preferred Shares". For more information with respect to the conversion of the Series A Preferred Shares, see the Material Change Report of the Company dated February 4, 2010, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein.

On July 5, 2010, the Company and Sahara finalized the Joint Oil Block JOA. In addition, the two parties entered into a clarification agreement which, among other matters, gave Sahara until September 15, 2010 to pay its share of costs, plus interest, incurred after April 1, 2010. Sahara's failure to pay its share of costs, plus interest, when due would constitute a default under the terms of the Joint Oil Block JOA.

On September 16, 2010, the Company, as operator under the Joint Oil Block JOA, issued a Notice of Default to Sahara due to Sahara's failure to pay when due its share of joint account expenses associated with the Joint Oil Block. Under the terms of the Joint Oil Block JOA, a formal default period began five business days after issuance of that notice and Sahara had until October 15, 2010, to pay all outstanding joint account expenses associated with its 50% working interest in the Joint Oil Block.

On October 20, 2010, the Company announced that Sahara had failed to cure its default under the Joint Oil Block JOA and that the Company was therefore exercising its option to require that Sahara completely withdraw from the Joint Oil Block, thereby forfeiting its 50% working interest to the Company. In response, Sahara filed for creditor protection under the Bankruptcy and Insolvency Act (Canada), with the intention of making a proposal to its creditors (including the Company).

On November 21, 2010, the Company announced that the Court of Queen's Bench of Alberta had ruled in the Company's favour, dismissing the creditor protection previously afforded Sahara and lifting the stay protecting Sahara. As a result, Sahara was notified that Sonde was exercising its option to require that Sahara completely withdraw from the Joint Oil Block, thereby forfeiting its 50% working interest to the Company.

On December 21, 2010, the Company entered into the Niko Sale Agreement with respect to the purchase of its interests in Block 5(c) by Niko for an aggregate purchase price of US$87.5 million, to be satisfied at closing by the payment of US$75.5 million in cash and the assumption of the Company's US$12.0 million liability under the performance guarantee provided for in the MG Block. A US$20 million debenture was provided by the Company to support the deposit made by Niko in the event that the Niko sale transaction was not completed. BG waived its right of first refusal with respect to Block 5(c) and the MG Block. The

- 13 -

transaction closed on June 23, 2011, and the Company received an additional US$1.5 million in purchase price adjustments. The Company ceased all operations in Trinidad and Tobago and completely exited the country effective September 30, 2011. For additional details refer to the Material Change Report of the Company dated December 29, 2010, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein.

In December 2010, the Mariner Exploration License expired. As a result, Joint Oil had the right to put back and sell the overriding royalty relating to the Mariner Block to the Company for US$12.5 million. This right, which was granted pursuant to the Mariner Swap Agreement, was exercised by Joint Oil in August 2011. The Company made a payment of US$12.5 million on January 15, 2012. Prior to the payment, the Company obtained confirmation from Joint Oil that the EPSA was in full force and effect.

2011

On January 11, 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North -1 well on the Joint Oil Block. The well has been temporarily abandoned while the Company evaluates the recoverable reserve scenarios, development options (including unitization) and cost estimates for the field's development.

On February 24, 2011, the Company announced that it had sold its subsidiary, Liberty Natural Gas LLC, which owned a 100% working interest in the LNG Project to an entity related to West Face Capital Inc. for US$1.0 million and an entitlement to receive a deferred cash consideration of US$12.5 million payable upon Liberty Natural Gas LLC's first successful gas delivery. The sale had an effective date of February 22, 2011.

On June 8, 2011, the Company declared Force Majeure on the Joint Oil Block because of UN sanctions adopted by the UN Security Council and Canada that prevented the Company from fulfilling its obligations under the EPSA.

On June 23, 2011, the Company completed the sale of its interests in Block 5(c) and the assumption of certain liabilities in respect of the MG Block through the Niko Sale Agreement for gross proceeds of US$75.5 million plus purchase price adjustments of US$1.5 million.

On September 23, 2011, the Company completed the acquisition of a block of producing and non-producing assets in Drumheller from a third party, which included the bulk of the producing interests in the Mannville “I” oil pool not previously owned by the Company, for an aggregate purchase price of $6.3 million.

On October 5, 2011, the Company lifted the Force Majeure declaration on the Joint Oil Block as a result of the Government of Canada and the United Nations repealing their unilateral sanctions against Libya on September 22, 2011.

On December 30, 2011, the Company redeemed all 150,000 outstanding Series “B” Preferred Shares for an aggregate amount of US$15,186,987.

2012

On January 1, 2012, the Company amalgamated Seeker Petroleum Ltd., Challenger Energy Corp. and Sonde Resources Trinidad and Tobago Ltd. into Sonde Resources Corp.

On January 15, 2012, the Company received a one year extension on the first phase of the exploration period on the Joint Oil Block until December 23, 2013. In addition, Sonde paid to Joint Oil US$12.5 million pursuant to the Mariner Swap Agreement.

On January 30, 2012, the Company announced that it had begun an initiative to identify and evaluate alternatives to finance its remaining North Africa obligations.  These initiatives resulted in the execution of the Farm-Out Agreement with Viking in December 2012.

On February 8, 2012, the Company completed the sale of 26,240 gross undeveloped acres (24,383 net acres) in its Kaybob Duvernay play in Alberta for aggregate proceeds of $75 million.  The sale resulted in a net gain of approximately $73 million.

- 14 -

On December 5, 2012, the Company announced it reached agreement to extend the three exploratory well drilling obligation into the second phase of the exploration period under the EPSA subject to final approval by Joint Oil, as well as principles relating to the UPOD with PA Resources. On December 24, 2012, Joint Oil’s Board and General Assembly approved the agreement to extend the three exploratory well drilling obligation into the second phase of the exploration under the EPSA.

On December 27, 2012, the Company announced the execution of the Viking Farm-Out Agreement.  The Viking Farm-Out is outlined in detail under the section Principal Properties – Offshore North Africa and the Material Change Report of the Company dated January 4, 2013, a copy of which is available on SEDAR at www.sedar.com and is incorporated by reference herein. As of the date hereof, this transaction has not closed.

On January 9, 2013, Sonde announced that it had retained FirstEnergy to initiate a process to explore and evaluate potential strategic alternatives to enhance shareholder value with regard to Sonde’s Western Canadian production and exploratory acreage. As financial advisor to the Board, FirstEnergy will assist in the process of analyzing and evaluating prospects and options available to the Company, which may include, among other alternatives, a sale of all or a material portion of the Western Canadian assets of the Company, a strategic investment in Sonde’s undeveloped acreage, a joint venture, or a merger or other business combination involving Sonde. The Board has established a Special Committee comprised of independent directors to oversee the strategic review process.

Significant Acquisitions

The Company did not complete any significant acquisitions during the year ended December 31, 2012 for which disclosure was required under Part 8 of NI 51-102.

DESCRIPTION OF THE BUSINESS

General

The Company is engaged in the exploration for, and acquisition, development and production of, petroleum and natural gas with operations in Western Canada and North Africa. See "Statement of Reserves Data and Other Oil and Gas Information." The Company also reviews new drilling opportunities and potential acquisitions, both domestic and international, to supplement its exploration and development activities.

Competitive Conditions

The oil and natural gas industry is intensely competitive in all its phases. The Company competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties, in accessing equipment, services and personnel to exploit and develop oil and natural gas properties,in the marketing of oil and natural gas and in attracting and retaining experienced industry personnel. The Company's competitors include resource companies which have greater financial resources, staff and facilities than those of the Company. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. The Company believes that its competitive position is equivalent to that of other oil and gas issuers of similar size and at a similar stage of development. See "Risk Factors - Competition".

Cycles

The development of oil and gas reserves is dependent on access to areas where exploration and production is to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances, which can impact the timing of drilling and maintenance activities and production.

Environmental Protection

The oil and gas industry is subject to environmental regulations pursuant to applicable legislation. Such legislation provides for restrictions and prohibitions on release or emission of various substances produced in

- 15 -

association with certain oil and gas industry operations, and requires that well and facility sites be abandoned and reclaimed to the satisfaction of environmental authorities. As at December 31, 2012, the Company had recorded an obligation on its statement of financial position of $30.0 million for the costs of decommissioning its oil and gas assets. The Company maintains an insurance program consistent with industry practice to protect against losses due to accidental destruction of assets, well blowouts, pollution and other operating accidents or disruptions. The Company also has operational and emergency response procedures and safety and environmental programs in place to reduce potential loss exposure. No assurance can be given that the application of environmental laws to the business and operations of the Company will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect the Company's financial condition, results of operations or prospects. See "Risk Factors – Environmental Risks" and "Industry Conditions".

Employees

The Company has a total of 26 full-time employees and consultants in the Calgary office, with eight employees in its Drumheller, Alberta office, one consultant in its Tunis office and one employee in Houston.

Foreign Operations

In addition to its Canadian operations, the Company is engaged in the exploration for oil and natural gas in offshore North Africa. International oil and gas operations are subject to inherent risks and uncertainties which are beyond the control of the Company, particularly those associated with exploring for, and developing, economic quantities of hydrocarbons, volatile commodity prices, political risks, foreign exchange rates, issues relating to global supply and demand, government regulations, and environmental matters. The Company's international exploration ventures may entail certain political and technical business risks. The Company's strategy is to mitigate such risks by aligning itself with partners and engaging personnel and consultants that have international experience. See "Risk Factors - Foreign Political and Security Issues", "Risk Factors - Foreign Operations", "Risk Factors - Foreign Legal Systems" and "Risk Factors - Foreign Currency Rates".

Social or Environmental Policies

The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to the Company. To this end, the Company has instituted health and safety policies and programs and endeavors to conduct its operations in a manner that will minimize both adverse effects and consequences of emergency situations by:

· complying with government regulations and standards, particularly relating to the environment, health and safety;

· conducting operations consistent with industry codes, practices and guidelines;

· ensuring prompt, effective response and repair to emergency situations and environmental incidents;

· providing training to employees and contractors to ensure compliance with corporate safety and environmental rules and procedures; and

· communicating openly with members of the public regarding its activities.

The Company believes that all employees and contractors have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved.

PRINCIPAL PROPERTIES

A summary description of the Company's major producing and exploration properties is set out below. References to gross volumes refer to total production. References to net volumes refer to the Company's working interest share before the deduction of royalties payable to others.

- 16 -

Western Canada

The Company derives all of its production and cash flow from operations in Western Canada. The Company’s Western Canadian oil and gas assets are primarily high working interest properties that are geographically concentrated in southern and west-central Alberta, the most significant being the Company’s Southern CGU (or Greater Drumheller, Alberta area), which accounts for approximately 85% of the Company’s production.  The balance of production largely comes from the Kaybob/Windfall and Boundary Lake/Eaglesham areas in west-central Alberta.

At December 31, 2012, the Company held 464,657 gross / 353,842 net acres in Western Canada the majority of which is operated by the Company.

 On January 9, 2013, Sonde announced that it had retained FirstEnergy to initiate a process to explore and evaluate potential strategic alternatives to enhance shareholder value with regard to Sonde's Western Canadian production and exploration properties.  As financial advisor to the Board, FirstEnergy is assisting in the process of analyzing and evaluating prospects and options available to the Company, which may include, among other alternatives, a sale of all or a material portion of the Western Canadian assets of the Company, a strategic investment in Sonde's undeveloped acreage, a joint venture or a merger or other business combination involving Sonde.  The Board has established a Special Committee comprised of independent directors to oversee the strategic review process.

Southern CGU

Drumheller

The greater Drumheller area encompasses Sonde’s interests from Townships 27 to 34, Range 11 to 21W4 and is inclusive of the Drumheller, West Drumheller, Watts, Rich, Richdale, Michichi, Stanmore, Wildunn Creek, Delia, Craigmyle, Coyote, Chain and Aerial fields or areas. The area includes 192,322 gross acres (128,955 net acres) of relatively consolidated land positions, both operated and non-operated and with varying working interests. Undeveloped land within the area totals 65,254 gross acres (52,303 net acres). The majority of oil production within the area is derived from the Mannville ‘I’ Pool in Township 29, Range 19W4 and the Michichi Pool in Township 31, Range 17W4. This pool has well established production with an operational waterflood pilot with expansion planned along with infill drilling. Additional oil contribution comes from Detrital, Banff and Nisku formations. Sonde has identified a Detrital/Banff horizontal play with promising results to date. Gas production from the Property is attributed to shallow gas and horseshoe canyon CBM as well as various larger targets within the Mannville, Glauconitic and Ellerslie formations. These plays remain a key theme going forward with the low cost workover, recompletions and drilling opportunities targeting these plays going a long ways towards maintaining base production.

Drumheller Mannville ‘I’ Pool

The Drumheller Mannville ‘I’ Pool is located in Township 29, Range 19W4 with Sonde owning 100% working interest in the production. The productive Ellerslie sand is an entrenched valley fill / estuarine deposit with major depositional channels oriented NE-SW. Reservoir-quality sand is truncated by erosion or non-deposition to the north and south, forming the trap for the pool. Several generations of channels exist, and younger channels truncate older ones, but pay is effectively top to base and no free water levels have been observed in the pool. However, local fluctuations in water saturation are common as it relates to significant changes in relative permeability of the reservoir to oil from place to place within the overall pool.  The reservoir is fine to medium grained sandstone with net pay-bearing sand ranging between 4 and 18 metres across the pool (net sand defined by utilizing a 40 API gamma ray or less cut-off).

Michichi Detrital/Banff

Sonde’s Michichi Detrital/Banff area is located in Township 31, Range 17W4 with the Company owning Detrital and Banff rights across a prospective portion of its contiguous, high working interest land position. The Detrital and Banff within this area are both oil-charged, and commonly co-produce in the same section and/or wellbore. The Basal Cretaceous Detrital sandstone is an entrenched valley fill deposit with major depositional channels oriented northeast-southwest and east-west, while the Upper Banff is a limestone deposit with porosity and permeability enhanced on the top and flank of erosional remnants on

- 17 -

the channel margins.  Detrital net reservoir-quality sand ranges from 2 to 16 metres on Sonde working interest land. The Banff carbonate is a karsted limestone stratigraphically trapped by shales deposited on margins of erosional highs. It is relatively tight rock at 3 to 9% porosity, but natural fractures generally provide productivity where a modest amount of porosity exists.  The Detrital structure in the area is monoclinal dip to the west with no structural closure. Reservoir-quality sand is truncated by non-deposition on the channel margins, and by erosion to the northeast and south-southwest, forming a series of individual stratigraphic traps within the greater Michichi area. The significant stratigraphic variability across the area limited initial vertical developments and is conducive to horizontal drilling which is capable of reducing this reservoir risk.  Historical vertical Banff/Detrital production from the area exhibits very low declines, emphasized by a period of production from 1994 through to 2003 demonstrating very flat production with limited activity suggesting a large resource in-place. Recently, operators including have initiated a new growth phase in the area with the drilling of horizontal wells targeting the underdeveloped Detrital and Banff.

Central CGU

Kaybob/Windfall

The Central CGU includes the Fox Creek, Windfall and Sheldon properties that have associated production and reserves, several non-producing properties and a substantial amount of undeveloped Montney and Duvernay mineral rights. The majority of reserves volumes and associated values for the central CGU are attributed to the Fox Creek and Windfall properties. In November 2012, production in this area was attributed to eleven wells, including eight Sonde operated and three non-operated wells, with production derived primarily from the Gething and Notikewin zones. Due to low natural gas prices, several gas events and wells are currently shut in. Sonde intends to return these to production when prices improve. Opportunities assigned by GLJ are low risk, low cost development operations, while Sonde has identified additional opportunities including horizontal Montney and Duvernay oil locations and Gething gas locations.

Northern CGU

Boundary Lake/Eaglesham

The Northern CGU is situated between Townships 76 and 92, Ranges 8W5 and 12W6 and includes the Eaglesham/Cindy, Grande Prairie, Red Earth and Doig properties and substantial undeveloped Wabamun rights in Eaglesham/Cindy property that are prospective for light oil development with horizontal wells. In November 2012, the Northern CGU had working interest sales of 126 Boe/d, consisting of 374 Mcf/d of natural gas, 60 bbl/d of light oil and 5 bbl/d of NGL’s, ascribed to eight wells. Production is primarily attributed to the Grande Prairie and Eaglesham/ Cindy properties, with production mainly from the Charlie Lake and Boundary Lake intervals in Grande Prairie and the Wabamun in Eaglesham/Cindy. The majority of reserves volumes and associated values are attributed to the Grande Prairie property, although the majority of long term upside is associated with the  Eaglesham/ Cindy property. Sonde believes that due to the presence of natural fracturing, Wabamun horizontal development wells may not require hydraulic fracturing or other stimulation procedures, thereby significantly reducing completion costs. The Company has developed an infill drilling scenario based on utilizing two to four wells per section, that if successful would potentially accommodate 162 to 324 horizontal locations. Opportunities assigned by GLJ include two low risk development operations. Sonde has working interests in a small number of facilities and pipelines in the area.

British Columbia CGU and Other

There are a small number of properties, stand-alone wells and land agreements that fall outside of the boundaries of the Southern, Central and Northern cash generating units. Properties include Northern British Columbia and Peace River Block British Columbia, while southern Saskatchewan hosts a concentration of undeveloped land. Sonde has working interests in 34,002 gross acres (10,943 net acres) of land within the Northern and Peace River Block British Columbia properties, with the majority of land, including most of the 30,853 gross acres (9,927 net acres) of undeveloped land associated with the Northern British Columbia property. Neither property currently has production.  As at December 31, 2012 the GLJ Report assigned 136

- 18 -

MBOE of proved plus pprobable reserves to these properties with a before tax 10% net present value of $51,000. This reflects two 37.5% working interest, non-operated wells assigned proved non-producing reserves that have been shut in due to low gas prices. The Northern British Columbia property is for Slave Point gas, while the Peace River Block opportunity is for Halfway gas. Both are scheduled to be returned to production in 2015.

International

Offshore North Africa (Tunisia and Libya)

The Company acquired the Exploration and Production Sharing Agreement for the 768,000 acre Joint Oil Block, offshore Tunisia and Libya, on August 27, 2008.

On December 24, 2012, Joint Oil approved the extension of the first phase of the exploration period pursuant to the EPSA to December 23, 2015. The extension provides for penalties for non-fulfillment of the minimum work program of US$15.0 million for each of the three exploratory wells, due December 23, 2013, December 23, 2014, and December 23, 2015, respectively.  In addition, the extension provides for the acquisition and processing of 200 square kilometres of 3D seismic covering the sub-contract area “B” (Libyan) of the Joint Oil Block, beginning in the second quarter of 2013.

On December 27, 2012, the Company entered into a Farm-Out Agreement with Viking Energy North Africa Limited (“Viking”) covering the Joint Oil Block. The Farm-Out Agreement includes the following terms:

· Viking will pay Sonde in total a US$3.0 million non-refundable signature bonus.  As at December 31, 2012, US$1.0 million of the signature bonus had been received by the Company, with the remaining US$2.0 million due upon closing;

· Viking will assume responsibility for the three well exploration commitment under the terms of the EPSA and fund 100% of the Joint Oil Block share of the Unit Plan of Development for the Zarat Field. The first well, Fisal, is to be drilled in 2013 along with the acquisition of seismic data covering the area around the Hadaf prospect in Libyan waters;

· Viking will provide to Sonde, prior to closing, the appropriate form of corporate guarantee with the agreed upon commercial terms, in order to secure the remaining work commitment under the terms of the EPSA;

· Sonde will receive 20% of the cost recovery and profit share revenue until Sonde recovers US$70 million. After payout of all of Viking's expenditures, the revenue will be split 33.33% to Sonde and 66.67% to Viking;

· Sonde retains the option, at its sole election, to fund its 33.33% share of the last two of the exploration wells; and

· Any future discoveries will be shared 33.33% to Sonde and 66.67% to Viking.

This farm out is subject to the following conditions precedent:

· Viking (or one of its affiliates) provides Sonde with a corporate guarantee sufficient to offset the current US$45.0 million guarantee for the potential penalties in respect of the three well drilling commitment and seismic obligation under the EPSA; and

· Joint Oil consents to the transfer of the interest to Viking as a second party to the EPSA and the naming of Viking as operator of the Joint Oil Block under the EPSA.

The Company has submitted the farm-out to Joint Oil for approval. The Company and Viking have met with Joint Oil on numerous occasions and Joint Oil has raised a number of conditions to approval that the Company and Viking are attempting to resolve. While the Company believes the farm-out should be approved on its merits alone, no assurance can be made that Joint Oil will approve it or that the farm-out will close. The farm-out can be terminated after March 31, 2013 unless agreed by mutual consent to extend.

- 19 -

Zarat Field Plan of Development

Viking and Sonde are preparing an amended Zarat Field Unit Plan of Development to Joint Oil. This Unit Plan of Development utilizes an FPSO  vessel  and encompasses the following key principles:

· Unit crude oil production is anticipated to begin in 2015 at approximately 38,000 barrels of oil per day;

· Projected design (three or four producing wells with subsea tieback to FPSO) achieves potentially 80% of the performance of original fixed structure development plan developed by Sonde and dramatically reduces front end capital expenditures;

· Produced gas will be re-injected for the first 5-7 years, allowing for an accelerated development timeline for the hydrocarbon liquids;

· Design will allow for immediate tie-in of Fisal prospect (exploratory well to be drilled in 2013), if proven productive, further enhancing its economics of development;

· Design will allow for future pipeline tie-in and production of the gas cap after the Inert and Acid Gas Initiative is implemented.

The Zarat North-1 well, which was the appraisal well for the Zarat Field and unit, was temporarily abandoned on January 11, 2011. This well was the third well drilled on the large Zarat anticlinal feature, following two wells drilled by Marathon in 1992 and 1994, respectively.  The Zarat North-1 well encountered 240 net feet of gas/condensate and oil pay in the Eocene El Gueria limestone, with oil/water and gas/oil contacts at the same structural elevation found in the Marathon wells. Tested in three separate intervals, the Zarat North-1 flowed at sustained rates averaging 8 MMcf/d of natural gas plus 750 bbl/d of condensate. The Zarat Unit Plan of Development is under evaluation as part of the Viking Farm-Out discussed above.

The Company filed a Plan of Development with Joint Oil for the development of the Zarat field. The Company expected Joint Oil to approve the plan of development expediently so that the Company could demonstrate to the market an asset with an approved Exploitation Plan. However, Joint Oil deferred approval of the Company's Plan of Development pending negotiations with the other license holder and Enterprise Tunisienne d'Activities Petrolicres (ETAP) on Unitization and a Unit Plan of Development for Zarat, which will in the Company's opinion be heavily dependent on the outcome of the inert and acid gases initiative described above. As a result, the Company expected approval of its Zarat Plan of Development to be delayed for the foreseeable future.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

GLJ prepared the GLJ Report in accordance with NI 51-101 and the COGE Handbook. The GLJ Report evaluated, as at December 31, 2012, the oil, NGL and natural gas reserves attributable to the properties of the Company. All of the Company's reserves are located in the Canadian provinces of Alberta and British Columbia. No reserves have been attributed to the Joint Oil Block in North Africa.

The tables below are summaries of the oil, NGL and natural gas reserves of the Company and the net present value of future net revenue attributable to such reserves as summarized in the GLJ Report based on forecast price and cost assumptions. The tables summarize the data contained in the GLJ Report and as a result may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to the Company's reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures and well abandonment costs for only those wells assigned reserves by GLJ. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Company's reserves estimated by GLJ represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Company's oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

The values shown for income taxes and future net revenue after income taxes were calculated on a stand-alone basis in the GLJ Report. The values shown may not be representative of future income tax obligations, applicable tax horizon or after tax valuation.

The GLJ Report is based on certain factual data supplied by the Company and GLJ's opinions of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to the Company's properties and contracts (except for certain information residing in the public domain)

- 20 -

were supplied by the Company to GLJ and accepted without any further investigation. GLJ accepted this data as presented and neither title searches nor field inspections were conducted.

Summary of Oil and Gas Reserves

	Gross Reserves			Net Reserves
	Light and Medium Crude Oil	NGLs	Natural Gas	Light and Medium Crude Oil	NGLs	Natural Gas
Reserve Category	Mbbl	Mbbl	MMcf	Mbbl	Mbbl	MMcf
Proved
Developed Producing	977	323	16,605	878	220	14,847
Developed Non-Producing	4	68	3,810	3	47	3,264
Undeveloped	0	0	1,753	0	0	1,652
Total Proved	981	390	22,168	881	267	19,763
Probable	1,912	223	13,384	1,628	153	11,887
Total Proved Plus Probable	2,893	613	35,553	2,509	420	31,650

Summary of Net Present Value of Future Net Revenue

	Before Future Income Tax Expenses and Discounted at (%/year)
	0%	5%	10%	15%	20%
Reserve Category	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	80,775	63,320	52,800	45,657	40,434
Developed Non-Producing	8,040	5,590	4,208	3,321	2,701
Undeveloped	2,901	1,746	1,091	707	475
Total Proved	91,716	70,656	58,099	49,685	43,610
Probable	126,685	77,402	51,026	35,073	24,710
Total Proved Plus Probable	218,400	148,058	109,125	84,758	68,320

- 21 -

	After Future Income Tax Expenses and Discounted at (%/year)
	0%	5%	10%	15%	20%
Reserve Category	(M$)	(M$)	(M$)	(M$)	(M$)
Proved
Developed Producing	80,775	63,320	52,800	45,657	40,434
Developed Non-Producing	8,040	5,590	4,208	3,321	2,701
Undeveloped	2,901	1,746	1,091	707	475
Total Proved	91,716	70,656	58,099	49,685	43,610
Probable	126,684	77,402	51,026	35,073	24,710
Total Proved Plus Probable	218,400	148,058	109,125	84,758	68,320

Total Future Net Revenue (Undiscounted)

	Revenue	Royalties	Operating Costs	Development Costs	Abandonment and Reclamation Costs	Future Net Revenue Before Future Income Tax Expenses	Future Income Tax Expenses	Future Net Revenue After Future Income Taxes Expenses
Reserve Category	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)	(M$)
Total Proved	224,346	26,502	95,986	3,875	6,268	91,716	-	91,716
Total Proved Plus Probable	502,861	65,438	188,678	22,654	7,691	218,400	-	218,400

Future Net Revenue By Production Group

	Future Net Revenue Before Future Income Tax Expenses and Discounted at 10%/year(3)	Unit Value Before Future Income Tax Expenses and Discounted at 10%/year
Reserve Category and Product Group	(M$)	($/BOE)
Total Proved
Light and Medium Crude Oil (1)	29,793	25.79
Associated Gas and Non-Associated Gas (2)	27,769	9.35
Non-Conventional Oil and Gas Activities (CBM)	538	1.69
Total	58,099	13.08
Total Proved Plus Probable
Light and Medium Crude Oil (1)	68,525	21.36

- 22 -

	Future Net Revenue Before Future Income Tax Expenses and Discounted at 10%/year(3)	Unit Value Before Future Income Tax Expenses and Discounted at 10%/year
Reserve Category and Product Group	(M$)	($/BOE)

Associated Gas and Non-Associated Gas (2)	38,974	9.03
Non-Conventional Oil and Gas Activities (CBM)	1,626	2.39
Total	109,125	13.30

Notes:

(1)  Including solution gas and other by-products

(2)  Including by-products but excluding solution gas

(3)  Other company revenue and costs not related to a specific production group have been allocated proportionately to production groups.  Unit values are based on Company Net Reserves.

Summary of Pricing, Exchange Rate and Inflation Rate Assumptions

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2012 in estimating the Company's reserves data, using forecast prices and costs.

												Alberta NGLs
		Bank of Canada Average Noon Ex-change Rate	NYMEX WTI Near Month Futures Contract Crude Oil at Cushing Oklahoma	BRENT Blend Near Month Futures Contract Crude Oil FOB North Sea	Light Sweet Crude Oil (40 API, 0.3%S) at Edmonton	Bow River Crude Oil Stream Quality at Hardisty	Lloyd Blend Crude Oil Stream Quality at Hardisty	WCS Crude Oil Stream Quality at Hardisty	Heavy Crude Oil Proxy (12 API) at Hardisty	Light Crude Oil (35 API, 1.2 %S) at Cromer	Medium Crude Oil (29 API, 2.0%S) at Cromer	Spec Ethane	Edmonton Propane	Edmonton Butane	Edmonton Pentanes Plus
Year	Infla- tion %	$US/$	$US/bbl	$US/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl	$/bbl
2013	2	1.00	90.00	105.00	85.00	71.63	69.93	70.13	60.92	83.30	79.90	11.09	34.06	65.45	96.63
2014	2	1.00	92.50	102.50	91.50	77.77	75.94	76.15	68.36	87.84	84.18	12.65	45.75	70.46	97.91
2015	2	1.00	95.00	102.50	94.00	79.90	78.02	78.22	71.10	90.24	86.48	14.20	56.40	72.38	97.76
2016	2	1.00	97.50	102.50	96.50	82.03	80.09	80.29	73.02	92.64	88.78	15.75	57.90	74.31	100.36
2017	2	1.00	97.50	100.00	96.50	82.03	80.09	80.29	73.02	92.64	88.78	16.53	57.90	74.31	100.36
2018	2	1.00	97.50	100.00	96.50	82.03	80.09	80.29	73.02	92.64	88.78	17.46	57.90	74.31	100.36
2019	2	1.00	98.54	101.35	97.54	82.91	80.96	81.16	73.81	93.64	89.74	17.81	58.52	75.11	101.44
2020	2	1.00	100.51	103.38	99.51	84.58	82.59	82.79	75.32	95.53	91.55	18.18	59.71	76.62	103.49
2021	2	1.00	102.52	105.45	101.52	86.29	84.26	84.46	76.87	97.46	93.40	18.55	60.91	78.17	105.58
2022	2	1.00	104.57	107.55	103.57	88.03	85.96	86.16	78.44	99.43	95.28	18.92	62.14	79.75	107.71
2023+	2	1.00	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr

- 23 -

Year				Alberta Plant Gate				Saskatchewan Plant Gate			British Columbia
	Henry Hub NYMEX Near Month Contract	Midwest Price at Chicago	AECO/NIT Spot	Spot 2013 $	Spot Then current 2013 $	ARP	Alliance	Sask Energy	Spot	Sumas Spot	Westcoast Station 2	Spot Plant Gate	Sulphur FOB Vancouver	Alberta Sulphur at Plant Gate
	$US/ MMBtu	$US/ MMBtu	$/ MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$/MMBtu	$US/LT	$/LT
2013	3.75	3.85	3.38	3.19	3.19	3.12	2.55	3.22	3.30	3.60	3.18	3.00	175.00	132.00
2014	4.25	4.35	3.83	3.56	3.63	3.56	3.03	3.66	3.74	4.10	3.63	3.45	150.00	107.00
2015	4.75	4.85	4.28	3.92	4.08	4.00	3.51	4.10	4.20	4.60	4.08	3.90	125.00	82.00
2016	5.25	5.35	4.72	4.27	4.53	4.44	3.99	4.54	4.64	5.10	4.52	4.34	125.00	82.00
2017	5.50	5.60	4.95	4.39	4.75	4.66	4.23	4.76	4.87	5.35	4.75	4.57	127.50	84.50
2018	5.80	5.90	5.22	4.55	5.02	4.92	4.52	5.02	5.14	5.65	5.02	4.83	130.05	87.05
2019	5.91	6.01	5.32	4.54	5.12	5.01	4.62	5.11	5.24	5.76	5.12	4.93	132.65	89.65
2020	6.03	6.13	5.43	4.55	5.22	5.12	4.74	5.22	5.35	5.88	5.23	5.04	135.30	92.30
2021	6.15	6.25	5.54	4.55	5.33	5.22	4.85	5.32	5.46	6.00	5.34	5.15	138.01	95.01
2022	6.27	6.37	5.64	4.55	5.44	5.33	4.97	5.43	5.56	6.12	5.44	5.25	140.77	97.77
2023+	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr

Notes:

(1)  Unless otherwise stated, the gas price reference point is the receipt point on the applicable provincial gas transmission system known as the plant gate.

(2)   The plant gate price represents the price before raw gas gathering and processing charges are deducted.

The weighted average realized sales prices by the Company for the year ended December 31, 2012 was $2.51/Mcf for natural gas, $76.62/bbl for light and medium crude oil and $58.38/bbl for NGLs. All figures are exclusive of royalties and transportation but include realized hedging gains and losses.

Reconciliation of Company's Gross Reserves by Product Type

The following table sets forth the changes the Company's reserve volume estimates made as at December 31, 2012 and the corresponding estimates as at December 31, 2011, using forecast prices and costs.

- 24 -

	Light and Medium Crude Oil			CBM			Conventional Natural Gas			NGLs			Total Oil Equivalent
	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable	Gross Proved	Gross Probable	Gross Proved Plus Probable
Factors	(Mbbl)	(Mbbl)	(Mbbl)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(MMcf)	(Mbbl)	(Mbbl)	(Mbbl)	(MBOE)	(MBOE)	(MBOE)
Dec. 31, 2011	1,084	899	1,983	3,221	2,709	5,930	25,071	10,517	35,588	416	189	605	6,215	3,292	9,507
Extensions and Improved Recovery	112	1,052	1,164	--	--	--	310	1,127	1,438	6	22	27	169	1,262	1,431
Technical Revisions	(13)	(39)	(51)	(1,013)	(325)	(1,339)	(1,926)	(644)	(2,570)	40	12	52	(462)	(188)	(650)
Discoveries	--	--	--	--	--	--	--	--	--	--	--	--	--	--	--
Acquisitions	--	--	--	--	--	--	--	--	--	--	--	--	--	--	--
Dispositions	--	--	--	--	--	--	--	--	--	--	--	--	--	--	--
Economic Factors	--	--	--	--	--	--	--	--	--	--	--	--	--	--	--
Production	(203)	--	(203)	(149)	--	(149)	(3,346)	--	(3,346)	(71)	--	(71)	(856)	--	(856)
Dec. 31, 2012	981	1,912	2,893	2,059	2,384	4,442	20,110	11,001	31,110	390	223	613	5,066	4,366	9,432

Proved Undeveloped Reserves

The following table sets forth the volumes of proved undeveloped reserves that were first attributed for each of the Company's product types for each of the most recent three financial years and, in the aggregate, before that time, using forecast prices and costs.

Financial Year End	Light and Medium Crude Oil		Natural Gas		NGLs
	First Attributed (Mbbl)	Cumulative at Year End(1) (Mbbl)	First Attributed (MMcf)	Cumulative at Year End(1) (MMcf)	First Attributed (Mbbl)	Cumulative at Year End(1) (Mbbl)
Prior to December 31, 2010	9	9	4,321	4,321	1	1
December 31, 2010	--	10	219	4,170	3	3
December 31, 2011	--	--	--	2,823	--	--
December 31, 2012	--	--	--	1,753	--	--

Note:

(1) Cumulative at year end is cumulative of previous year plus first attributed, less developed during the year.

Proved undeveloped reserves are generally those reserves related to planned infill drilling locations. The Company's proved undeveloped reserves are forecasted to be developed during the next two years.  The timing of development of the Company's proved undeveloped reserves is dependent upon a number of factors, including forecast commodity prices for the determination of economic projects.

Probable Undeveloped Reserves

The following table sets forth the volumes of probable undeveloped reserves that were first attributed for each of the Company's product types for each of the most recent three financial years and, in the aggregate, before that time, using forecast prices and costs.

- 25 -

Financial Year End	Light and Medium Crude Oil		Natural Gas		NGLs
	First Attributed (Mbbl)	Cumulative at Year End(1) (Mbbl)	First Attributed (MMcf)	Cumulative at Year End(1) (MMcf)	First Attributed (Mbbl)	Cumulative at Year End(1) (Mbbl)
Prior to December 31, 2010	536	536	5,328	5,328	10	10
December 31, 2010	--	458	65	4,751	1	9
December 31, 2011	--	549	--	3,368	--	9
December 31, 2012	1,590	1,590	2,218	4,510	36	36

Note:

(1) Cumulative at year end is cumulative of previous year plus first attributed, less developed during the year.

Probable undeveloped reserves relate to wells to be drilled, tied in and brought on-stream in future. The Company's probable undeveloped reserves are forecasted to be developed during the following two to four years in accordance with the Company's development program and budget.  The timing of development of the Company's probable undeveloped reserves is dependent upon a number of factors, including forecast commodity prices for the determination of economic projects.

Significant Factors and Uncertainties Affecting Reserves Data

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.

As circumstances change and additional data becomes 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, prices, economic conditions and governmental restrictions.  In addition, reserve estimates may change based on actual production performance of development schemes which have previously only been assessed based on simulations and/or pilot projects, such as the Company's Mannville "I" pool waterflood.

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.

Future Development Costs

The following table sets forth the development costs deducted in the estimation in the GLJ Report of future net revenue attributable to proved reserves and proved plus probable reserves, using forecast prices and costs.

- 26 -

	Total Proved	Total Proved Plus Probable
Year	(M$)	(M$)
2013	--	13,867
2014	538	2,784
2015	755	1,116
2016	21	21
2017	--	--
2018	2,227	4,514
Remaining Years	333	350
Total for all years undiscounted	3,875	22,654

Future development costs are associated with the reserves evaluated by GLJ in the GLJ Report and do not necessarily represent the Company's exploration and development budget.  The Company expects to fund its future development costs from internally generated cash flow from operations, debt (where deemed appropriate) and new equity issues (if available on favourable terms). In addition, the Company may consider Farm-Out arrangements for certain projects. The Company does not expect that the cost of funding will make the development of a property uneconomic for the Company, nor is it expected that the cost of such funding will impact the Company's reserves or future net revenue.

Oil and Gas Wells

The following table sets forth the number and status of wells in which the Company has a working interest as at December 31, 2012.

Location	Light and Medium Crude Oil				Natural Gas
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
British Columbia	-	-	-	-	-	-	13.0	6.4
Alberta	94.0	79.9	57.0	43.0	274.0	138.3	151.0	109.2
Saskatchewan	-	-	-	-	-	-	5.0	5.0
Total	94.0	79.9	57.0	43.0	274.0	138.3	169.0	120.6

Properties With No Attributed Reserves

The following table summarizes the undeveloped gross and net acres of properties with no attributed reserves in which the Company has an interest and also the number of net acres for which the Company's rights to explore, develop or exploit will, absent further action, expire within one year.

Location	Gross Acres	Net Acres	Net Acres Expiring Within One Year
Southern CGU	202,002	135,392	0
Central CGU	153,985	141,272	0
Northern CGU	68,611	60,180	0
Other CGU	40,057	16,998	679
Offshore North Africa (1)	768,000	768,000	0
Total	1,232,655	1,121,842	679

Note:

(1) Net acres will reduce by 66.67% upon completion of the Viking Farm-Out.

- 27 -

The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15 million per exploration well plus a contractual commitment to start the acquisition of 200 square kilometers of 3D seismic in sub-contract area B (Libya) by the second quarter 2013. As at December 31, 2012, the estimated cost of drilling the three remaining exploration wells to satisfy the remaining work commitments on the Joint Oil Block, Offshore Tunisia and Libya, was US$100 million to the Company with the potential for costs to exceed this amount.  If the Viking Farm-Out is completed, this obligation will be assumed by Viking.

Significant Factors or Uncertainties Relevant to Properties With No Attributed Reserves

Due to low product prices for natural gas, Sonde has elected to defer new drilling for most natural gas prospects in 2013. The Company has also assessed the economics of all wells and, to the extent permitted, shut-in uneconomic wells.

Following the sale of 26,240 gross undeveloped acres in the Kaybob Duvernay in our Central CGU for $75 million in February 2012, Sonde has an extensive inventory of opportunities, of which only a portion have had reserves assigned by GLJ.  In our GLJ report are opportunities include 12 drilling locations and 42 well operations that include reactivations, completions and tie-ins. All drilling opportunities are associated with the Southern CGU and comprise four probable horizontal Detrital locations and four proved undeveloped and four probable undeveloped CBM locations. Of the 42 well operations, 22 are attributed to the Southern CGU, with 16 associated with the Central CGU, two to the Northern CGU and two to the other areas. Expenditures are planned for waterflood facilities and water injector conversions in the Drumheller Mannville ‘I’ Pool and pipeline implementation and water disposal in the Ante Creek area in the Central CGU.  Complementing these opportunities, the Company has identified over 100 horizontal Montney oil locations, over 500 Duvernay oil locations and 13 horizontal Gething gas locations within the Central CGU. Within the Northern CGU, Sonde has identified up to 324 horizontal Wabamun oil infill locations, while the Company has compiled an inventory of up to 18 horizontal Detrital locations within the Southern CGU. The Company intends to finance any future residual Western Canada capital expenditures after the strategic alternatives review to the extent it can, with existing cash flow, and proceeds from the strategic alternatives.

Forward Contracts

The Company may periodically enter into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility. These financial instruments are to be entered into solely for hedging purposes and are not used for trading or other speculative purposes. As of December 31, 2012, the Company had not entered into any of these types of contracts.

Additional Information Concerning Abandonment and Reclamation Costs

The Company typically estimates abandonment and reclamation costs for surface leases, wells, facilities and pipelines, as applicable, on an area by area basis.  Well abandonment costs for wells where reserves have been assigned by GLJ are included in the GLJ Report as deductions in arriving at future net revenue.

The expected total abandonment and disconnect costs, net of salvage value, included in the GLJ Report for 226 wells under the proved reserves category is $7.7 million undiscounted ($3.2 million discounted at 10%), of which a total of $0.7 million undiscounted is estimated to be incurred in 2013, 2014 and 2015. This estimate does not include remediation or reclamation of surface leases and abandonment costs for wells and facilities without reserves.  The Company has recorded an asset retirement obligation of $30.0 million which includes the abandonment of 25 wells, over the next three years.  The Company's net abandonment and reclamation cost is expected to be $1.5 million ($1.0 million discounted at 10%) during the next three financial years.

The Company is liable for its share of ongoing environmental obligations and for the ultimate reclamation of the properties held by it upon abandonment. Ongoing environmental obligations are expected to be funded out of cash flow.

- 28 -

Costs Incurred

The following table summarizes capital expenditures (including capitalized general and administrative expenses) incurred by the Company for the year ended December 31, 2012:

Property Acquisition Costs		Exploration Costs	Development Costs
Proved Properties	Unproved Properties
(M$)	(M$)	(M$)	(M$)
0	6,088	4,630	26,663

Tax Horizon

Based on production from existing reserves, the Company estimates that it will not be required to pay income taxes in 2013 or 2014 and with continued exploration activity, the tax horizon could be pushed further.

Exploration and Drilling Activity

During the twelve months ended December 31, 2012, Sonde drilled and fracked three of the five originally planned short radius horizontal oil wells in Michichi. The three wells were completed using a diesel-based frac during the third quarter of 2013 and were subsequently tied in. During the twelve months ended December 31, 2012, Sonde drilled and completed its initial Montney oil well, the 4-19-67-25W5, in Ante Creek North. An extended test confirmed the previously announced short-term production data, with high water cuts (~95%) throughout the production period. The well is capable of approximately 120 BOE/d hydrocarbon production; however, it provides insufficient production to support the required pipeline and processing infrastructure on its own. If Sonde can prove an extension to this pool with follow-up drilling, the 4-19 can be tied-in as part of a future development plan.

Sonde continued its well re-activation program concentrated on an extensive portfolio of suspended wells. Sonde performed 77 net work overs and recompletions in the twelve months ended December 31, 2012.

Sonde has tested the previously announced waterflood play in the Drumheller Mannville “I” pool. Sonde is very encouraged by the test results, and the play has contributed significantly to the Company’s  46% year over year (2011 to 2012) increase in oil reserves.

The following table summarizes the Company's participation and net interest in wells drilled in Canada during the year ended December 31, 2012.  No wells were drilled in North Africa.

	Gas		Oil		Service		Dry and Abandoned		TOTAL
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Exploration Development	-- --	-- --	1.0 3.0	1.0 3.0	-- --	-- --	-- --	-- --	1.0 3.0	1.0 3.0
TOTAL	--	--	4.0	4.0	--	--	--	--	4.0	4.0

Production Estimates

The following tables sets forth for each product type the total volume of production estimated by GLJ in the GLJ Report for 2013 as reflected in the estimates of gross proved reserves and gross probable reserves and gross proved plus probable reserves as disclosed above.

- 29 -

Reserve Category - CGU	Light and Medium Crude Oil	Natural Gas	NGLs	Total Oil Equivalent
	(bbl/d)	(Mcf/d)	(bbl/d)	(BOE/d)
Proved
Northern Alberta	55	502	3	142
Southern Alberta	435	6,439	116	1,624
Central Alberta	47	808	18	199
British Columbia	0	0	0	0
Total	537	7,748	137	1,965
Probable
Northern Alberta	2	33	0	8
Southern Alberta	82	241	4	127
Central Alberta	4	41	1	12
British Columbia	0	0	0	0
Total	88	315	5	146
Total Proved Plus Probable
Northern Alberta	57	535	3	149
Southern Alberta	517	6,679	120	1,750
Central Alberta	50	849	19	211
British Columbia	0	0	0	0
Total	624	8,063	142	2,111

Production Volume by Cash Generating Unit

The following table indicates the Company’s average daily production by CGU for the year ended December 31, 2012.

CGU	Light and Medium Crude Oil	Natural Gas	NGLs	Total Oil Equivalent	%
	(bbl/d)	(Mcf/d)	(bbl/d)	(BOE/d)
Northern Alberta	51	628	6	162	7
Southern Alberta	438	8,070	168	1,950	82
Central Alberta	65	977	28	256	11
British Columbia	0	50	0	8	-
Total	554	9,725	202	2,376	100

Production History

The following table sets forth, on a quarterly basis for the year ended December 31, 2012, certain information in respect of production, product prices received, royalties paid, operating expenses and resulting netback.

- 30 -

	Three Months Ended
	March 31, 2012	June 30, 2012	September 30, 2012	December 31, 2012
Average Daily Production Volume
Light and Medium Oil (bbl/d)	565	554	523	573
NGL (bbl/d)	255	191	203	189
Natural Gas (Mcf/d)	11,553	9,665	8,758	8,940
Total (BOE/d)	2,746	2,356	2,155	2,252
Average Prices Received
Light and Medium Oil ($/bbl)	90.84	67.60	77.09	72.69
NGL ($/bbl)	61.86	61.08	52.24	56.35
Natural Gas ($/Mcf)	2.20	2.10	2.36	3.50
Total ($/BOE)	33.73	29.45	32.46	37.14
Royalties Paid
Light and Medium Oil ($/bbl)	15.90	12.81	11.22	10.74
NGL ($/bbl)	21.26	20.03	20.27	19.08
Natural Gas ($/Mcf)	0.02	(0.35)	(0.25)	(0.16)
Total ($/BOE)	4.72	3.18	3.32	3.67
Production Costs
Light and Medium Oil and NGLs ($/bbl)	16.73	19.17	18.73	22.44
Natural Gas ($/Mcf)	3.10	3.54	3.27	3.92
Total ($/BOE)	17.26	19.75	19.33	23.13
Transportation Costs
Light and Medium Oil and NGLs ($/bbl)	0.76	0.53	0.70	0.95
Natural Gas ($/Mcf)	0.13	0.10	0.16	0.16
Total ($/BOE)	0.78	0.56	0.73	0.67
Netback Received(1)
Light and Medium Oil and NGLs ($/bbl)	46.76	31.56	38.05	32.44
Natural Gas ($/Mcf)	(1.05)	(1.89)	(0.78)	(0.33)
Total ($/BOE)	10.97	5.96	9.10	9.67

Note:

(1) Netback is calculated by subtracting royalties, transportation and operating costs from revenues.

- 31 -

RISK FACTORS

An investment in Common Shares is subject to certain risks. Investors should carefully consider the risk factors set out below and consider all other information contained herein and in the Company's other public filings. In order to mitigate these risks, the Company has qualified technical and financial personnel, with experience in the areas of Canada and North Africa. Further, the Company has focused its foreign operations, and plans to target future operations, in known and prospective hydrocarbon basins in jurisdictions that have previously established long-term oil and gas ventures with oil and gas companies. Additional risks and uncertainties not currently known to the management of the Company may also have an adverse effect on the Company's business, prospects, financial condition, results of operations, cash flows or the trading prices of its securitiesand the information set out below does not purport to be an exhaustive summary of all risks affecting the Company.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future and the Company has significant work commitments in connection with the EPSA in North Africa. If the Company's revenues or reserves decline, it may limit the Company's ability to expend or access the capital necessary to undertake or complete future drilling programs and meet commitments. 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 Company. The inability of the Company to access sufficient capital for its operations, including the closing and implementation of the Viking Farm-Out which will reduce the Company's capital commitments, could have a material adverse effect on the Company's financial condition, results of operations or prospects.  The Company's financial statements contain a "going concern" note based on the uncertainty of closing the Viking Farm-Out, developments involving the Company's inability to meet its three exploratory well obligation in respect of the Joint Oil Block, unitization with and plan of development on the Zarat Field, drilling rig availability and an initiative on inert and acid gas sequestration.     

Additional financial information with respect to the foregoing is provided in the Company's financial statements and management discussion and analysis for the year ended December 31, 2012, copies of which are available on SEDAR at www.sedar.com.

North Africa

On December 24, 2012, Joint Oil approved the extension of the first phase of the exploration period under the EPSA to December 23, 2015. The extension provides for penalties for non-fulfillment of the minimum work program of US$15.0 million for each of the three exploratory wells, due December 23, 2013, December 23, 2014, and December 23, 2015, respectively.  In addition, the extension provides for the acquisition and processing of 200 square kilometres of 3D seismic covering the sub-contract area “B” (Libyan) of the Joint Oil Block, beginning in the second quarter of 2013.

On December 27, 2012, the Company entered into the Farm-Out Agreement with Viking covering the Joint Oil Block. Completion of the Viking Farm-Out is subject to a number of conditions precedent which are outside of the control of the Company, including the approval of Joint Oil to the transfer of the interest to Viking as party to the EPSA and the appointment of Viking as operator of the Joint Oil Block under the EPSA.  As of the date hereof, the Farm-Out Agreement has not closed and no assurance can be provided as to the timing for completion of this transaction.

In addition the Company must unitize the discovered Zarat Field with the license holder on the southern border of the Joint Oil Block.  Negotiations are underway but the outcome is uncertain at this time. A plan of development submitted on the Joint Oil Block must be approved by Joint Oil and the license holders to the south and could delay the Zarat Field UPOD. The political stability of Tunisia and Libya remains in question, which may affect the Company’s activities on the Joint Oil Block.

- 32 -

Western Canada Strategic Process

The Company has retained FirstEnergy to pursue a process to explore and evaluate potential strategic alternatives to enhance shareholder value with regard to the Company's Western Canadian producing and exploratory properties.  There can be no assurance that this process will result in a sale of all or any of the Company's Western Canadian assets or that a strategic investment, joint venture or business combination will be identified or consummated on terms acceptable to the Company or at all.

Capital Markets

The market events and conditions witnessed over the past three financial years, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility in commodity prices and increases in the rates at which the Company is able to borrow funds for its capital programs. While there have been recent signs which may suggest the beginning of a global economic recovery, there can be no certainty regarding the timing or extent of a potential recovery, and such continued uncertainty in the global economic situation means that the Company, along with all other oil and gas entities, may continue to face restricted access to capital and increased borrowing costs. This could have an adverse effect on the Company, as its ability to make future capital expenditures is dependent on, among other factors, the overall state of the capital markets and investor appetite for investments in the energy industry generally and the Company's securities in particular.

Additional Funding Requirements

The Company's cash flow from its producing reserves is not currently and may not be sufficient to fund its ongoing activities at all times. From time to time, the Company may require additional financing in order to carry out its acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Company's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Company's ability to expend the necessary capital to replace its reserves or to maintain its production. If the Company's cash flow from operations is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available on favorable terms.

Issuance of Debt

From time to time the Company may enter into transactions to acquire assets or the shares of other corporations. These transactions may be financed partially or wholly with debt, which may increase the Company's debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, the Company may require additional debt financing that may not be available or, if available, may not be available on favorable terms. Neither the articles of the Company nor its by-laws limit the amount of indebtedness that the Company may incur. The level of the Company's indebtedness from time to time, could impair its ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.   This in turn, could have a material adverse effect on the Company's business, financial condition, results of operations and cash flow.

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 Company 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 Company 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 Company'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 Company will be able to continue to locate

- 33 -

satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, management of the Company 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 Company.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, availability of drilling rigs, support equipment, 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 hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury. In particular, the Company 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 Company. In accordance with industry practice, the Company is not fully insured against all of these risks, nor are all such risks insurable. Although the Company maintains liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event the Company could incur significant costs that could have a material adverse effect upon its financial condition. 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 could have a material adverse effect on the Company.

Operational Dependence

Other companies operate some of the assets in which the Company has an interest. As a result, the Company will have limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Company's financial performance. The Company's return on assets operated by others will therefore depend upon a number of factors that may be outside of the Company'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.

Project Risks

The Company 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 Company's ability to execute projects and market oil and natural gas will depend upon numerous factors beyond the Company's control, including:

· the availability of drilling and related equipment;

· the availability of processing capacity;

· the availability and proximity of pipeline capacity;

· the availability of storage capacity;

- 34 -

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

· the availability of alternative fuel sources;

· the effects of inclement weather;

· unexpected cost increases;

· accidental events;

· currency fluctuations;

· changes in regulations;

· the availability and productivity of skilled labor in Canada and North Africa; and

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

Because of these factors, the Company may 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.

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.  The availability of specialized drilling equipment, such as offshore drilling rigs, can be more limited, requiring longer lead times to secure.  Demand for such limited equipment or access restrictions may affect the availability of such equipment to the Company and may delay exploration and development activities or involve greater costs to secure such equipment.  To the extent the Company is not the operator of its oil and gas properties, the Company will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators.

Prices, Markets and Marketing of Crude Oil and Natural Gas

The marketability and price of oil and natural gas that may be acquired or discovered by the Company is and will continue to be affected by numerous factors beyond its control. The Company's ability to market its oil and natural gas may depend upon its ability to contract capacity on pipelines that deliver natural gas to commercial markets. The Company 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 Company's revenues, profitability and future growth and the carrying value of its oil and gas properties are substantially dependent on prevailing prices of oil and gas. The Company's ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include economic conditions, in the United States, Canada, and North Africa, the actions of the OPEC and Russia, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternative fuel sources. Any substantial and extended decline in the price of oil and gas would have an adverse effect on the Company's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations.

Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have

- 35 -

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

Pipeline and Processing Capacity

Although pipeline and facility expansions are ongoing, the lack of firm pipeline and natural gas processing capacity, together with interruptions in pipeline and processing service, continues to affect the oil and natural gas industry and potentially limit the ability to produce and market natural gas production.

Insurance

The Company's involvement in the exploration for and development of oil and natural gas properties may result in the Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although prior to conducting drilling and other field activities, the Company will obtain insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, the Company 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 such uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Company's financial position, results of operations or prospects.

Hydraulic Fracturing

Concern has been expressed over the potential environmental impact of hydraulic fracturing operations, including water aquifer contamination, other qualitative and quantitative effects on water resources as large quantities of water are used, and injected fluids either remain underground or flow back to the surface to be collected, treated and disposed of. Regulatory authorities in certain jurisdictions have announced initiatives in response to such concerns.  Federal, provincial and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs, additional operating restrictions or delays, and adversely affect the Company’s production and results of operations. Public perception of environmental risks associated with hydraulic fracturing can further increase pressure to adopt new laws or permitting requirements or lead to regulatory delays, legal proceedings and/or reputational impacts. Any new laws, or permitting requirements regarding hydraulic fracturing could lead to operational delay, increased operating costs, and third-party or governmental claims. This could also increase the Company’s cost of compliance and doing business as well as delay the development of hydrocarbon (natural gas and oil) resources from shale formations, which may not be commercial without use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves.

In the event federal, provincial, local, or municipal legal restrictions are adopted in areas where the Company is currently conducting, or in the future plans to conduct operations, the Company may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. In addition, if hydraulic fracturing becomes subject to increased regulation, the Company’s fracturing activities could become subject to additional permitting requirements and result in permitting delays as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves.

- 36 -

Legal Proceedings

The Company may from time to time be subject to litigation and regulatory proceedings arising in the normal course of its business. The Company cannot determine whether such litigation and regulatory proceedings will, individually or collectively, have a material adverse effect on its business, results of operations or financial condition. To the extent expenses incurred in connection with litigation or any potential regulatory proceeding or action (which may include substantial fees of lawyers and other professional advisors and potential obligations to indemnify officers and directors who may be parties to such actions) are not covered by available insurance, such expenses could adversely affect the Company's cash position.

Environmental Risks

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 international conventions and international, national, provincial, state and local law and regulation. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and 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 same can result in the imposition of clean-up orders, fines and/or penalties, some of which may be material, as well as possible forfeiture of requisite regulatory approvals obtained from the various governmental authorities. The discharge of GHG emissions and other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the Company believes that it is 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 adversely affect its financial condition, results of operations or prospects. See "Industry Conditions".

Canadian Tax Considerations

As the Company is engaged in the oil and natural gas business its operations are subject to certain unique provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation relating to characterization of costs incurred in their businesses which effects whether such costs are deductible and, if deductible, the rate at which they may be deducted for the purposes of calculating taxable income. The Company has reviewed its historical income tax returns with respect to the characterization of the costs incurred in the oil and natural gas business as well as other matters generally applicable to all corporations including the ability to offset future income against prior year losses. The Company has filed or will file all required income tax returns and believes that it is in full compliance with the provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation, but such returns are subject to reassessment. In the event of a successful reassessment of the Company it may be subject to a higher than expected past or future income tax liability as well as potentially interest and penalties and such amount could be material.

Foreign Operations

International operations in North Africa are subject to political, economic and other uncertainties, including, among others: risk of war, risk of terrorist activities, revolution, border disputes, sanctions by other governments that limit or prevent certain actions, expropriation, renegotiations or modification of existing contracts, freezing of bank accounts and other assets, restrictions on repatriation of funds, import, export and transportation regulations and tariffs, taxation policies including royalty and tax increases and retroactive tax claims, exchange controls, limits on allowable levels of production, currency fluctuations, labor disputes, sudden changes in laws, government control over domestic oil and gas pricing, and other uncertainties arising out of foreign government sovereignty over the Company's international operations.  See Risk Factors – North Africa.

The Company's international operations may also be adversely affected by laws and policies of Canada, the United States and other jurisdictions affecting foreign trade, taxation and investment.  For example, the Company may be at a disadvantage in that it may compete against companies or other entities from countries that are not subject to Canadian laws and regulations, including the Corruption of Foreign Public

- 37 -

Officials Act (or similar legislation of other jurisdictions).  Residents of nationals or countries not subject to such legal regimes may offer inducements to foreign governments and foreign public officials to entice such governments and officials to deal with them to the disadvantage of the Company.

Furthermore international oil and gas operations in offshore North Africa involve substantial costs and are subject to certain risks owing to the underdeveloped nature of the oil and gas industry in Libya and Tunisia. The oil and gas industry in Libya and Tunisia is not as developed as the oil and gas industry in Canada. As a result, drilling and development operations may take longer to complete and may cost more than similar operations in Canada. The availability of technical expertise, specific equipment and supplies is more limited in various countries than in Canada and the United States. Such factors may subject oil and gas operations in other countries to economic and operating risks not experienced in Canada.

Foreign Legal Systems

Tunisia and Libya have less developed legal systems than in Canada which may result in risks such as: (i) effective legal redress in the courts of such jurisdictions, whether in respect of a breach of law or regulation, or, in an ownership dispute, being difficult to obtain; (ii) a higher degree of discretion on the part of governmental authorities; (iii) the lack of judicial or administrative guidance on interpreting applicable rules and regulations; (iv) inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions; or (v) relative inexperience of the judiciary and courts in such matters. In certain jurisdictions the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licenses and agreements for business. These may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. There can be no assurance that joint ventures, licenses, license applications or other legal arrangements will not be adversely affected by the actions of government authorities and the effectiveness of and enforcement of such arrangements in these jurisdictions cannot be assured.

Foreign Currency Rates

A significant amount of the Company's activities are transacted in or referenced to the currencies of the United States and Tunisia. The Company's revenues, operating costs and certain of its payments in order to maintain property interests are to be in the local currency of the jurisdiction where the applicable property is located. As a result, fluctuations in the currencies of the United States and Tunisia against the Canadian dollar, and each of those currencies against currencies in jurisdictions where properties of the Company are located, could result in unanticipated fluctuations in the Company's financial results which are denominated in Canadian dollars. The Company does not currently manage its exposure to fluctuations in currency exchange rates.

Competition

The Company actively competes for reserve acquisitions, exploration leases, licences and concessions, development properties, production and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than the Company. The Company's competitors include major integrated oil and natural gas companies, state owned oil and gas companies and numerous other independent oil and natural gas companies and individual producers and operators. Competition may also be presented by alternate energy sources.

Certain of the Company's customers and potential customers are themselves exploring for oil and gas, and the results of such exploration efforts could affect the Company's ability to sell or supply oil or gas to these customers in the future. The Company's ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with its future industry partners and joint operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

- 38 -

Reserve Replacement

The Company's future oil and natural gas reserves, production, and cash flows to be derived therefrom are highly dependent on the Company successfully acquiring or discovering new reserves. Existing reserves and production will decline over time without the continual addition of new reserves. A future increase in the Company's reserves will depend not only on the Company's ability to develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or develop or acquire prospects. There can be no assurance that the Company's future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas.

Reliance on Industry Partners

In order to carry out certain of its business and operations, the Company relies on its industry partners (certain of which include suppliers, contractors and joint venture parties and operators). Accordingly, the Company is exposed to third party risk. Should such industry partners fail to fulfill those duties and obligations each owes to the Company, such failure could have a material adverse effect on the Company's business and/or operations.

Reliance on Key Employees

The Company's success depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on the Company. The Company does not have key person insurance in effect for management. The contributions of these individuals to the Company's immediate operations 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 Company 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 Company's management.

Permits, Licences and Approvals

The Company's properties are held in the form of licences and leases and working interests in licences and leases. If the Company 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 Company's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on its results of operations and business.

Royalties, Incentives and Production Taxes

In addition to federal regulations, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown Lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time, the Governments of Canada, Alberta and British Columbia have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects.  There can be no assurance that, if implemented, these incentive programs will be continued.

Land Tenure

Crude oil and natural gas located in the Canadian western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and

- 39 -

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.

Title to Properties

Although title reviews may be conducted prior to the purchase of 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 Company's claim which could result in a reduction of the revenue received by the Company.

Reserve Information

There are numerous uncertainties inherent in estimating quantities of reserves and future net revenues to be derived therefrom, including many factors beyond the control of the Company.  The reserve and future net revenue information contained in the GLJ Report are only estimates and the actual production and ultimate recoverable reserves from the Company's properties and future net revenues may be greater or less than the estimates prepared in such report.  Evaluations of reserves and future net revenues depend on a number of variable factors and assumptions, including the following:

· historical production from the area compared with production from other producing areas;

· the assumed effects of regulations by governmental agencies;

· the quality, quantity and interpretation of available relevant data;

· assumptions concerning commodity prices; and

· assumptions regarding future operation costs, development costs, abandonment costs and taxes.

The GLJ Report has been prepared using certain commodity price assumptions which are described in the notes to the reserve tables. If lower prices for crude oil, natural gas liquids and natural gas are realized by the Company and substituted for the price assumptions utilized in the report, the present value of estimated future net cash flows for the Company's reserves would be reduced and the reduction could be significant.  Similarly, decreased production or increases in operating costs and development costs would reduce the estimated future net revenues set forth in the GLJ Report.  The present value of estimated future net revenues referred to herein should not be considered as the fair market value of estimated reserves attributable to the Company’s properties.  Exploration for oil and natural gas involves many risks, which even a combination of experience and careful evaluation may not be able to overcome. There is no assurance that further commercial quantities of oil and natural gas will be discovered by the Company.

Dilutive Effect of Financings and Acquisitions

The Company may make future acquisitions or enter into financing or other transactions involving the issuance of securities of the Company which may be dilutive to its current shareholders.

Dividends

The Company has not paid any dividends on its outstanding Common Shares nor is expected to in the near future.

Volatile Trading Price

The trading price of the Common Shares is subject to substantial volatility often based on factors related and unrelated to our financial performance or prospects.  Factors unrelated to the Company's financial performance could include macroeconomic developments nationally, within North America or globally; domestic and global commodity prices or current perceptions of the oil and gas market.  Similarly the market price of the Common Shares could be subject to significant fluctuations in response to the Company’s operating results, financial condition, liquidity and other internal factors.  Factors that could

- 40 -

affect the market price of the Common Shares that are unrelated to performance include domestic and global commodity prices and the market perceptions of attractiveness of particular industries.  The price which the Common Shares will trade cannot be accurately predicted.

Third Party Credit Risk

The Company 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 Company, such failures could have a material adverse effect on the Company and its cash flow from operations. 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 Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

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

Hedging

Historically the Company has entered into commodity price contracts and the Company may enter into such contracts in the future.  As of December 31, 2012, all contracts have expired.  Similarly, from time to time the Company 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 Company will not benefit from the fluctuating exchange rate.

Aboriginal Claims

The Canadian First Nations have made rights and title claims to a significant portion of Western Canada. At present the Company is unable to assess what, if any, impact such claims will have on the business and operations that it conducts in Western Canada.

Conflict of Interest

Certain of the directors and officers of the Company are also directors and officers of other oil and gas companies involved in natural resource exploration and development, and conflicts of interest may arise between their duties as officers and directors of the Company and as officers and directors of such other companies. Such conflicts must be disclosed in accordance with, and are subject to such other procedures and remedies as apply under the ABCA.

- 41 -

INDUSTRY CONDITIONS

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

Canadian Government Regulations

Over the last several years, the federal Government has undertaken a number of initiatives to achieve domestic GHG reductions.  These measures include regulations, codes and standards, targeted investments, incentives, tax measures and programs that directly reduce GHG emissions.

Going forward, the Government has announced that it will focus on a sector-by-sector regulatory approach, beginning with the largest sources of emissions.  Given the high degree of economic integration between Canada and the U.S., Canada has stated that it will be aligned with future U.S. emissions reduction regulations where it is appropriate and in Canada's best interests to do so.  This regulatory agenda will continue to be supported by targeted complementary measures designed to advance Canada's transition to a clean energy economy.

Under Canada's plan to address climate change, actions have been taken regarding two of the largest sources of GHG emissions:  the electricity and transportation sectors.  The oil sands industry is expected to be a sector of the economy where the federal Government will next regulate GHG emissions.

There has been much public debate surrounding Canada's ability to meet emission reduction targets and the strategies proposed for controlling climate change and GHG emissions. It is likely that any such strategies which are eventually adopted by the Canadian government will materially impact the nature of oil and gas operations, including those carried out by the Company. At present, it is not possible to predict the impact such strategies will have on the business, operations and/or finances of the Company.

Alberta

Environmental legislation in the Province of Alberta has largely been consolidated into the Environmental Protection and Enhancement Act (Alberta), the Water Act (Alberta) and the Oil and Gas Conservation Act (Alberta). These statutes impose environmental standards, require compliance, reporting and monitoring obligations, and impose penalties. In addition, the emissions reduction requirements in the Climate Change and Emissions Management Act (Alberta) came into effect on July 1, 2007. Under this legislation, Alberta facilities emitting more than 50,000 tonnes of GHG emissions per year must report such emission to Alberta Environment and Sustainable Resource Development and to Environment Canada while facilities emitting more than 100,000 tonnes of GHG emissions per year must reduce their emissions intensity by 12 percent. The Company has four options to choose from in order to meet the reduction requirements outlined in this legislation, and these are: making improvement to operations that result in reductions; purchasing emission credits from other sectors or facilities that have reduced their emissions below the required emission intensity reduction levels; purchasing off-set credits from other sectors or facilities that have emissions below the 100,000 tonne threshold and are voluntarily reducing their emissions in Alberta; or contributing to the 'Climate Change and Emissions Management Fund'. The Company can choose one of these options or a combination thereof, however it should be noted that the price of off-set credits could be raised, and the required reductions in GHG emissions intensity presently set forth could be increased to unspecified levels.

- 42 -

In January of 2008 Alberta introduced its Climate Change Strategy which includes three broad themes: (i) conserving and using energy efficiently; (ii) implementing carbon capture and storage; and (iii) greening energy production. Under the Climate Change Strategy, Alberta has indicated its intention to meet the following emission reduction targets: a 20 megatonne reduction by 2010, a 50 megatonne reduction by 2020 and a 200 megatonne reduction by 2050, all while maintaining economic growth. In furtherance of this Climate Change Strategy, the Government of Alberta has begun enacting legislation including the 2009 Carbon Capture and Storage Funding Act and the 2010 Carbon Capture and Storage Statutes Amendment Act.

DIVIDENDS

The Company has not declared or paid any dividends on the Common Shares since incorporation. It is not currently expected that dividends will be paid in respect of the Common Shares during the current phase of development of the Company's business and operations. The payment of dividends in the future will be at the discretion of the Board and will be dependent on the future earnings and financial condition of the Company and such other factors as the Board considers appropriate.

Dividends of US$0.9 million (US $6 per Series B Preferred Share) and US$1.0 million (US $6.67 per Series B Preferred Share) were paid by the Company in each of the years ended December 31, 2010 and 2011, respectively, to various holders of the Series B Preferred Shares. The Series B Preferred was redeemed on December 31, 2011.

DESCRIPTION OF SHARE CAPITAL

The Company's authorized share capital consists of an unlimited number of Common Shares and an unlimited number of Preferred Shares, issuable in series. As of the date hereof, 62.3 million Common Shares and no Preferred Shares are issued and outstanding .

Common Shares

The holders of Common Shares are entitled to notice of and to vote at all meetings of Shareholders (except meetings at which only holders of a specified class or series of shares are entitled to vote) and are entitled to one vote per Common Share. The holders of Common Shares are entitled to receive such dividends as the Board may declare and, upon liquidation, to receive such assets of the Company as are distributable to holders of Common Shares.

Preferred Shares

The Preferred Shares may be issued in one or more series with each series to consist of such number of shares as may, before the issue of the series, be fixed by the Board.  The Board is authorized, before the issue of the series, to determine the designation, rights, restrictions, conditions and limitations attaching to the Preferred Shares of each series.  The Preferred Shares of each series rank equally with respect to the payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up and in priority to the Common Shares and any other shares of the Company ranking junior to the Preferred Shares.  In addition, if any amount of a fixed cumulative dividend or an amount payable on return of capital in respect of shares of a series of Preferred Shares is not paid in full, the shares of the series are entitled to participate rateably with the shares of any other series of the same class in respect of such amounts.

The Series A Preferred Shares were converted to Series B Preferred Shares on February 3, 2010.  On December 30, 2011, the Company redeemed the 150,000 Series B Preferred Shares previously outstanding.  No Preferred Shares are currently issued and outstanding.

Rights Plan

The Company adopted the Rights Plan in accordance with the Rights Plan Agreement. Pursuant to the terms of the Rights Plan Agreement, the Rights Plan will expire on the date that the annual meeting of Shareholders to be held in 2013 terminates unless re-approved by the Shareholders.  The Company intends to seek a renewal of the Rights Plan for an additional three years. For more information with respect to the

- 43 -

Rights Plan, see the Information Circular of the Company relating to the 2013 annual and special meeting of Shareholders and the Rights Plan Agreement, copies of which are or will be available on SEDAR at www.sedar.com and are incorporated by reference herein.

MARKET FOR SECURITIES

The Common Shares are listed and posted for trading on the TSX and the NYSE MKT under the symbol "SOQ". The following table sets forth the price ranges and volume of Common Shares traded as reported by the TSX for the periods indicated.

2012	High ($)	Low ($)	Close ($)	Volume
January	3.00	2.41	2.59	768,970
February	3.02	2.35	2.38	3,017,540
March	2.55	2.19	2.44	884,153
April	2.44	1.87	2.35	3,728,641
May	2.32	1.78	1.93	2,290,270
June	2.04	1.52	1.79	1,883,250
July	1.84	1.51	1.72	619,694
August	1.69	0.90	0.99	2,468,251
September	0.99	0.63	0.75	2,285,850
October	0.95	0.72	0.94	3,355,044
November	1.02	0.80	1.02	307,264
December	1.79	0.95	1.63	7,152,314

PRIOR SALES

During the year ended December 31, 2012, a total of 2,504,000 Options, being the only unlisted securities of the Company that were issued, were granted are as follows:

Date of Grant	Number of Options	Exercise Price
March 26, 2012	664,500	$2.41
May 17, 2012	82,500	$1.93
July 3, 2012	5,000	$1.77
September 11, 2012	5,000	$0.88
October 2, 2012	25,000	$0.75
October 18, 2012	250,000	$0.90
November 13, 2012	25,000	$0.90
November 16, 2012	1,442,000	$0.96
November 20, 2012	5,000	$0.96

ESCROWED SECURITIES

To the knowledge of management of the Company, none of its securities are subject to escrow conditions or contractual restrictions on transfer.

- 44 -

DIRECTORS AND OFFICERS

Directors and Officers

The following sets forth, as at the date hereof, the residence of the directors and executive officers of the Company, their offices or positions with the Company, their principal occupations during the past five years and the period during which each director has served as a director. The term of the directors' office expires at the next annual meeting of Shareholders.

Name and Residence	Office or Position	Director Since	Principal Occupation During the Last Five Years
Kerry R. Brittain(1)(3) Texas, United States	Chairman of the Board	September 2009	Retired from private law Prior to July 2007, Senior Vice President, General Counsel and Secretary for Harvest Natural Resources Inc., a U.S. public oil and gas company.
Jack W. Schanck Alberta, Canada	President and Chief Executive Officer and Director	December 2010	President and Chief Executive Officer of Sonde since October 2010.  From 2007 to 2009, Managing Partner of Tecton Energy (following the merger of Southview Energy and Tecton Energy).
Dr. James M. Funk(3)(4) Pennsylvania, United States	Director	September 2009	From January 2004 to present, President and Geologist of J.M Funk & Associates, Inc., a private oil and gas consulting company.
W. Gordon Lancaster(1)(2) British Columbia, Canada	Director	April 2011	From November 2009 to present, an independent business consultant. From January 2004 to November 2009, Chief Financial Officer of Ivanhoe Energy Inc., a public oil and gas company.
Dr. William J.F. Roach(1)(4) Alberta, Canada	Director	September 2009	From January 2012 to present, Chief Executive Officer of Cavalier Energy Inc., a private oil sands company. From October 2010 to December 2011, Chief Executive Officer of Calera Corporation, a carbon capture company. Prior thereto, from October 2004 to October 2010, President and Chief Executive Officer of UTS Energy Inc., a public oil and gas company.
James H.T. Riddell(2)(4) Alberta, Canada	Director	January 2010	From June 2002 to present, President and Chief Operating Officer of Paramount Resources Ltd., a public oil and gas company and from February 2010 to present, President and Chief Executive Officer of Trilogy Energy Corp., a public oil and gas company. Prior thereto, from February 2005 to February 2010, President and Chief Executive Officer of Trilogy Energy Ltd., a public oil and gas company.
Gregory G. Turnbull(2) (3) Alberta, Canada	Director	September 2009	From July 2002 to present, a partner with the law firm of McCarthy Tétrault llp.

- 45 -

Name and Residence	Office or Position	Director Since	Principal Occupation During the Last Five Years
Kurt A. Nelson Texas, United States	Chief Financial Officer	N/A	From May 2011 to present, Chief Financial Officer of the Company.  Prior thereto, from November 2001 to May 2008, Vice President and Chief Accounting Officer for Harvest Natural Resources, Inc. a public oil and gas company.
Toufic Nassif(5) Texas, United States	President, North Africa	N/A	From November 2011 to present. President Sonde North Africa. From September 2010 to November 2011 President of T P Nassif and Associates an oil and gas consultancy firm based in Houston. From April 2004 till September 2010 VP and Commercial Director, BP Libya, Director for BP Exploration North Africa and BP Exploration Libya Ltd.

Notes:

(1) Member of the Audit Committee.

(2) Member of the Compensation Committee.

(3) Member of the Corporate Governance Committee.

(4) Member of the Health, Safety, Environment and Reserves Committee.

(5) Mr. Nassif was appointed President, North Africa, a wholly-owned subsidiary of the Company on November 16, 2012.

As at December 31, 2012, the directors and executive officers of the Company, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 530,729 Common Shares representing less than one percentof the issued and outstanding Common Shares.

Corporate Cease Trade Orders or Bankruptcies

To the knowledge of management, no director or executive officer of Sonde is, or has been, within the past 10 years before the date hereof, a director or executive officer of any issuer that, while that person was acting in that capacity: (i) was the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under securities legislation for a period of more than 30 consecutive days; or (ii) was subject to an event that resulted, after the person ceased to be a director or executive officer, in the issuer being the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under securities legislation for a period of more than 30 consecutive days, other than:

· Mr. Riddell was a director and executive officer of Paramount Resources Ltd., the general partner of T.T.Y. Paramount Partnership No. 5, a limited partnership engaged in oil and gas exploration and development activities. A cease trade order against T.T.Y. Paramount Partnership No. 5 was issued by the Quebec Securities Commission in 1999 for failing to file its June 30, 1998 financial statements in Quebec. The cease trade order was revoked on April 9, 2008. T.T.Y. Paramount Partnership No. 5 was dissolved on July 21, 2008.

To the knowledge of management, no director, executive officer of Sonde or controlling Shareholder is, or has been, within the past 10 years before the date hereof, a director or executive officer of any issuer that, while that 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 or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets, other than:

· Messrs. Brittain, Funk, Roach and Turnbull were appointed directors of the Company in connection with the completion of the CCAA Proceeding;

· Mr. Turnbull was a director of Action Energy Inc., a corporation engaged in the exploration, development and production of oil and gas in Western Canada.  Action Energy Inc. was placed in

- 46 -

receivership on October 28, 2009 by its major creditor and Mr. Turnbull resigned as a director immediately thereafter; and

· Mr. Riddell was a director of Jurassic Oil and Gas Ltd., a private oil and gas company, within one year of such company becoming bankrupt. Jurassic Oil and Gas Ltd.'s bankruptcy was subsequently annulled.

Personal Bankruptcies

To the knowledge of management, no director, executive officer of Sonde or controlling Shareholder has, within the 10 years before the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or became subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold such person's assets.

Penalties or Sanctions

To the knowledge of management, no director, executive officer of Sonde or controlling Shareholder has: (i) been subject to 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, other than penalties for late filing of insider reports; or (ii) been subject to 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

Certain of the directors and officers of the Company are directors and/or officers of other private and public companies. Some of these private and public companies may, from time to time, be involved in business transactions or banking relationships which may create situations in which conflicts might arise. Any such conflicts shall be resolved in accordance with the procedures and requirements of the relevant provisions of the ABCA, including the duty of such directors and officers to act honestly and in good faith with a view to the best interests of the Company.

AUDIT COMMITTEE

Composition of the Audit Committee

The Audit Committee operates pursuant to a charter that sets out its responsibilities and composition requirements. A copy of the charter is attached to this Annual Information Form as Appendix "C". The Audit Committee consists of Messrs. Lancaster (Chair), Brittain and Roach. All members of the Audit Committee are independent and financially literate (as determined by National Instrument 52-110, Audit Committees). In addition, Mr. Lancaster is a “financial expert” as defined under National Instrument 52-110, Audit Committees.

In considering criteria for the determination of financial literacy, the Board looked at the ability to read and understand a balance sheet, an income statement and cash flow statement of a public company as well as the director's past experience in reviewing or overseeing the preparation of financial statements. The following sets out the education and experience of each director relevant to the performance of his duties as a member of the Audit Committee.

W. Gordon Lancaster

Gord Lancaster is a Chartered Accountant and completed a 20-year career in public accounting with Deloitte LLP (formerly Deloitte & Touche LLP) with the last five years as a partner in that firm’s Vancouver office. He spent the next 27 years as a Chief Financial Officer of large and medium sized publicly traded companies. Mr. Lancaster also currently serves as the Chair of the audit committee of a TSX listed forestry company and as a member of the audit committee for a TSX and HKSE listed coal mining company. Mr. Lancaster is a Chartered Accountant certified in British Columbia and is a member of the Institute of

- 47 -

Corporate Directors. For more information with respect to Mr. Lancaster’s principal occupations during the past five years, see "Directors and Officers".

Kerry R. Brittain

Kerry Brittain retired from private law practice after 35 years' experience advising companies on acquisitions, dispositions and other domestic and international transactions in the oil and gas industry. Mr. Brittain previously served as Senior Vice President, General Counsel and Secretary of a U.S. public oil and gas company and, in that role, was responsible for reporting at the Board of Directors' level on governance and compliance matters.  Mr. Brittain holds a Bachelor of Arts degree and a Juris Doctor degree.

Dr. William J. F. Roach

Dr. Roach is the Chief Executive Officer of Cavalier Energy Inc., a private oil sands company and from October 2004 until October 2010, Dr. Roach was the President and Chief Executive Officer of UTS Energy Inc., a public oil sands company.  Dr. Roach has been responsible for overseeing the preparation of financial statements and related financial and operating reporting in accordance with NI 51-102 and the rules of the TSX.  In his prior roles Dr. Roach has been responsible for establishing and maintaining disclosure controls and procedures and internal control over financial reporting, and providing annual and quarterly certifications in connection therewith. Dr. Roach is also a member of the Audit Committee of Kior Inc., a NASDAQ listed company. Dr. Roach holds a Bachelor Science degree in Metallurgy, a Doctorate degree in Metallurgy and is a Chartered Engineer in the United Kingdom and a Professional Engineer in Canada.

Auditors' Fees

Deloitte llp is the external auditor of the Company and is independent to the Company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta. Fees paid to the Company's auditors for the years ended December 31, 2012 and 2011 are detailed below.

Fee	For the year ended December 31, 2012	For the year ended December 31, 2011
Audit Fees	$312,922	$329,600
Audit-Related Fees(1)	$6,126	$162,526
Tax Fees(2)	$66,554	$152,168
Other Fees(3)	--	$24,398
Total	$385,602	$668,692

Notes:

(1) "Audit-Related Fees" include the aggregate fees paid to the external auditors for services related to the audit services, including reviewing quarterly financial statements and management's discussion thereon, conversion to International Financial Reporting Standards and consulting with the Board and Audit Committee regarding financial reporting and accounting standards.

(2) "Tax Fees" include the aggregate fees paid to external auditors for tax compliance, tax advice, tax planning and advisory services, including namely preparation of tax returns.

(3) "All Other Fees" include the aggregate fees paid to the external auditors for assurance procedures in connection with filings statements and information circulars and services related to offerings.

All permissible categories of non-audit services to be provided by the external auditor must be pre-approved by the Audit Committee subject to certain statutory exceptions.

LEGAL AND REGULATORY PROCEEDINGS

Except as disclosed herein, Sonde is not a party to any legal proceeding nor was it a party to, nor is or was any of its property the subject of any legal proceeding, during the year ended December 31, 2012, nor is management of the Company aware of any such contemplated legal proceedings, which involve a claim for damages, exclusive of interest and costs, that may exceed 10% of the current assets of the Company.

During the year ended December 31, 2012, there were no: (i) penalties or sanctions imposed against the Company by a court relating to securities legislation or by a securities regulatory authority; (ii) penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered

- 48 -

important to a reasonable investor in making an investment decision; or (iii) settlement agreements the Company entered into before a court relating to securities legislation or with a securities regulatory authority.

In addition, the Company is involved in various claims and litigation arising in the ordinary course of business.  In the opinion of the Company such claims and litigation are not expected to have a material effect on the Company’s financial position or its results of operations. The Company maintains insurance, which in the opinion of the Company, is in place to address any future claims as to matters insured.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Except as disclosed herein, no director or executive officer of the Company, or any person or company that is the beneficial owner of, or who exercises control or direction of, more than 10% of the Common Shares or any associate or affiliate of any of the foregoing persons has had any material interest, direct or indirect, in any transaction in the three most recently completed financial years or during the current financial year that has materially affected or will materially affect Sonde.

TRANSFER AGENT AND REGISTRAR

Valiant Trust Company at its principal offices in Calgary, Alberta and Toronto, Ontario, is the transfer agent and registrar for the Common Shares.

MATERIAL CONTRACTS

Except for contracts entered into in the ordinary course of business, the Company has not entered into any material contracts within the most recently completed financial year, or before the most recently completed financial year that are still in effect, other than:

· Rights Plan Agreement - see "Description of Share Capital - Rights Plan";

· Farm-Out Agreement - see "Principal Properties - International"; and

· Amending Agreement for the Joint Oil Block Exploration and Production Sharing Agreement

INTERESTS OF EXPERTS

Reserve estimates contained in this Annual Information Form have been prepared by GLJ. As at December 31, 2012, the effective date of those estimates, and as of the date hereof, the principals, directors, officers and associates of GLJ, as a group, owned, directly or indirectly, less than one percent of the outstanding Common Shares.

Deloitte llp is the external auditor of the Company and is independent within the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

ADDITIONAL INFORMATION

Additional information relating to the Company may be found on SEDAR at www.sedar.com. Specifically, information as to directors' and officers' remuneration and indebtedness, principal holders of the Company's securities and securities authorized for issuance under equity compensation plans is contained in the Information Circular of the Company prepared in connection with the most recent annual meeting of Shareholder that involved the election of directors. Additional financial information is provided in the Company's financial statements and management discussion and analysis for the year ended December 31, 2012.

APPENDIX "A"

REPORT ON RESERVES DATA BY

INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

Terms to which a meaning is ascribed in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities have the same meaning herein.

To the Board of Directors of Sonde Resources Corp. (the "Company"):

1. We have evaluated the Company's reserves data as at December 31, 2012. The reserves data are estimates of proved and probable reserves and related future net revenue as at December 31, 2012, 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 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%, included in the reserves data of the Company evaluated by us for the year ended December 31, 2012, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management and Board of Directors.

Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country)	Net Present Value of Future Net Revenue (10% discount rate)
			Audited (M$)	Evaluated (M$)	Reviewed (M$)	Total (M$)
GLJ Petroleum Consultants	February 19, 2013	Canada	Nil	109,125	Nil	109,125

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are 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 our reports referred to in paragraph 4 for events and circumstances occurring after their preparation dates.

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:

GLJ Petroleum Consultants Ltd., Alberta, Canada,

February 19, 2013

(signed) "Keith M. Braaten"

Keith M. Braaten

President & CEO

APPENDIX "B"

REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Terms to which a meaning is ascribed in National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities have the same meaning herein.

Management of Sonde Resources Corp. (the "Company") is responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved and probable reserves and related future net revenue as at December 31, 2012, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Company's reserves data. The report of the independent qualified reserves evaluator is presented in Appendix "A" to the Annual Information Form of the Company, effective as at December 31, 2012.

The Health, Safety, Environment and Reserves Committee of the Board of Directors of the Company has:

(a) reviewed the Company'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 Health, Safety, Environment and Reserves Committee of the Board of Directors has reviewed the Company'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 Health, Safety, Environment and Reserves 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 judgements regarding future events, actual results will vary and the variations may be material.

(signed) "Jack W. Schanck"	(signed) "William Dirks"
Jack W. Schanck	William Dirks
Chief Executive Officer	Chief Operating Officer
(signed) "William Roach"	(signed) "James M. Funk"
William J.F. Roach	James M. Funk
Director	Director

Dated March 21, 2013

APPENDIX "C"

AUDIT COMMITTEE CHARTER

ESTABLISHMENT OF COMMITTEE

1. Audit Committee

The Board of Directors (the “Board”) of Sonde Resources Corp. (the “Corporation”) has established an audit committee (the “Audit Committee” or the “Committee”).

The primary objective of the Audit Committee is to act as a liaison between the Board and the Corporation’s independent external auditor and to assist the Board in fulfilling its oversight responsibilities with respect to:

(a) the financial statements and other financial information provided by the Corporation to its shareholders, the public and others;

(b) the Corporation’s compliance with legal and regulatory requirements;

(c) the qualification, independence and performance of the external auditors; and

(d) the Corporation’s risk management and internal financial and accounting controls, and management information systems.

Although the Committee has the powers and responsibilities set forth in this Charter, the role of the Committee is oversight.  The members of the Committee are not full-time employees of the Corporation and may or may not be accountants or auditors by profession or experts in the fields of  accounting or auditing  and, in any event, do not serve in such capacity.  Consequently it is not the duty of the Committee to conduct audits or to determine that the Corporation’s financial statements and disclosures are complete and accurate and are in accordance with generally accepted accounting principles and applicable rules and regulations.  These are the responsibilities of management.

2. Composition of Committee

(a) the Audit Committee will consist of at least three directors. All members of the Committee must be independent as defined in applicable securities laws (subject to permitted exemptions under those laws) and the rules of any stock exchange on which the Corporation’s securities are listed for trading.

(b) each member of the Audit Committee must be financially literate, or become financially literate within a reasonable period of time following his or her appointment to the Committee (provided that the Board has determined that this will not materially adversely affect the ability of the Committee to satisfy its responsibilities).  A member is financially literate under applicable securities laws if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Corporation’s financial statements.

2

3. Appointment of Committee Members

Members of the Audit Committee will be appointed by the Board and re-appointed at the meeting of the Board immediately following each annual meeting of shareholders. Committee members will hold office until the next annual meeting or earlier if their successors are appointed, they are removed by the Board or they cease to be directors of the Corporation.

4. Compensation of Committee Members

The Board will fix the remuneration of the members of the Audit Committee and may provide additional remuneration to the Chair of the Committee. Other than as remuneration for acting in his or her capacity as a member of the Board or any Board committee, or as a part-time chair or vice- chair of the Board or any Board committee, or as otherwise permitted by applicable securities laws, no consulting, advisory or other compensatory fee will be paid to a member of the Audit Committee by the Corporation or any subsidiary of the Corporation.

5. Vacancies

When a vacancy occurs in the membership of the Audit Committee, it may be filled by the Board and must be filled by the Board if the membership of the Committee as a result of the vacancy is less than three directors. Any member may be removed or replaced at any time by the Board. Any member will cease to be a member upon ceasing to be a director.

COMMITTEE PROCEDURES

6. Committee Chair

The Board will appoint a Chair for the Audit Committee.

7. Absence of Committee Chair

If the Chair is not present at any meeting of the Audit Committee, one of the other members of the Committee present at the meeting will be chosen by the Committee to preside at the meeting.

8. Secretary of Committee

The Secretary of the Company shall be the secretary to the Committee unless the Committee designates otherwise.

9. Meetings

The Audit Committee will meet at least four times per year. All Committee members are expected to attend each meeting, in person or by telephone - or video-conference. The Committee shall only act on the affirmative vote of a majority of members. A resolution in writing, signed by all the Audit Committee members entitled to vote on that resolution at a meeting of the Committee, is as valid as if it had been passed at a meeting of the Committee.

10. Notice of Meetings

(a) A meeting of the Audit Committee may be called by any member of the Committee, by the Chairman of the Board, the chief executive officer or the chief financial officer of the Corporation (or persons holding equivalent offices) or by the external auditor. Notice of the time and place of a meeting will be given in writing or by electronic communication to each member of the Committee and to the external auditor prior to the time fixed for the

3

meeting.

11. Quorum and Participation

(a) A majority of the number of members of the Audit Committee appointed by the Board constitutes a quorum at any meeting of the Committee.

(b) A member of the Audit Committee may, if all the members of the Committee consent, participate in a meeting of the Committee by means of a telephonic, electronic or other communication facility that permits all participants to communicate adequately with each other during the meeting. A member participating in a Committee meeting by those means is deemed to be present at that meeting.

12. Attendance by External Auditor and Others

(a) The external auditor is entitled, at the expense of the Corporation, to attend and be heard at every meeting of the Audit Committee, and, if so requested by a member of the Committee, shall attend every meeting of the Committee held during the term of office of the external auditor.

(b) At the invitation of the Chair of the Audit Committee, one or more officers or employees of the Corporation or directors who are not members of the Committee may attend a meeting of the Committee.

13. Procedure, Records and Reporting

The chair of the Committee shall report regularly to the Board on the Committee’s activities, findings and re commendations.  Minutes of all meetings shall be made available to the Board, and all information reviewed and discussed by the Committee at any meeting shall be retained and made available for examination by the Board upon request of the chair.

14. Independent Advisors

The Audit Committee may engage independent counsel and other advisors as it determines necessary to carry out its duties. Furthermore, the Committee has the authority to set and pay the compensation for any such advisors which are employed by the Committee.  The Corporation will provide the Committee adequate funds to cover fees and other costs incurred in carrying out its duties and responsibilities.

15. Review of Committee Performance and Charter

At least annually the Committee will review its performance and effectiveness and report the results to the Board. The annual review will include an assessment of the adequacy of this Charter and the Committee will recommend any proposed changes to the Board for approval.

16. Duties and Reliance

(a) In exercising their powers and discharging their duties under this charter and applicable

4

law, each member of the Audit Committee must (i) act honestly and in good faith with a view to the best interests of the Corporation and (ii) exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances.

(b) Each member of the Audit Committee will be entitled to reasonable reliance, or reliance in good faith, on:

(i) financial statements of the Corporation represented to the member of the Committee by an officer of the Corporation or in a written report of the external auditor of the Corporation to reflect fairly the financial condition of the Corporation;

(ii) the Corporation’s disclosure compliance system and on the Corporation’s officers, employees and others whose duties would in the ordinary course have given them knowledge of the relevant facts; and

(iii) a report, statement or opinion of an expert, being a person or company whose profession gives authority to a statement made in a professional capacity by the person or company including, without limitation, an accountant, actuary, appraiser, auditor, engineer, financial analyst, geologist or lawyer.

MANDATE OF COMMITTEE

17. External Auditor

(a) The external auditor will report directly to the Audit Committee, be responsible for planning with the Corporation and carrying out the audit of the annual financial statements (and any requested review of quarterly financial statements) and ultimately be accountable to the Audit Committee and the Board as the representatives of the shareholders.

(b) The Audit Committee will recommend to the Board:

(i) the external auditor to be nominated for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services for the Corporation; and

(ii) the compensation of the external auditor.

(c) The Audit Committee will be directly responsible for overseeing the work of the external auditor engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services for the Corporation, including the following:

(i) review of the mandate of the external auditor, including the annual engagement letter, audit plan, audit scope and the factors considered in determining the audit scope, including the major risk factors; and confirmation as to whether or not any limitations have been placed on the scope or nature of the external auditor’s audit procedures;

(ii) review of significant accounting and reporting principles, practices and procedures applied by the Corporation in preparing its financial statements, including discussions with the external auditor of its judgments about the quality, not just the acceptability, of the Corporation’s accounting principles used in financing reporting;

5

(iii) review of the independence of the external auditor, and obtain from the external auditors, at least annually, a formal written statement delineating all relationships between the external auditors and the Company as contemplated by Independence Standards Board Standard No. 1, Independence Discussions with Audit Committees;

(iv) review any rotation of the partners assigned to the audit in accordance with applicable laws and professional standards, the internal quality control findings of the external auditor’s firm and peer reviews;

(v) review of the performance of the external auditor, including the relationship between the external auditor and management and the evaluation of the lead partner of the external auditor;

(vi) termination or resignation of the external auditor if circumstances warrant, after due inquiry and discussion with management and the external auditor;

(vii) resolution of disagreements between management and the external auditor regarding financial reporting;

(viii) review of material written communications between the external auditor and management;

(ix) review of the annual management letter from the external auditor regarding internal controls and opportunities for improvement or efficiency, plus management’s response and follow-up in respect of any identified weakness; and

(x) communication with the external auditor regarding such other matters as are required by the Canadian Institute of Chartered Accountants Handbook and other professional standards.

(d) As necessary or desirable, but in any case at least quarterly the Audit Committee will meet or communicate directly with the external auditor and members of management, in separate executive sessions, as required or appropriate to discharge the responsibilities of the Committee.  The Committee will discuss with the external auditor, without management being present, (a) the quality of the Corporation’s financial and accounting personnel, and (b) the completeness and accuracy of the Corporation’s financial statements.  Also, the Committee will elicit the comments of management regarding the responsiveness of the external auditors to the Corporation’s needs.

(e) The Audit Committee will have a  predetermined arrangement with  the  external auditor that  it  will  advise the Committee, through its Chair and management of the Corporation, of any matters identified through procedures followed for the review of interim quarterly financial statements of the Corporation, and that such notification is to be made prior to the related press release. The Audit Committee will also receive a written confirmation provided by the external auditor at the end of each of the first three quarters of the year that it has nothing to report to the Committee, if that is the case, or the written enumeration of required reporting issues.

18. Non-Audit Services

(a) The Audit Committee will pre-approve all non-audit services to be provided to the Corporation or its subsidiaries by the external auditor.

(b) The Audit Committee may delegate to one or more of its members the authority to pre- approve non-audit services. The pre-approval of non-audit services by any member to whom

6

authority has been delegated must be presented to the Committee at its first scheduled meeting following such pre-approval.

(c) Pre-approval of de minimus non-audit services will be satisfied if:

(i) the aggregate amount of all the non-audit services that were not pre-approved is reasonably expected to constitute no more than five per cent of the total amount of fees paid by the Corporation and its subsidiaries to the Corporation’s external auditor during the fiscal year in which the services are provided;

(ii) the Corporation or the subsidiary, as the case may be, did not recognize the services as non-audit services at the time of the engagement; and

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

(d) Pre-approval of non-audit services will also be satisfied if the Audit Committee adopts specific policies and procedures for the engagement of non-audit services and:

(i) the pre-approval policies and procedures are detailed as to the particular service;

(ii) the Audit Committee is informed of each non-audit service; and

(iii) the procedures do not include delegation of the Audit Committee’s responsibilities to management.

19. Financial and Other Disclosure

(a) The Audit Committee will review, discuss with management (and the external auditor where required or appropriate) and, if required or appropriate, approve or recommend that the Board approve the following Corporation documents prior to public disclosure:

(i) annual audited financial statements and related management’s discussion and analysis;

(ii) quarterly unaudited financial statements and related management’s discussion and analysis;

(iii) certifications by the chief executive officer and chief financial officer of annual and quarterly filings, disclosure controls and procedures and internal controls over financial reporting;

(iv) news releases announcing financial results, containing financial information based on unreleased financial results or non-GAAP financial measures or providing earnings guidance or forward-looking financial information; and

(v) financial information contained in  any  annual information form, information circular, prospectus, take-over bid circular, issuer bid circular or rights offering circular.

7

(b) The Audit Committee will be satisfied that adequate procedures are in place for the review of the Corporation’s public disclosure of financial information extracted or derived from the Corporation’s financial statements and will periodically assess the adequacy of those procedures.

(c) The Audit Committee will review the disclosure required by applicable securities laws to be included in its annual information form and cross-referenced in management information circular to solicit proxies from the shareholders of the Corporation for the purpose of electing directors to the Board. That disclosure will consist of the text of this charter, the composition of the Audit Committee, the relevant education and experience of Committee members, reliance on certain exemptions from securities laws relating to audit committees, oversight of the nomination and compensation of the external auditor, policies and procedures for non-audit services and external auditor service fees.

20. Financial Reporting Processes

(a) The Audit Committee will review with management and the external auditor:

(i) the appropriateness of the Corporation’s accounting principles and policies and financial reporting;

(ii) any changes to the Corporation’s accounting principles and policies and financial reporting as such changes are recommended by management or the external auditor;

(iii) the accounting treatment of significant risks and uncertainties;

(iv) key  estimates  and  judgments  of  management  that  may  be  material  to  the Corporation’s financial reporting;

(v) significant changes to the audit plan, if any; and

(vi) Any serious disputes or difficulties with management encountered during the audit and the cooperation received by the external auditor during its audit, including access to all requested records, data and information.

(b) The Audit Committee will in particular review the following specific matters, where material:

(i) the effect of regulatory and accounting initiatives;

(ii) extraordinary transactions;

(iii) the use of special purpose entities;

(iv) off-balance sheet transactions;

(v) financial risk management, including the use of derivatives;

(vi) asset retirement or reclamation obligations;

(vii) pension obligations;

8

(viii) commitments, contingencies and guarantees;

(ix) related party transactions;

(x) actual or pending legal claims, tax or regulatory matters; and

(xi) any other matters of accounting or auditing risk.

21. Other Responsibilities

(a) The Audit Committee will establish procedures for:

(i) the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters; and

(ii) the confidential, anonymous submission by employees of the Corporation of concerns regarding questionable accounting or auditing matters.

(b) The Audit Committee will review on a timely basis all discovered incidents of fraud within the Corporation, regardless of monetary value;

(c) The Audit Committee will oversee any auditing or accounting reviews or similar procedures or investigations and may conduct its own investigations with full access to books, records, facilities and personnel of the Corporation.

(d) The Audit Committee will at least annually provide oversight of the Corporation’s risk management policies.

(e) The Audit Committee will review and approve the Corporation’s policies regarding officer and director expenses, perquisites and use of corporate assets, and may review expenses actually incurred by the chief executive officer and other senior officers.

(f) The Audit Committee will review and approve the Corporation’s hiring policies regarding partners, employees and former partners and employees of the present and any former external auditor of the Corporation.

(g) Review with management, internal audit and the external auditors the methods used to establish and monitor the Corporation’s policies with respect to unethical or illegal activities by Corporation employees that may have a material impact on the financial statements.

(h) Generally as part of the review of the annual financial statements, receive a report(s), at least annually, concerning legal, regulatory and compliance matters that may have a material impact on the financial statements.

(i) Coordinate with the Reserves Committee as necessary concerning the disclosure of information with respect to the Corporation’s oil and gas reserves, including the Corporation’s procedures for complying with the disclosure requirements and restrictions of applicable regulations.

(j) Review with the external auditor the internal controls on computerized information system controls and security.

The Audit Committee will review and/or approve any other matters specifically delegated to the Committee by the Board and undertake on behalf of the Board such other activities as may be necessary or desirable to assist the Board in fulfilling its responsibilities.