Exhibit 1.3







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MANAGEMENT'S DISCUSSION AND ANALYSIS





This Management's Discussion and Analysis ("MD&A") has been prepared by management as of March 27, 2014 , and reviewed and approved by the Board of Directors (the “Board”) of Sonde Resources Corp. ("Sonde" or the "Company").  This MD&A is a review of the operational results of the Company.





Effective January 1, 2011 the Company adopted International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. This MD&A should be read in conjunction with the audited consolidated financial statements for the years ended December 31, 2013 and 2012.





Non-IFRS Measures - This MD&A contains references to funds from (used for) operations, funds from (used for) operations per share and operating netback, which are not defined under IFRS as issued by the International Accounting Standards Board and are therefore non-IFRS financial measures that do not have any standardized meaning prescribed by IFRS and are, therefore, unlikely to be comparable to similar measures presented by other issuers.





Management of the Company believes funds from (used for) operations, funds from (used for) operations per share and operating netback are relevant indicators of the Company’s financial performance, ability to fund future capital expenditures and repay debt. Funds from (used for) operations and operating netback should not be considered an alternative to or more meaningful than cash flow from operating activities, as determined in accordance with IFRS, as an indicator of the Company's performance.





In the operating netback and funds from (used for) operations section of this MD&A, reconciliation has been prepared of funds from (used for) operations and operating netback to cash (used in) provided by operating activities, the most comparable measure calculated in accordance with IFRS.





Forward-Looking Statements - This MD&A contains information that constitutes “forward-looking information” or “forward-looking statements” (collectively “forward-looking information”) within the meaning of applicable securities legislation.  This forward-looking information includes, among others, statements regarding:





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|• | the completion and results of the inert and acid gas initiative;

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|• | the ability to locate and secure an offshore drilling rig for the Fisal-1 well and future drilling obligations in North Africa;

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|• | the approval of the proposed unitization of the Zarat field and the revised Zarat field unit plan of development;

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|• | the future capital expenditures for the acquisition, exploration, development and production of oil and natural gas;

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|• | business strategy, plans, priorities and planned exploration and development activities;

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|• | the revitalized marketing campaign for the Joint Oil Block;

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|• | the results of seismic program covering the Hadaf prospect;

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|• | other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance; and

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|• | the Company's tax pools.




Undue reliance should not be placed on forward-looking information.  Forward-looking information is based on current expectations, estimates and projections that involve a number of risks which could cause actual results to vary and in some instances to differ materially from those anticipated by the Company and described in the forward-looking information contained in this MD&A.  The material risk factors include, but are not limited to:





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|• | the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas, market demand and unpredictable facilities outages;

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|• | risks and uncertainties involving geology of oil and gas deposits;

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|• | uncertainty related to production, marketing and transportation;

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|• | availability of experienced service industry personnel and equipment;

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|• | availability of qualified personnel and the ability to attract or retain key employees or members of management;

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|• | the uncertainty of reserves or resources estimates, reserves or resources life and underlying reservoir risk;

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|• | the uncertainty of estimates and projections relating to production, costs and expenses;

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|• | potential delays or changes in plans with respect to exploration or development projects or capital expenditures;

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|• | delays due to adverse weather conditions;

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|• | fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;

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|• | the outcome and effects of any future acquisitions and dispositions;

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|• | health, safety and environmental risks;

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|• | uncertainties as to the availability and cost of financing and changes in capital markets;

2013 Annual MD&A |1


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|• | risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action);

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|• | risks associated with competition from other producers;

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|• | changes in general economic and business conditions;

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|• | the possibility that government policies or laws may change or government approvals may be delayed or withheld;

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|• | the impact on the Company’s financing abilities relating to its North African obligations;

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|• | the negotiation of the proposed unitization and plan of development of the Zarat field; and

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|• | general economic, market and business conditions.




The foregoing list of risk factors is not exhaustive.  Additional information on these and other factors which could affect the Company’s operations or financial results are included in the Company’s most recent Annual Information Form.  In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission.





Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is presented.  The Company assumes no obligation to update forward-looking information should circumstances or management’s estimates or opinions change, except as required by law. Statements contained in this document relating to estimates, results, events and expectations are forward-looking statements within the meaning of Section 27A of the United States Securities Act of 1933, as amended and Section 21E of the United States Securities Exchange Act of 1934, as amended.





These forward-looking statements involve known and unknown risks, uncertainties, scheduling, re-scheduling and other factors which may cause the actual results, performance, estimates, projections, resource potential and/or reserves, interpretations, prognoses, schedules or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such statements.  Such factors include, among others, those described in the Company’s annual reports on Form 40-F or Form 20-F on file with the U.S. Securities and Exchange Commission.





Boe Presentation – Production information is commonly reported in units of barrel of oil equivalent ("boe").  For purposes of computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet to one barrel of oil (6:1).  This conversion ratio of 6:1 is based on an energy equivalency conversion method primary applicable at the burner tip and does not represent a value equivalency at the wellhead.





Such disclosure of boe may be misleading, particularly if used in isolation.  Additionally, given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be misleading as an indication of value.





Readers should be aware that historical results are not necessarily indicative of future performance. Natural gas production is expressed in thousand cubic feet (“mcf”) or million cubic feet (“mmcf”). Oil and natural gas liquids are expressed in barrels (“bbls”) or thousands of barrels (“mbbls”).


2013 Annual MD&A |2


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Business overview





Sonde is a Calgary, Alberta, Canada based energy company engaged in the exploration for and production of oil and natural gas. The Company’s operations are located offshore North Africa and in Western Canada.





North Africa





On August 27, 2008, the Company entered into an Exploration and Production Sharing Agreement (“EPSA”) with a Tunisian company, Joint Oil, covering the Joint Oil Block.  Joint Oil is owned equally by the governments of Tunisia and Libya.  The EPSA contract area straddles the offshore border between Tunisia and Libya.  Under terms of the EPSA, the Company is the operator.





On December 24, 2012, Joint Oil approved an amendment to the EPSA allowing for the extension of the first phase of the exploration period under the EPSA to December 23, 2015.  The extension provided for the drilling of three exploration wells, one each year, due December 23, 2013, December 23, 2014 and December 23, 2015.  On December 20, 2013, the Company reached an agreement with Joint Oil to extend the drilling deadline of the first exploration well required under the EPSA, Fisal-1, from December 23, 2013 to November 30, 2014 subject to the satisfaction of certain conditions, including the posting of a Confirmed Standby Letter of Credit(the "Agreement").  These conditions were met subsequent to the year ended December 31, 2013.





On December 27, 2012, the Company entered into a farm-out agreement with Viking Exploration and Production Tunisia Limited (“Viking”).  The farm-out agreement was terminated on November 15, 2013.  The Company is currently in the process of analyzing and evaluating prospects and options available to the Company with respect to the exploration and development of its North Africa assets, including potential farm-outs, strategic investments, the sale of an interest in the Joint Oil Block and other means of financing.  There is a great deal of uncertainty regarding the future development of the Joint Oil Block. The key items that contribute to this development uncertainty are:





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|• | The Inert and Acid Gas Initiative –In June, 2012, the DGE (Tunisian Direction Generale de L’Energie) announced an initiative for the Gulf of Gabes operators offshore Tunisia to study options for sequestration of carbon dioxide and other inert and acid gases (which comprise a high percentage of all known oil and gas accumulations in the Gulf of Gabes, including the Joint Oil Block) to allow the currently stranded high inert content gas to be developed commercially and brought to the Tunisian market. This initiative will ensure that the Zarat Development and other developments in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments with international organizations such as the Kyoto Accord on greenhouse gas emissions. The first phase of the study has been completed and work on the second phase of the study, which identifies the various options for inert and acid gas processing and CO2 sequestration, is near completion.  In addition to the work that the consortium is completing to find a global solution for inert and acid gas in the Gulf of Gabes, the potential negative impact of the presence of high inerts in the Zarat Field has been significantly decreased due to the proposed plan of development discussed below,which contemplates the re-injection of produced inert and acid gas into the reservoir for the first seven years.

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|• | Drilling Rig Availability –Sonde has been working through a rig consortium, composed of various operators in Tunisia under the auspices of ETAP, the Tunisian National Oil Company, to secure a slot in a rig program for drilling Fisal by the end of November 2014 as agreed with Joint Oil.  Current discussions are focusing on securing the first slot of the rig that an operator is bringing into Tunisia in mid-August 2014. Sonde remains optimistic that with the help of ETAP and Joint Oil the Company will be able to secure a slot to drill Fisal as scheduled.

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|• | Unitization and Plan of Development –The DGE requested that the parties involved in the Zarat development submit to the DGE, for review and approval, the final draft of the Unitization Agreement by the first week of October 2013 and the Unit Plan of Development no later than December 31, 2013.  Working with Joint Oil and ETAP, the Company finalized the draft Unitization Agreement and submitted it to the DGE before the deadline.  The Company also proposed a new plan of development for Zarat that will allow for the re-injection of produced gases into the reservoir.  This will allow for a more cost effective development and the expedited receipt of liquids sales proceeds. Working with Joint Oil the Company submitted the Unit Plan of Development to the DGE prior to December 31, 2013.

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|• | Exploratory Well Obligations –As discussed above, on December 24, 2012 the Company received an extension of the first exploration phase to December 23, 2015 and on December 20, 2013 received an extension to November 30, 2014 on drilling the first exploratory well, Fisal-1.




2013 Annual MD&A |3


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Western Canada





On January 9, 2013, Sonde announced that it had retained FirstEnergy Capital Corp. (“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 a result of the strategic alternatives process, the following transactions were undertaken by the Company.





During the year ended December 31, 2013 the Company sold 45,671 net acres of undeveloped land in the Montney play and 44,094 acres of undeveloped land in the Duvernay play, both in Central Alberta, to an unrelated third party.  This land was classified as exploration and evaluation assets and had a net book value of $2.6 million.  In addition, the Company sold related property, plant and equipment associated with the Montney play, with a net book value of $5.9 million, to the same unrelated third party.  These assets were sold for total proceeds of $6.1 million, resulting in a loss on disposition of $2.4 million.





On December 31, 2013 the Company completed the previously announced Plan of Arrangement with Marquee Energy Ltd. ("Marquee")  whereby Marquee acquired substantially all of the Western Canadian assets of Sonde, including all of Sonde's Southern Alberta properties and all of Sonde's reserves, for consideration of $15 million in cash and 21,182,492 common shares of Marquee ("the Marquee Transaction").  The Marquee Transaction resulted in a loss on disposition of $30.9 million.  As a step in the Marquee Transaction, the common shares of Marquee received were distributed to Sonde's shareholders.





As a result of the Marquee Transaction, the Company no longer has production or revenue from operations in Western Canada.





Strategy


North Africa


Sonde has one clearly defined primary objective - the exploration and development of the Joint Oil Block. The divestiture of substantially all of the Company's Western Canadian assets has provided Sonde with the necessary capital and focus to advance the preparation for drilling Fisal and to further define the Hadaf exploration prospect in Libyan waters.





During the fourth quarter of 2013, Sonde completed the acquisition of 200 square kilometers of 3D seismic covering the Hadaf prospect. The data is currently being processed and the results of the program are expected in April 2014.  Interpretation of the processed data will commence immediately thereafter.





Sonde plans to drill the Fisal-1 exploration well during 2014 to further de-risk the Joint Oil Block exploration plays and to provide an enticing value proposition to potential partners.  The Company is actively pursuing a strategic partner for the Joint Oil Block.





As a result of the Marquee Transaction, the Company no longer generates cash flow from petroleum and natural gas sales, and the Company no longer has a material credit facility.  As such, the Company must fund operations from working capital, new financings, farm-outs or property dispositions.  Additional capital from such sources may not be accessible on terms and conditions or at a time acceptable to the Company, and there is material risk that the Company will exhaust its working capital prior to the execution of new financings, farm-outs or property dispositions. See "Contingencies and commitments", "Substantial capital requirements", "Liquidity and capital resources" and "Liquidity risk" for further discussion regarding the Company's obligations and working capital position.





Western Canada





The Company’s remaining Western Canadian oil and gas assets are primarily prospective undeveloped land positions in the Duvernay (44,021 acres net) and Wabamun (53,489 acres net) plays in West Central and Northern Alberta.  The Company is currently evaluating strategic alternatives with respect to its Western Canada assets.





Contingencies and commitments





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|(a) | North Africa EPSA




The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15.0 million per exploration well, and the Company has provided a corporate guarantee to a maximum of US$45.0 million ( December 31, 2012 - US$45.0 million) to secure its minimum work program obligations. The potential cost of drilling the three wells could exceed US$120.0 million.  The Company's US$45.0 million corporate guarantee was reduced to US$30 million subsequent to year end in connection with the posting of a US$15 million Confirmed Standby Letter of Credit as discussed below.





2013 Annual MD&A |4


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|(b) | North Africa exploratory well extension and farm-out




On December 24, 2012, Joint Oil approved the amendment to the EPSA allowing for the extension of the first phase of the exploration period under the EPSA to December 23, 2015.  The extension provided for the drilling of three exploration wells, one each year, due December 23, 2013, December 23, 2014 and December 23, 2015.  On December 20, 2013, the Company reached an agreement with Joint Oil to extend the drilling deadline of the first exploration well required under the EPSA, Fisal-1, from December 23, 2013 to November 30, 2014.





The Agreement required Sonde to deliver to Joint Oil a Confirmed Standby Letter of Credit ("Letter of Credit") in the amount of US$15.0 million by no later than January 10, 2014.  Sonde met this requirement subsequent to the year ended December 31, 2013 .  As a result of funding the Letter of Credit, US$15.0 million of the Company's cash and cash equivalents was classified to restricted cash, and the Company's corporate guarantee was reduced from US$45.0 million to US$30.0 million.





The Agreement allows Sonde to use the restricted cash to meet its payables in respect of the Fisal-1 Well if it is drilled by November, 2014.  If Sonde does not drill the Fisal-1 Well on or before November 30, 2014, Joint Oil shall have the right to draw the US$15.0 million under the Letter of Credit as payment of the penalty under the EPSA.





On December 27, 2012, the Company entered into a farm-out agreement with Viking Exploration and Production Tunisia Limited (“Viking”).  The farm-out agreement was terminated on November 15, 2013 due to Viking's inability to secure its required funding.





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|(c) | Commitments and financial liabilities




At December 31, 2013 , the Company has committed to future payments over the next five years and thereafter, as follows:


(CDN$ thousands)20142015201620172018ThereafterTotalAccounts payable and accrued liabilities10,135—————10,135Stock based compensation liability326—————326North Africa exploration commitments31,90815,954————47,862Office rent payable1,4921,5071,5131,5131,5285,75113,30443,86117,4611,5131,5131,5285,75171,627





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|(d) | Litigation and claims




The Company is not involved in any claims or litigation arising in the ordinary course of business.  The Company maintains insurance, which in the opinion of the Company, is sufficient to address any future claims as to matters insured.





Substantial capital requirements





The Company may make 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.





There can be no assurance that debt or equity financing 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 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 developments involving the Company's inability to meet its three exploratory well obligation in respect of the Joint Oil Block, unitization, the potential approval of a new unit plan of development which will allow for the re-injection of produced gases into the reservoir and drilling rig availability.





The uncertainty associated with the development of the Joint Oil Block may adversely affect the Company's ability to secure financing for these commitments through a farm-out, strategic partner, or sale process.





2013 Annual MD&A |5


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Liquidity and capital resources





(CDN$ thousands)December 31 2013December 31 2012Cash and cash equivalents33,95019,695Accounts receivable6,0554,683Current portion of prepaid expenses and deposits882733Accounts payable and accrued liabilities(10,135)(6,850)Stock based compensation liability(326)(1,074)Working capital surplus30,42617,187


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|(1) | This table includes both continuing and discontinued operations.




At December 31, 2013 , the Company had $34.0 million in cash and cash equivalents ( December 31, 2012 – $19.7 million).  In 2013 cash flow was augmented by non-core asset dispositions and the Marquee Transaction.  In 2012 cash flow was augmented by the February 8, 2012 sale of 24,383 net acres of undeveloped land in the Kaybob Duvernary play in Central Alberta for cash proceeds of $75 million, resulting in a gain of $73.4 million.





As at December 31, 2013 , the Company had working capital of $30.4 million ( December 31, 2012 – $17.2 million ) and had issued four letters of credit for $0.3 million ( December 31, 2012 – three letters of credit for $0.2 million ).  Subsequent to year end US$15 million of the Company's cash and cash equivalents was classified as restricted as a result of posting the Confirmed Standby Letter of Credit discussed previously.





As a result of the completion of the Marquee Transaction, the Company's $25.0 million ( December 31, 2012 - $30.0 million) demand revolving credit facility (“Credit Facility A”) was cancelled.  Credit Facility A was secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company.  All security over the assets has been released.





Capital expenditures and dispositions





Q4Q3Q4Year ended December 31(CDN$ thousands)20132013201220132012Continuing operationsNorth Africa4,483503(199)6,4996,413Corporate Assets(22)7(120)(77)1844,461510(319)6,4226,597Discontinued operations(16,188)1,5213,079(19,549)(46,988)Net capital expenditures(11,727)2,0312,760(13,127)(40,391)


Q4Q3Q4Year ended December 31(CDN$ thousands)20132013201220132012Exploration and evaluation3,550251413,9904,630Drilling and completions(4)464(246)52715,140Plants, facilities and pipelines7475821,4762,0105,126Land and lease3892601,0391,1786,288Capital well workovers(51)68657441,822Capitalized general and administrative expenses4828641,1652,7424,575Capital expenditures5,1132,2634,23210,49137,581Western Canada dispositions(16,550)—(250)(22,683)(75,229)North Africa farm-out proceeds——(995)—(995)Exploration and evaluation impairment, charged to exploration expense(290)(232)(227)(935)(1,748)Net capital expenditures(11,727)2,0312,760(13,127)(40,391)


2013 Annual MD&A |6


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North Africa





During the three months ended December 31, 2013 the Company completed seismic acquisition covering the Hadaf prospect in Libyan waters, resulting in capital expenditures of $3.5 million.  The Company is currently analyzing the results of the seismic program.  This seismic data acquisition comprised a portion of the 2013 work commitments under the EPSA.





Western Canada





During the year ended December 31, 2013 , the Company disposed of property, plant and equipment, primarily in the Montney play of Central Alberta, with a net book value of $5.9 million, and the related exploration and evaluation assets with a net book value of $2.6 million, for total net proceeds of $6.1 million, resulting in a loss of $2.4 million.  On December 31, 2013 the Company completed the previously announced Plan of Arrangement with Marquee whereby Marquee acquired substantially all of the Western Canadian assets of Sonde, including all of Sonde's Southern Alberta properties and all of Sonde's reserves, for consideration of $15 million in cash and 21,182,492 common shares of Marquee.  The Marquee Transaction resulted in a loss of $30.9 million.  As a step in the Marquee Transaction, the common shares of Marquee received were distributed to Sonde's shareholders.





In 2012 the Company completed the sale of 24,383 net acres of undeveloped land in the Kaybob Duvernay play in Central Alberta to an unrelated third party for cash proceeds of $75.0 million, resulting in a gain of $73.4 million.





Discontinued operations





Production


Q4Q3Q4Year ended December 31Commodity20132013201220132012Natural gas(mcf/d)7,0828,2448,9407,6509,725Crude oil(bbls/d)456494572488554Natural gas liquids(bbls/d)133160189160202Total production(boe/d)(6:1)1,7692,0282,2511,9232,376


Q4Q3Q4Year ended December 31Region20132013201220132012Southern Alberta (boe/d)1,5211,7471,9071,6421,950Central Alberta (boe/d)136177203166256Other Western Canada (boe/d)112104141115170Total production(boe/d)(6:1)1,7692,0282,2511,9232,376


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|(1) | All production is attributed to discontinued operations.




For the three and twelve months ended December 31, 2013 , production was weighted 33% and 34% respectively to crude oil and natural gas liquids, compared to 34% and 32% respectively during the three and twelve months ended December 31, 2012 .  For the three months ended December 31, 2013 , production averaged 1,769 boe/d, compared to 2,028 boe/d for the three months ended September 30, 2013 and 2,251 boe/d for the three months ended December 31, 2012 .





The decrease in production during the three months ended December 31, 2013 compared to the three months ended September 30, 2013 was due to natural decline.   The decrease in production compared to the three months ended December 31, 2012 is due to natural decline and constrained capital expenditures due to the Western Canada strategic alternatives process.





2013 Annual MD&A |7


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Operating netback and funds (used for) from operations


(CDN$ thousands)($ per boe)Three months ended December 3120132012% change20132012% changePetroleum and natural gas sales(2)6,3917,694(17)39.7037.147Transportation(2)(174)(139)25(1.08)(0.67)61Royalties(2)(643)(763)(16)(3.98)(3.68)85,5746,792(18)34.6432.796Operating expense(2)(1,987)(3,703)(46)(12.34)(17.87)(31)Well workover expense(2)(272)(1,090)(75)(1.69)(5.26)(68)Operating netback(1)3,3151,9996620.619.66113General and administrative(3,324)(1,869)78(20.65)(9.02)129Foreign exchange loss(12)(39)(69)(0.07)(0.19)(63)Interest and other income1546(67)0.090.22(59)Interest expense(12)(14)(14)(0.07)(0.07)—Funds (used for) from operations(1)(18)123(115)(0.09)0.60(115)Decommissioning expenditures(2)(98)(228)(57)(0.61)(1.10)100Changes in non-cash working capital4,481(1,235)46327.84(5.96)567Cash provided by operating activities4,365(1,340)42627.14(6.46)520


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|(1) | Non-IFRS measure.

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|(2) | All operating netback and decomissioning expenditures are attributed to discontinued operations.  See the Company's 2013 audited financial statements for a breakdown of changes in non-cash working capital attributed to discontinued operations.




For the three months ended December 31, 2013 , funds used for operations was $0.02 million compared to funds from operations of $0.1 million for the same period in 2012.  This was primarily the result of a 17% decrease in petroleum and natural gas revenue and a 75% decrease in well workover expense, substantially offset by a 78% increase in general and administrative expense.


(CDN$ thousands)($ per boe)Year ended December 3120132012% change20132012% changePetroleum and natural gas sales(2)27,78528,873(4)39.5833.2019Realized loss on financial instruments(2)—(92)(100)—(0.11)(100)Transportation(2)(751)(599)25(1.07)(0.69)55Royalties(2)(2,299)(3,286)(30)(3.27)(3.78)(13)24,73524,896(1)35.2428.6223Operating expense(2)(11,834)(14,209)(17)(16.86)(16.34)3Well workover expense(2)(1,067)(2,960)(64)(1.52)(3.40)(55)Operating netback(1)11,8347,7275316.868.8890General and administrative(10,594)(8,505)25(15.09)(9.78)54Foreign exchange loss(62)(411)(85)(0.09)(0.47)(81)Interest and other income103192(46)0.150.22(32)Interest expense(97)(285)(66)(0.14)(0.33)(58)Income taxes110(35)4140.16(0.04)500Funds from (used for) operations(1)1,294(1,317)1981.85(1.52)222Decommissioning expenditures(2)(1,382)(379)265(1.97)(0.44)348Changes in non-cash working capital4,6522,776686.633.19108Cash provided by operating activities4,5641,0803236.511.23429


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|(1) | Non-IFRS measure.

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|(2) | All operating netback and decomissioning expenditures are attributed to discontinued operations.  See the Company's 2013 audited financial statements for a breakdown of changes in non-cash working capital attributed to discontinued operations.




For the year ended December 31, 2013 , funds from operations was $1.3 million compared to funds used for operations of $1.3 million for the same period in 2012.  This was primarily the result of a 30% decrease in royalty expense, a 17% decrease in operating expense and a 64% decrease in well workover expense.  These changes were partially offset by a 25% increase in general and administrative expense.





2013 Annual MD&A |8


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Petroleum and natural gas sales





Q4Q3Q4Year ended December 31(CDN$ thousands, except where otherwise noted)20132013201220132012Petroleum and natural gas salesNatural gas2,5751,9142,8829,4768,942Crude oil3,1444,4433,83415,02315,620Natural gas liquids6729219783,2864,311Transportation(174)(235)(139)(751)(599)Royalties(643)(560)(763)(2,299)(3,286)Realized loss on commodity derivatives————(92)Total5,5746,4836,79224,73524,896Average sales price(including commodity derivatives)Natural gas ($/mcf)3.992.523.503.392.51Crude oil ($/bbl)75.7297.7772.6984.2676.62Natural gas liquids ($/bbl)55.7462.4356.3556.3058.38Average sales price($/boe)39.7039.0037.1439.5833.09AECO 5a($/mcf)3.062.883.593.242.45Edmonton Light($/bbl)96.93100.5284.2593.3386.86


|    |                                                                               
|--- | ------------------------------------------------------------------------------
|(1) | All petroleum and natural gas sales are attributed to discontinued operations.




For the three months ended December 31, 2013 , petroleum and natural gas sales, net of transportation and royalties , was $5.6 million , compared to $6.5 million for the three months ended September 30, 2013 and $6.8 million for the three months ended December 31, 2012 .  The decrease in sales during the three months ended December 31, 2013 compared to the three months ended December 31, 2012 and the three months ended December 31, 2012 was due to decreased production.


For the year ended December 31, 2013 , petroleum and natural gas sales, net of transportation and royalties , was $24.7 million , compared to $24.9 million for the year ended December 31, 2012 .  The decrease in sales was due to lower production, substantially offset by higher commodity prices.





The Company realized an average sales price, exclusive of royalties and transportation, of $39.70 per boe during the three months ended December 31, 2013 compared to $39.00 per boe during the three months ended September 30, 2013 and $37.14 per boe during the three months ended December 31, 2012 .  The 1.8% increase in realized sales price during the three months ended December 31, 2013 compared to the three months ended September 30, 2013 was due to an increase in natural gas prices substantially offset by a decrease in liquids prices.  The 6.9% increase in realized sales price during the three months ended December 31, 2013 compared to the three months ended December 31, 2012 was due to an increase in natural gas prices.





Royalties


Q4Q3Q4Year ended December 31(CDN$ thousands, except where otherwise noted)20132013201220132012RoyaltiesCrown4723475191,4952,362Freehold and overriding171213244804924Total6435607632,2993,286Royalties per boe ($)3.982.993.683.273.78Average royalty rate(%)10.08.09.99.011.4


|    |                                                         
|--- | --------------------------------------------------------
|(1) | All royalties are attributed to discontinued operations.




The Company pays royalties to provincial governments, freehold landowners and overriding royalty owners.  Royalties are calculated and paid based on petroleum and natural gas sales net of transportation. Crown royalties on Alberta natural gas production are calculated based on the Alberta Reference Price, which may vary from the Company’s realized corporate price, impacting the average royalty rate.  In addition, various items impact the average royalty rate paid, such as cost of service credits and other royalty credit programs.





2013 Annual MD&A |9


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Royalties on horizontal gas wells drilled in Alberta in 2012, 2013 and beyond, generally bear royalties at a maximum of 5% for 18 months or until cumulative production reaches 50,000 boe. Horizontal oil wells generally bear royalties at a maximum of 5% for 18 to 48 months until cumulative production reaches 50,000 boe to 100,000 boe, depending on well depth.





For the three months ended December 31, 2013 , natural gas and liquids royalties were $0.6 million , or 10.0% of total petroleum and natural gas sales, compared to $0.6 million or 8% of total petroleum and natural gas sales during the three months ended September 30, 2013 and $0.8 million or 9.9% of total petroleum and natural gas sales during the three months ended December 31, 2012 .  The decrease in natural gas and liquids royalties during the three months ended December 31, 2013 compared to the three months ended December 31, 2012 is due to an increase in the Gas Cost Allowance received by the Company in 2013.





For the year ended December 31, 2013 , natural gas and liquids royalties were $2.3 million , or 9% of total petroleum and natural gas sales, compared to $3.3 million or 11% of total petroleum and natural gas sales during the year ended December 31, 2012 .  The decrease in natural gas and liquids royalties during the year ended December 31, 2013 compared to the year ended December 31, 2012 is attributable to a decrease in the Company's production, primarily in the Eaglesham and Puskwa fields located in the Northern cash-generating unit ("CGU"), where the royalty rate is higher than in the Southern CGU.





Operating and well workover expense





Combined operating and well workover expenses during the three months ended December 31, 2013 were $2.3 million or $14.03 per boe, compared to $3.3 million or $17.51 per boe during the three months ended September 30, 2013 and $4.8 million or $23.13 per boe during the three months ended December 31, 2012 .  Combined operating and well workover expenses during the year ended December 31, 2013 were $12.9 million or $18.38 per boe, compared to $17.2 million or $19.74 per boe during the year ended December 31, 2012 .  The decrease in operating and well workover expenses was due to decreased production and fewer workovers being performed.  All operating and well workover expense was from discontinued operations.





Depletion, depreciation and impairment





For the three months ended December 31, 2013 , depletion and depreciation was $2.4 million or $15.00 per boe compared to $2.2 million or $13.28 per boe during the three months ended September 30, 2013 and $2.7 million or $13.11 per boe during the three months ended December 31, 2012 .  The calculation of depletion and depreciation excluded $53.1 million ( September 30, 2013 – $56.5 million, December 31, 2012 - $54.6 million) related to exploration and evaluation assets, primarily comprised of the Company’s North Africa asset.  The increase in depletion and depreciation during the three months ended December 31, 2013 compared to the three months ended September 30, 2013 was due to higher depreciation recorded on fixed assets.  The decrease in depletion and depreciation during the three months ended December 31, 2013 compared to the three months ended December 31, 2012 was due to lower production.





For the year ended December 31, 2013 , depletion and depreciation was $9.7 million or $13.80 per boe compared to $11.0 million or $12.68 per boe during the year ended December 31, 2012 . The decrease in depletion and depreciation during the year ended December 31, 2013 compared to the year ended December 31, 2012 is due to a smaller depletion base resulting from production decline and impairments incurred during the twelve months ended December 31, 2012 .





For the year ended December 31, 2013 , $9.3 million of the depletion and depreciation recorded was from discontinued operations ( year ended December 31, 2012 - $10.8 million).





An impairment test is performed on capitalized property plant and equipment costs at a CGU level on an annual basis and quarterly when indicators of impairment exist.  During the year ended December 31, 2013 , Sonde recorded an impairment of $0.9 million ($0.6 million in the Northern Alberta CGU and $0.3 in the BC CGU) to reflect low natural gas prices.  During the year ended December 31, 2012 , Sonde recorded an impairment of $16.2 million ($12.1 million in the Southern Alberta CGU, $2.4 million in the Central Alberta CGU, and $1.7 million in the Northern Alberta CGU) to reflect low natural gas prices.





Impairments recognized during the year ended December 31, 2013 were calculated using a 14% discount rate.  Using a discount rate of 13% would have reduced the impairment by $0.1 million.  Using a discount rate of 15% would have increased the impairment by $0.1 million.  Impairments recognized during the year ended December 31, 2012 were calculated using an 11% discount rate.  Using a discount rate of 10% would have reduced the 2012 impairment by $5.8 million.  Using a discount rate of 12% would have increased the 2012 impairment by $5.2 million.





For the year ended December 31, 2013 , $0.9 million of the impairment recorded was from discontinued operations ( year ended December 31, 2012 - $16.2 million).





2013 Annual Consolidated Financial Statements |10


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Sensitivities





The following sensitivity analysis is provided to demonstrate the impact of changes in commodity prices on petroleum and natural gas sales for the year ended December 31, 2013 , and is based on the balances disclosed in this MD&A and the consolidated financial statements for the year ended December 31, 2013 :


(CDN$ thousands)Petroleum and Natural Gas SalesChange in average sales price for natural gas by $1.00/mcf2,792Change in the average sales price for oil and gas liquids by $1.00/bbl237Change in natural gas production by 1 mmcf/d1,239Change in crude oil and natural gas liquids production by 100 bbls/d5,130





General and administrative expenses


Q4Q3Q4Year ended December 31(CDN$ thousands, except where otherwise noted)20132013201220132012Gross general and administrative expense4,9403,0363,03414,46913,080Capitalized general and administrative expense(1,616)(864)(1,165)(3,875)(4,575)3,3242,1721,86910,5948,505General and administrative expense($/boe)(20.65)(11.64)(9.02)(15.09)(9.78)





For the three months ended December 31, 2013 , gross general and administrative (“G&A”) expenses increased to $4.9 million from $3.0 million during the three months ended September 30, 2013 and from $3.0 million during the three months ended December 31, 2012 .  The increase in G&A during the three months ended December 31, 2013 is due to increased professional fees, primarily related to the Western Canadian strategic alternatives process and the Marquee Transaction.





Gross G&A for the three months ended December 31, 2013 consists of $0.9 million related to North Africa and $4.0 million related to Western Canada administration and corporate head office costs.  Gross G&A for the three months ended September 30, 2013 consists of $0.5 million related to North Africa and $2.5 million related to Western Canada administration and corporate head office costs.  Gross G&A for the three months ended December 31, 2012 consists of $0.6 million relating to North Africa and $2.4 million related to Western Canada administration and corporate head office costs.





For the year ended December 31, 2013 , gross G&A expenses increased to $14.5 million from $13.1 million during the year ended December 31, 2012 .  Gross G&A consists of $2.6 million related to North Africa and $11.9 million related to Western Canada administration and corporate head office costs.  Gross G&A for the year ended December 31, 2012 consists of $3.0 million related to North Africa and $10.0 million related to Western Canada administration and corporate head office costs.





Share based compensation


Q4Q3Q4Year ended December 31(CDN$ thousands)20132013201220132012Stock option expense1,3621682552,047762Stock unit award expense961696619071Restricted share unit expense(77)11132(133)(177)Share based compensation1,3813481,0482,004656





Stock based compensation expense for the year ended December 31, 2013 was $2.0 million compared to $0.7 million for the year ended December 31, 2012 . The increase in stock based compensation during the year ended December 31, 2013 was due to the vesting and repricing of all outstanding stock options on December 31, 2013 as a result of the Marquee Transaction.





2013 Annual MD&A |11


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Income taxes





The Company’s current and future income taxes are dependent on factors such as production, commodity prices and tax classification of drilling costs related to exploration and development wells.  At December 31, 2013 , the Company has estimated $215.4 million in tax pools ( December 31, 2012 - $281.3 million ) including $151.2 million in non-capital losses ( December 31, 2012 - $137.4 million ) that are available for future deduction against taxable income.  Non-capital losses expire in the years 2026 – 2033.





(CDN$ thousands)December 31, 2013December 31, 2012Canadian exploration expense—56,802Canadian oil and gas property expense9,400—Canadian development expense—21,791Undepreciated capital costs14,85029,041Foreign exploration expense9,0134,354Non-capital losses151,245137,414Capital losses30,09430,094Share issue costs and other7481,767215,350281,263





Share capital





As a step in the Marquee Transaction, the common shares of Marquee received were distributed to Sonde's shareholders, resulting in a reduction to share capital of $16.9 million, and all outstanding common shares were consolidated on a 0.9 for 1 basis.





(CDN$ thousands)December 31, 2013December 31, 2012Number (thousands)AmountNumber (thousands)AmountOpening common shares outstanding and share capital56,071,313369,89256,071,313369,892Share consolidation and Marquee common share distribution pursuant to the Transaction with Marquee—(16,946)——56,071,313352,94656,071,313369,892





As at March 27, 2014 , the Company had 56,071,313 common shares and 4.5 million stock options issued and outstanding.





Interest rate risk





The Company is exposed to interest rate risk as the credit facilities bear interest at floating market interest rates.  The Company has no interest rate swaps or hedges to mitigate interest rate risk at December 31, 2013 .  The Company’s exposure to fluctuations in interest expense on its net loss and comprehensive income, assuming reasonably possible changes in the variable interest rate of +/- 1% is insignificant. This analysis assumes all other variables remain constant.





Credit risk





As at December 31, 2013 the Company’s allowance for doubtful accounts is $2.2 million (December 31, 2012 – $1.7 million ), of which $0.5 million is related to Western Canada.  This amount offsets $1.8 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago ( December 31, 2012 – $1.8 million ).  The Company considers all amounts greater than 90 days to be past due.  As at December 31, 2013 , $0.7 million of accounts receivable are past due, all of which are considered to be collectible ( December 31, 2012 - $0.9 million ).  The Company’s credit risk exposure is as follows:





2013 Annual MD&A |12


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(CDN$ thousands)December 31, 2013December 31, 2012Western Canada joint interest billings3,8992,310Revenue accruals and other receivables2,1552,373Accounts receivable6,0544,683Restricted cash213—Cash and cash equivalents33,95019,695Maximum credit exposure40,21724,378





Commodity price risk





The Company may enter into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility.  These financial instruments are entered into solely for risk mitigation purposes and are not used for trading or other speculative purposes.





In 2011, the Company sold a call option on a portion of the Company’s oil production from March 2011 through December 2012. The Company did not hold any such instruments at December 31, 2013 . The gains and losses associated with this instrument are as follows:





Year endedDecember 31, 2013December 31, 2012TermContractVolumeFixed PriceRealized (loss)Unrealized gainRealized (loss)Unrealized gainMarch 1, 2011 – December 31, 2012Call250 Bbls/d$100 $US/bbl——$(92)$781





Foreign exchange risk





The Company’s foreign exchange risk denominated in U.S. dollars is as follows:





(US$ thousands)December 31 2013December 31 2012Cash and cash equivalents11,1972,185Foreign denominated financial assets11,1972,185North Africa payables3,675566Foreign denominated financial liabilities3,675566





These balances are exposed to fluctuations in the Canadian and U.S. dollar exchange rate. At this time, the Company has chosen not to enter into any risk management agreements to mitigate foreign exchange risk. The Company’s exposure to foreign currency exchange risk, assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent is insignificant. This analysis assumes all other variables remain constant.





Liquidity risk





The Company generally relies on a combination of cash flow from operating activities and credit facility availability to fund its capital requirements and to provide liquidity for all operations.  As a result of the Marquee Transaction, the Company no longer generates cash flow from petroleum and natural gas sales, and the Company no longer has a material credit facility.  As such, subsequent to December 31, 2013, the Company must fund operations from working capital, new financings, farm-outs or property dispositions.





2013 Annual MD&A |13


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Disclosure controls and procedures and internal control over financial reporting





Disclosure controls and procedures are designed to provide reasonable assurance that material information is gathered and reported to senior management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding public disclosure.  Management, including the CEO and CFO, has evaluated the effectiveness of the Company’s disclosure control and procedures as of December 31, 2013. Based on this evaluation, Management concluded that the Company’s disclosure controls and procedures, as defined by the rules of the Canadian Securities Administrators, as of December 31, 2013 were effective. In addition, during the period beginning January 1, 2013 and ending December 31, 2013, there were no changes to the Company’s internal controls that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.





Management’s annual report on internal control over financial reporting





Management is responsible for establishing and maintaining adequate internal controls over financial reporting. Management has assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2013 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Company’s internal control over financial reporting. Based on this assessment, Management has assessed the effectiveness of the Company’s internal controls over financial reporting as at December 31, 2013 and has concluded that such controls were effective as at that date.





It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. In reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.





Off-balance sheet arrangements





The Company has no off-balance sheet arrangements.





Selected annual information





Twelve months ended December 31201320122011Petroleum & natural gas sales(1)24,73524,89634,592Net loss from continuing operations(2)(20,189)(31,974)(43,475)Net loss from continuing operations per share – basic and diluted(2) (3)(0.36)(0.57)(0.77)Net (loss) income(4)(54,075)21,483(40,571)Net (loss) income per share – basic and diluted(4)(0.96)0.38(0.72)Funds from (used for) operations(4) (5)1,294(1,317)7,597Funds from (used for) operations per share – basic and diluted(4) (5)0.02(0.02)0.14Total assets(4)94,508186,486186,887Total non-current financial liabilities(4) (6)1,33229,97226,344Working capital surplus (deficit) as at December 31, 2013(4)30,42617,187(20,907)


|    |                                                                                                                                                                                                                                                                 
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Petroleum and natural gas sales and realized gains on financial instruments net of royalties and transportation.  All petroleum and natural gas sales, realized gains on financial instruments , royalties and transportation relate to discontinued operations.

|    |                                                                                                                                                                                                                                                                                                   
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | 2011 net loss from continuing operations and net loss from continuing operations per share - basic and diluted have not been updated to reflect the completion of the Marquee Transaction and therefore include income and loss attributed to operations that have been subsequently discontinued.

|    |                                                                                                                                                                                 
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | All per share amounts presented in this table were calculated using the number of common shares outstanding on a post  0.9 for 1 consolidation basis (56,071,313 common shares).

|    |                                                                 
|--- | ----------------------------------------------------------------
|(4) | Includes both continuing operations and discontinued operations.

|    |                   
|--- | ------------------
|(5) | Non-IFRS measures.

|    |                           
|--- | --------------------------
|(6) | Decommissioning provision.




2013 Annual MD&A |14


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Quarterly financial summary





20132013201320132012201220122012($ thousands except per share and production amounts)Q4Q3Q2Q1Q4Q3Q2Q1ProductionNatural gas (mcf/d)7,0828,2447,4237,9348,9408,7579,66511,553Crude oil and natural gas liquids (bbl/d)589654622737761695745820Total (boe/d)1,7692,0281,8582,0592,2512,1552,3562,746Petroleum & natural gas sales(1)5,5746,4836,0716,6076,7925,6315,4876,986Net loss from continuing operations(9,179)(3,037)(3,057)(4,916)(3,195)(1,179)(23,003)(4,597)Net loss from continuing operations per share – basic and diluted(2)(0.16)(0.05)(0.05)(0.09)(0.06)(0.02)(0.41)(0.08)Net (loss) income(3)(39,407)(4,399)(4,857)(5,412)(3,870)(2,073)(28,030)55,456Net (loss) income per share – basic and diluted(3)(0.70)(0.08)(0.09)(0.10)(0.07)(0.04)(0.50)0.99Funds (used for) from operations(3)(4)(18)1,191593(472)123494(1,267)(667)Funds (used for) from operations per share – basic and diluted(3)(4)—0.020.01(0.01)—0.01(0.02)(0.01)


|    |                                                                                                                                                                                        
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Petroleum and natural gas sales and realized gains on financial instruments net of royalties and transportation. All petroleum and natural gas sales relate to discontinued operations.

|    |                                                                                                                                                                                 
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | All per share amounts presented in this table were calculated using the number of common shares outstanding on a post  0.9 for 1 consolidation basis (56,071,313 common shares).

|    |                                                                 
|--- | ----------------------------------------------------------------
|(3) | Includes both continuing operations and discontinued operations.

|    |                   
|--- | ------------------
|(4) | Non-IFRS measures.




Significant factors and trends that have impacted the Company’s results during the above periods include:





|  |                                                                                                                                                                                                     
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Revenue is directly impacted by the Company’s ability to replace existing production and add incremental production through its on-going workover, recompletion and capital expenditure program; and

|  |                                                                                                                                                                                                                                                                                        
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|• | Fluctuations in the Company’s petroleum and natural gas sales and net (loss) income from quarter to quarter are primarily caused by variations in production volumes, realized oil and natural gas prices and the related impact of royalties and impairments and subsequent reversals.

Please refer to the other sections of this MD&A for the detailed discussions on changes for the three months ending December 31, 2013 .





Significant accounting estimates and judgments





Significant estimates used in the preparation of the Financial Statements include, but are not limited to, those areas discussed below.





|    |                     
|--- | --------------------
|(a) | Oil and gas reserves




Certain depletion, depreciation, impairment and decommissioning and restoration charges are measured based on the Company’s estimate of oil and gas reserves. The estimation of reserves and resources is an inherently complex process and involves the exercise of professional judgment. Reserves and resources were evaluated at December 31, 2012 and 2011 by independent petroleum consultants in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, and are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook.  Oil and gas reserves and resources estimates are based on a range of geological, technical and economic factors, including projected future rates of production, estimated commodity prices, engineering data, and the timing and amount of future expenditures, all of which are subject to uncertainty. Assumptions reflect market and regulatory conditions existing at each annual reporting date, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.





2013 Annual MD&A |15


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The Company's reserves were not evaluated at December 31, 2013 by independent petroleum consultants due to the disposition of all reserves to Marquee as discussed above.





|    |                                 
|--- | --------------------------------
|(b) | Exploration and evaluation costs




Certain exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. The Company is required to make estimates and judgments about the future events and circumstances regarding the economic viability of extracting the underlying resources. The costs are subject to technical, commercial and management review to confirm the continued intent to develop and extract the underlying resources. Unsuccessful drilling, or changes to project economics, resource quantities, expected production techniques, production costs and required capital expenditures, are important factors when making this determination. If a judgment is made that the extraction of resources is not viable, the associated exploration and evaluation costs are impaired and charged to net income or loss.





|    |                                                 
|--- | ------------------------------------------------
|(c) | Decommissioning liabilities and other provisions




The Company recognizes liabilities for the future decommissioning and restoration of property, plant and equipment. These provisions are based on estimated costs, which take into account the anticipated method and extent of restoration, technological advances and the possible future use of the site. Actual costs are uncertain and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience and prices. The expected timing of future decommissioning and restoration may change due to certain factors, including reserve life. Changes to assumptions related to future expected costs, discount rates and timing may have a material impact on the amounts presented. Other provisions are recognized in the period in which it becomes probable that there will be a future cash outflow.





|    |                      
|--- | ---------------------
|(d) | Deferred income taxes




Deferred tax assets are recognized when it is considered probable that unused tax losses, tax credits and deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of tax laws in each jurisdiction differ significantly from the Company’s estimate, the ability of the Company to realize the deferred tax asset could be impacted.





Deferred tax liabilities are recognized for taxable temporary differences. The Company records a provision for the amount that is expected to be settled, which requires the application of judgment as to the ultimate outcome. Deferred tax liabilities could be impacted by changes in the Company’s estimate of the likelihood of a future outflow, the expected settlement amount, and the tax laws in the jurisdiction which the Company operates.





|    |                     
|--- | --------------------
|(e) | Impairment of assets




The allocation of assets into CGUs requires significant judgment and interpretations with respect to the geographical location, similar reservoir characteristics and development plans, integration between assets, the existence of active markets, similar exposure to market risks, discrete processing and gathering facilities versus shared infrastructures, and the way in which management monitors the operations.





The recoverable amounts of CGUs and individual assets have been determined based on value in use. The key assumptions the Company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes and future operating and development costs. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value.





|    |                         
|--- | ------------------------
|(f) | Share based compensation




Expenses recorded for share based compensation are based on the historical volatility of the Company’s share price which may not be indicative of the future volatility.





2013 Annual MD&A |16


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Supplemental environmental disclosures





The oil and gas industry is subject to extensive environmental laws and regulations from municipal, provincial, and federal jurisdictions. Compliance with emerging legislation may require significant expenditures and failure to comply may result in the issuance of shut-in or closure orders or the imposition of fines and penalties, which could be material. It is possible that the costs of future environmental compliance may have a material adverse effect on the Company’s financial condition. Environmental regulation provides for, among other things, restrictions and prohibitions on the generation, handling, storage, transportation, treatment, and disposal of hazardous substances and waste from spills, releases, or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells, facility sites, and other properties associated with the Company’s operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. Under environmental legislation, the Company, may be liable for personal injury, cleanup costs, remedial measures, and other environmental and property damages, as well as administrative, civil and criminal penalties.





Furthermore, future changes in environmental laws and regulations, including adoption of stricter standards or more stringent enforcement, could result in increased costs, incurred liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on the Company’s financial condition. As the Company’s operations and activities emit greenhouse gases, the Company may be subject to emissions targets and may subject the Company to legislation that will require


increasingly strict regulation with respect to emissions of greenhouse gases. Given the evolving nature of climate change action and regulation, it is not possible to predict the nature of future legislation with respect to climate change or the impact on the Company, its operations and financial condition at this time. The Company has not established a separate reclamation fund for the


purpose of funding estimated future environmental and reclamation obligations. Any site reclamation or abandonment costs or abandonment costs incurred in the ordinary course in a specific period will be funded out of cash flow from operations. It is not possible to predict the Company’s ability to fully fund the cost of all its future environmental, abandonment and reclamation obligations.


The Company is not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time, as opposed to sudden and catastrophic damages, is not available on economically reasonable terms. Accordingly, the Company’s properties may be subject to liability due to hazards that cannot be insured against or that have not been insured against due to prohibitive premium


costs or for other reasons.





Additional information





Additional information relating to the Company, including the Company’s annual information form, is filed on SEDAR and can be viewed at www.sedar.com.  Information can also be obtained by contacting the Company at Sonde Resources Corp., Suite 3100, 500 - 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6 and on the Company’s website at www.sonderesources.com.


2013 Annual MD&A |17