Exhibit 1.3
 MANAGEMENT'S DISCUSSION AND ANALYSIS
 
 This Management's Discussion and Analysis ("MD&A") has been prepared by management as of March 21, 2013, 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 with disclosure of oil and gas activities in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101").
 
 Effective January 1, 2011 the Company adopted International Financial Reporting Standards (“IFRS”). This MD&A should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ended December 31, 2012 and 2011.
 
 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 from 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:
 
 ·
business strategy, plans, priorities and planned exploration and development activities;
 ·
exploration potential relating to the Company’s Western Canadian properties;
 ·
expected sources of funding for the capital program, including the completion of the farm-out with Viking Energy North Africa Limited (“Viking”) which, upon closing, is anticipated to reduce the Company’s work commitments;
 ·
estimates of reserves and future net revenue associated therewith;
 ·
future costs, expenses and royalty rates and development, exploration and other expenses;
 ·
expected volume and product mix of the Company's oil and gas production and future oil and gas prices and interest rates in respect of the Company's commodity risk management programs;
 ·
the anticipated closing of the farm-out to Viking;
 ·
the proposed unitization of the Zarat field and development of an amended Zarat field unit plan of development;
 ·
the possible results of Sonde’s strategic alternatives process in Western Canada and the impact it may have on sources of funding for future exploration and development activities;
 ·
other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance; and
 ·
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 interim MD&A. The material risk factors include, but are not limited to:
  2012 Annual MD&A|1
  ·
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;
 ·
risks and uncertainties involving geology of oil and gas deposits;
 ·
uncertainty related to production, marketing and transportation;
 ·
availability of experienced service industry personnel and equipment;
 ·
availability of qualified personnel and the ability to attract or retain key employees or members of management;
 ·
the uncertainty of reserves estimates, reserves life and underlying reservoir risk;
 ·
the uncertainty of estimates and projections relating to production, costs and expenses;
 ·
potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
 ·
delays due to adverse weather conditions;
 ·
fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;
 ·
the outcome and effects of any future acquisitions and dispositions;
 ·
health, safety and environmental risks;
 ·
uncertainties as to the availability and cost of financing and changes in capital markets;
 ·
risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action);
 ·
risks associated with competition from other producers;
 ·
changes in general economic and business conditions;
 ·
the possibility that government policies or laws may change or government approvals may be delayed or withheld;
 ·
commercial risks relating to the closing of the Viking farm-out and the negotiation of the proposed unitization of the Zarat field; and
 ·
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”).
 2012 Annual MD&A|2
 Reserve Disclosures–Information concerning oil and gas reserves and contingent resources are deemed to be forward-looking information, as this information involves the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated.  Future net revenues disclosed herein do not represent fair market value.
 
 Business Overview and Strategy
 
 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 in Western Canada and offshore North Africa.
 
 Western Canada
 
 The Company derives all of its production and cash flow from operations in Western Canada. The Company’s Southern Alberta cash generating unit (“CGU”), (or Greater Drumheller, Alberta area), accounts for approximately 85% of the Company’s production.  The balance of production comes largely from the Kaybob/Windfall and Boundary Lake/Eaglesham areas in west-central Alberta. The Company’s Western Canadian oil and gas assets are primarily high potential, high working interest producing properties which are complemented by a portfolio of highly prospective undeveloped land positions throughout Greater Alberta.
 
 In February, 2012 Sonde sold 26,240 gross acres (24,383 net) in its Kaybob Duvernay play in Alberta for aggregate proceeds of $75 million, resulting in a net gain of $73.4 million. Sonde continues to accumulate undeveloped acreage in the Duvernay (95,742 acres net), Montney (44,488 acres net), Wabamun (50,736 acres net) and Detrital/Banff (46,677 acres net) plays. Of these lands, 85% have been purchased within the past 18 months, and as such, there are no land expiry issues. These land positions are typically large, consolidated and 100% working interest holdings with outstanding characteristics and growth potential. In the Duvernay, Montney and Wabamun plays, Sonde has identified approximately 216, 50 to 70 and 162 to 324 horizontal drilling locations in each play respectively.
 
 2012 Western Canada Drilling Program
 
 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 2012 and were subsequently tied in.
 
 During the twelve months ended December 31, 2012, Sonde spudded 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 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 proved plus probable (“2P”) oil reserves.
 
 Western Canada Strategic Alternatives Process
 
 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 financial advisor to the Board of Directors of Sonde, 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.
 2012 Annual MD&A|3
 North Africa
 
 During January 2012, the Company completed the shooting of 513 square kilometers of 3D seismic around two potential Zarat Field exploration well locations in accordance with the requirements of the Joint Oil Block Exploration and Production Sharing Agreement (“EPSA”).
 
 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 kilometers of 3D seismic in the Libyan sector 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 covering the Joint Oil Block. The farm-out agreement contains the terms as outlined in Contingencies and Commitments section (b) “North Africa exploratory well extension & farm-out”. As of the date hereof, the farm-out agreement has not closed and completion of this transaction is subject to a number of conditions.
 
 The success of the Company’s ongoing operations are dependent upon a number of factors, including but not limited to, the price of energy commodity products, the Company’s ability to manage price volatility, increasing production and related cash flows, controlling costs, availability of experienced service industry personnel and equipment, capital spending allocations, the ability to attract equity investment, the results of Sonde’s Western Canada strategic alternatives process, hiring and retaining qualified personnel and managing political and government risk, particularly with respect to its interests in North Africa.
  Operating netback and cash flow from (used for) operations
  ($ thousands)

($ per boe)Three months ended December 31

2012

2011

% change

2012

2011

% changePetroleum and natural gas sales

7,694

10,240

(25)

37.14

38.23

(3)Realized gain on financial instruments

--

508

(100)

--

1.90

(100)Transportation

(139)

(255)

(45)

(0.67)

(0.95)

(29)Royalties

(763)

(1,048)

(27)

(3.67)

(3.91)

(6)6,792

9,445

(28)

32.80

35.27

(7)Operating expense

(3,703)

(3,846)

(4)

(17.87)

(14.36)

24Well workover expense

(1,090)

(642)

70

(5.26)

(2.40)

119Operating netback(1)

1,999

4,957

(60)

9.67

18.51

(48)General and administrative

(1,869)

(2,529)

(26)

(9.02)

(9.44)

(4)Foreign exchange (loss) gain

(39)

602

(106)

(0.19)

2.25

(108)Interest and other income

46

342

(87)

0.22

1.28

(83)Interest expense

(14)

(217)

(94)

(0.07)

(0.81)

(91)Funds from operations(1)

123

3,155

(96)

0.61

11.79

(95)Decommissioning expenditures

(228)

(351)

(35)

(1.10)

(1.31)

(16)Changes in non-cash working capital

(1,235)

2,284

(154)

(5.96)

8.53

(170)Cash (used in) provided by operating activities(1)

(1,340)

5,088

(126)

(6.45)

19.01

(134)
 (1)
Non-IFRS measure.
  For the three months ended December 31, 2012, funds from operations was $0.1 million compared to funds from operations of $3.2 million for the same period in 2011. This was primarily the result of a 25% reduction in petroleum and natural gas revenue, consistent operating expense and a 70% increase in well workover expense incurred to address normal wear and tear on older wells.
 2012 Annual MD&A|4
  ($ thousands)

($ per boe)Twelve months ended December 31

2012

2011

% change

2012

2011

% changePetroleum and natural gas sales

28,873

39,495

(27)

33.20

38.70

(14)Realized (loss) gain on financial instruments

(92)

988

(109)

(0.11)

0.97

(111)Transportation

(599)

(1,042)

(43)

(0.69)

(1.02)

(32)Royalties

(3,286)

(4,489)

(27)

(3.78)

(4.40)

(14)24,896

34,952

(29)

28.62

34.25

(16)Operating expense

(14,209)

(13,473)

5

(16.34)

(13.20)

24Well workover expense

(2,960)

(2,054)

44

(3.40)

(2.01)

69Operating netback(2)

7,727

19,425

(60)

8.88

19.04

(53)General and administrative

(8,505)

(10,646)

(20)

(9.78)

(10.43)

(6)Foreign exchange (loss) gain

(411)

593

(169)

(0.47)

0.58

(181)Interest and other income

192

428

(55)

0.22

0.42

(48)Interest expense

(285)

(2,067)

(86)

(0.33)

(2.03)

(84)Income taxes

(35)

(136)

(74)

(0.04)

(0.13)

(69)Funds (used for) from operations(1,2)

(1,317)

7,597

(117)

(1.52)

7.45

(120)Decommissioning expenditures

(379)

(1,221)

(69)

(0.44)

(1.20)

(63)Changes in non-cash working capital

2,776

(1,268)

(319)

3.19

(1.24)

(357)Cash provided by operating activities(1)

1,080

5,108

(79)

1.23

5.01

(75)
 (1)
Table includes both continuing and discontinued operations. There were no petroleum and natural gas sales associated with discontinued operations, which consisted of nil (2011 – $1.5 million) general and administrative and nil (2011 – $0.4) interest expense.
 (2)
Non-IFRS measure.
 
 For the twelve months ended December 31, 2012, funds used for operations was $1.3 million compared to funds from operations of $7.6 million for the same period in 2011. This was primarily the result of a 27% reduction in petroleum and natural gas revenue and a 44% increase in well workover expense, offset by a 20% decrease in general and administrative expense and an 86% decrease in interest expense, as all bank debt was repaid in early 2011.
 
 Production
 
 Q4

Q3

Q4

Twelve months endedCommodity

2012

2012

2011

2012

2011Natural gas (mcf/d)

8,940

8,757

12,186

9,725

12,187Crude oil (bbls/d)

572

523

5877

554

538Natural gas liquids (bbls/d)

189

172

2933

202

227Total production (boe/d) (6:1)

2,251

2,155

2,9111

2,376

2,796
 
 Q4

Q3

Q4

Twelve months endedRegion

2012

2012

2011

2012

2011Southern Alberta (boe/d)

1,907

1,813

2,324

1950

2,158Central Alberta (boe/d)

203

194

276

256

311Other Western Canada (boe/d)

141

148

311

170

327Total production (boe/d) (6:1)

2,251

2,155

2,911

2,376

2,796
 
 For the three and twelve months ended December 31, 2012, production averaged 2,251 boe/d and 2,376 boe/d, respectively. The three month increase in production during the period ended December 31, 2012 is due to shut-in gas wells being brought online.  The twelve month decrease in production during the period ended December 31, 2012 is due to decreased gas volumes due to natural decline, the shut-in of gas wells, decreased production from initial flow rates in the Mannville “I” wells in Drumheller, and significant third-party outages in both Southern and Central Alberta.
 2012 Annual MD&A|5
  Petroleum and natural gas sales
 
 Q4

Q3

Q4

Year

Year($ thousands, except where otherwise noted)

2012

2012

2011

2012

2011Petroleum and natural gas salesNatural gas

2,882

1,901

3,895

8,942

16,868Crude oil

3,834

3,708

4,956

15,620

17,431Natural gas liquids

978

827

1,389

4,311

5,196Transportation

(139)

(145)

(255)

(599)

(1,042)Royalties

(763)

(660)

(1,048)

(3,286)

(4,489)Realized gain (loss) on commodity derivatives

--

--

508

(92)

988Total

6,792

5,631

9,445

24,896

34,952Average sales price (including commodity derivatives)Natural gas ($/mcf)

3.50

2.36

3.93

2.51

4.04Crude oil ($/bbl)

72.69

77.09

91.73

76.62

88.22Natural gas liquids ($/bbl)

56.35

52.24

51.64

58.38

62.79Average sales price ($/boe)

37.14

32.46

40.13

33.09

39.67AECO 5a ($/mcf)

3.59

2.34

3.29

2.45

3.49Edmonton Light ($/bbl)

84.25

86.08

97.71

86.86

95.56
 
 For the three months ended December 31, 2012, petroleum and natural gas sales, net of transportation and royalties was $6.8 million, consisting of $2.9 million in natural gas, $3.8 million in crude oil and $1.0 million in natural gas liquids sales, less $0.1 million of transportation costs and $0.8 million of royalties. The Company realized an average sales price of $37.14 per boe during the three months ended December 31, 2012 compared to $32.46 per boe in the three months ended September 30, 2012, and $40.13 in the three months ended December 31, 2011, exclusive of royalties and transportation.
 
 For the twelve months ended December 31, 2012, petroleum and natural gas sales, net of transportation and royalties was $24.9 million, consisting of $8.9 million in natural gas, $15.6 million in crude oil and $4.3 million in natural gas liquids sales, less $0.6 million of transportation costs, $3.3 million of royalties and $0.1 million in realized losses on commodity derivatives. The Company realized an average sales price of $33.09 per boe during the twelve months ended December 31, 2012, compared to $39.67 per boe for the same period in 2011, exclusive of royalties and transportation, representing a decrease of 16.6%.
 
 Royalties
 
 Three months ended

December 31

Twelve months ended

December 31($ thousands, except where otherwise noted)

2012

2011

2012

2011RoyaltiesCrown

519

713

2,362

3,572Freehold and overriding

244

335

924

917Total

763

1,048

3,286

4,489Royalties per boe ($)

3.68

3.91

3.78

4.40Average royalty rate (%)

9.9

10.0

11.4

11.4
 
 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.
 2012 Annual MD&A|6
 In addition, various items impact the average royalty rate paid, such as cost of service credits and other royalty credit programs.
 
 Royalties on horizontal gas wells drilled in Alberta in 2011 and 2012 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.
 
 Natural gas and liquids royalties for the three months ended December 31, 2012 were $0.8 million or 9.9% of total petroleum and natural gas sales compared to 10.0% in 2011. Royalties for twelve months ended December 31, 2012 were $3.3 million or 11.4% of total petroleum and natural gas sales compared to 11.4% in 2011.
 
 Operating and well workover expense
 
 Combined operating and well workover expenses for the three months ended December 31, 2012 were $4.8 million or $23.13 per boe, compared to $4.5 million or $16.76 per boe for the same period in 2011. Combined operating and well workover expenses for the twelve months ended December 31, 2012 were $17.2 million or $19.74 per boe, compared to $15.5 million or $15.21 per boe for the same period in 2011. The increase from 2011 to 2012 is attributable to additional workovers, turnarounds and maintenance being performed in the Southern CGU.
 
 Capital expenditures
 
 Three months ended

December 31

Twelve months ended

December 31($ thousands)

2012

2011

2012

2011Acquisitions

--

153

--

6,242Exploration and evaluation

141

2,353

4,630

11,326Drilling and completions

(246)

9,828

15,140

30,485Plants, facilities and pipelines

1,476

2,559

5,126

6,216Land and lease

1,039

3,316

6,288

5,281Capital well workovers

657

550

1,822

858Capitalized general and administrative expenses

1,165

898

4,575

3,312Capital expenditures

4,232

19,657

37,581

63,720Trinidad disposition

--

--

--

(87,908)Western Canada dispositions

(250)

(501)

(75,229)

(501)North Africa farm-out proceeds

(995)

--

(995)

--Western Canada exploration and evaluation impairment, charged to exploration expense

(227)

(159)

(1,748)

(1,270)Net capital expenditures

2,760

18,997

(40,391)

(25,959)
 
  2012

2011

2012

2011($ thousands)

Continuing operationsCanada

3,079

16,381

(46,988)

48,289North Africa

(199)

2,436

6,413

12,182Corporate Assets

(120)

180

184

9132,760

18,997

(40,391)

61,384Discontinued operationsTrinidad and Tobago

--

--

--

(87,343)Net capital expenditures

2,760

18,997

(40,391)

(25,959)
  2012 Annual MD&A|7
  Continuing operations
 
 Western Canada
 
 In February, 2012 Sonde sold 26,240 gross acres (24,383 net) in its Kaybob Duvernay play in Alberta for aggregate proceeds of $75 million, resulting in a net gain of $73.4 million. Sonde continues to accumulate undeveloped acreage in the Duvernay (95,742 acres net), Montney (44,488 acres net), Wabamun (50,736 acres net) and Detrital/Banff (46,677 acres net) plays. Of these lands, 85% have been purchased within the past 18 months, and as such, there are no land expiry issues.
 
 2012 Western Canada Drilling Program
 
 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 and were subsequently tied in.
 
 During the twelve months ended December 31, 2012, Sonde spudded 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 workovers 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.
 
 North Africa
 
 During the twelve months ended December 31, 2012, the Company capitalized $6.4 million of costs related to the North Africa operation.  These costs related to the acquisition and processing of 513 square kilometers of 3-D seismic ($3.4 million), pre-drilling planning costs ($0.9 million) and capitalized general and administrative costs ($3.1 million), offset by $1.0 million of farm-out proceeds.
 
 Discontinued operations
 
 Trinidad and Tobago / LNG Project
 
 On December 22, 2010 the Company entered into an agreement to sell its remaining 25% interest in Block 5(c) and the Mayaro-Guayaguayare block (“MG Block”) exploration and production license for an aggregate purchase price of US$87.5 million plus interest on the outstanding balance prior to closing. The transaction closed on June 22, 2011 for gross proceeds of US$78.1 million and the assumption of the Company’s performance guarantee provided for the MG Block of US$12.0 million.
 
 On December 15, 2011, the Government of Trinidad and Tobago granted the Company’s request to transfer the MG Block and the related performance guarantee to the purchaser in accordance with the terms of the purchase agreement.
 
 The Trinidad and Tobago assets and the LNG Project were designated as held for sale at December 31, 2010, meaning general and administrative costs incurred in 2011 no longer met the criteria for capitalization. During the twelve months ended December 31, 2011, the Company incurred $0.6 million related to continued joint venture transactions with the operator of Block 5(c). No expenditures were incurred in 2012.
 2012 Annual MD&A|8
  Proceeds from disposition


(CDN$ thousands)Cash received


56,877Debenture retired


19,898MG Block Performance Guarantee Assumed By Purchaser


11,716Transaction costs


(583)Net proceeds


87,908Net assets disposed at carrying valueExploration and evaluation assets


79,664Asset retirement obligation


(3,040)Net assets


76,624Gross gain on disposition


11,284Realized foreign currency translation reserve


(5,975)Net gain on disposition


5,309
  Change in proved and probable reserves and impairment
 
 millions

NPV @ 10%

NPV @ 12%

BOE

% LiquidsOpening reserves (December 31, 2011)

$ 113.6

$ 104.2

9.5

27%Production





(0.9)Additions and revisions





0.8Closing Reserves (December 31, 2012)

$ 109.0

$ 98.1

9.4

37%
 
 The Company’s 2012 drilling program focused on oil and liquids rich targets, shifting the ending reserve mix from 27% to 37% liquids. The Company’s 2012 independent reserve report included a 46% increase in proved and probable oil reserves, from 1,983 Mbbl of working interest oil at year-end 2011 to 2,893 Mbbl at year-end 2012.
  This increase is attributable primarily to a significant addition of probable oil reserves for the Mannville “I” pool waterflood, which was initiated by the Company with a five well pilot project in early 2012. Oil reserves have also increased due to drilling efforts in the Michichi Detrital/Banff pool, and the Montney exploration well drilled at Ante Creek North.
  The Company’s 2012 proved and probable natural gas reserves declined 14%, from 41,518 mmcf of working interest gas at year-end 2011 to 35,553 mmcf of gas at year-end 2012. This decrease is attributable to a combination of lower forecast natural gas prices and other economic factors, plus a decreased emphasis in 2012 on gas-oriented projects.
  Impairment tests were carried out at December 31, 2012 and were based on fair value less costs to sell calculations, using the following forward commodity price projections:
 2012 Annual MD&A|9
  Year

AECO Gas (Cdn/mmbtu)(1)

Edmonton Light Sweet Crude Oil (Cdn/bbl)(1)2013

3.38

85.002014

3.83

91.502015

4.28

94.002016

4.72

96.502017

4.95

96.502018

5.22

96.502019

5.32

97.542020

5.43

99.512021

5.54

101.522022

5.64

103.57Remainder(2)

2.0%

2.0%(1)Source: Independent qualified reserves evaluator’s price forecast, effective January 1, 2013.(2)Percentage change represents the change in each year after 2022 to the end of the reserve life.
 
 An impairment test is performed on capitalized property and equipment costs at a CGU level on an annual basis and quarterly when indicators of impairment exist.  During the year ended December 31, 2012, the Company recognized an impairment of $16.2 million (December 31, 2011 – $34.3 million) to property, plant and equipment to reflect changes in reserves and the low natural gas price environment for future production.
 
 The impairments recorded during the year ended December 31, 2012 were recorded in the Southern Alberta, Central Alberta and Northern Alberta CGUs, as follows:
 
 (CDN$ millions)

December 31

2012

December 31

2011Southern Alberta CGU

4.6

20.1Central Alberta CGU

9.6

13.5Northern Alberta CGU

2.0

0.5British Columbia CGU

--

0.216.2

34.3
 
 The December 31, 2012 impairment was recognized using an 11% discounted cash flow (December 31, 2011 – 12%).  Using a discount rate of 10% would reduce 2012 impairment by $5.8 million.  Using a discount rate of 12% would increase 2012 impairment by $5.2 million.
 
 Depletion and depreciation
 
 For the three months ended December 31, 2012 depletion and depreciation was $2.7 million or $13.11 per boe compared to $4.3 million or $15.88 per boe for the same period in 2011. The calculation of depletion and depreciation included an estimated $22.7 million (December 31, 2011 - $11.0 million) for future development capital associated with proved plus probable undeveloped reserves and excluded $56.5 million (December 31, 2011 – $69.0 million) related to exploration and evaluation assets.
 
 For the twelve months ended December 31, 2012 depletion and depreciation was $11.0 million or $12.68 per boe compared to $14.9 million or $14.61 per boe for the same period in 2011. The variance for the twelve months is caused by a lower depletion base due to asset impairments in the first and second quarters of 2012.
  2012 Annual MD&A|10
 
 General and administrative expenses
  Three months ended

December 31

Twelve months ended

December 31($ thousands, except where otherwise noted)

2012

2011

2012

2011Continuing operationsGross general and administrative expense

3,034

3,410

13,080

12,436Capitalized general and administrative expense

(1,165)

(898)

(4,575)

(3,312)1,869

2,512

8,505

9,124Discontinued operationsGross general and administrative expense

--

17

--

1,522Capitalized general and administrative expense

--

--

--

----

17

--

1,522Total net general and administrative expense

1,869

2,529

8,505

10,646General and administrative expense ($/boe)

9.02

9.44

9.78

10.43
 
 Continuing operations
 
 For the three months ended December 31, 2012, gross general and administrative (“G&A”) expenses for continuing operations decreased to $3.0 million from $3.4 million for the same period in 2011. Gross G&A for continuing operations consists of $0.6 million (2011 – $0.4 million) relating to North Africa and $2.4 million (2011 – $3.0 million) related to Western Canada administration and corporate head office. The decrease is due to cost management initiatives and a reduction of employees in 2012.
 
 For the twelve months ended December 31, 2012, gross G&A expenses for continuing operations increased to $13.1 million from $12.4 million in 2011. Gross G&A for continuing operations consists of $3.0 million (2011 – $1.8 million) relating to North Africa and $10.1 million (2011 – $10.6 million) related to Western Canada administration and corporate head office.
 
 Discontinued operations
 
 For the three and twelve month periods ended December 31, 2012, gross G&A expenses from discontinued operations decreased to nil and nil, from nil and $1.5 million respectively in 2011. Costs declined due to the sale of the Trinidad and Tobago assets on June 22, 2011and the sale of the LNG Project on February 22, 2011. There were no such sales in 2012.
 
 Share based compensation
 
 Three months ended

December 31

Twelve months ended

December 312012

2011

2012

2011Stock option expense

255

455

762

2,810Stock unit award expense

661

573

71

1,425Restricted share unit expense

132

143

(177)

493Share based compensation

1,048

1,171

656

4,728
 
 Stock option expense for the year ended December 31, 2012 was $0.8 million (December 31, 2011 – $2.8 million). The reduction was due to a decline in the Company’s share price during 2012.
 
 At December 31, 2012, the Company had 1.2 million (December 31, 2011 – 1.5 million) stock unit awards outstanding, issued to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the applicable vesting date. The stock units have time and/or share based performance vesting terms which vary depending on whether the holder is an executive officer or director.
 2012 Annual MD&A|11
 If subsequent to the grant date, the shareholders of the Company approve an equity compensation plan under which the stock units may be paid with common shares of the Company, then the Board may determine that the stock units may be paid in cash or common shares. As of December 31, 2012, the Company recorded a liability of $0.9 million to recognize the fair value of the vested stock units (December 31, 2011 - $2.0 million).
 
 During the year ended December 31, 2012, the Company paid $1.1 million to settle awards held by officers,  current and former directors (December 31, 2011 - nil).  In addition, during the year ended December 31, 2012, an officer forfeited awards valued at $0.2 million (December 31, 2011 - nil).
 
 The Restricted Share Unit Plan became effective on March 24, 2011, to attract and retain experienced personnel with incentive compensation tied to shareholder return. Under the plan, each grantee will be entitled to, in respect of each Restricted Share Unit (“RSU”), a cash amount equal to the fair market value of one common share in the capital of the Company on such vesting date, with the vesting subject to a minimum floor share price and/or the lapse of time. During the year ended December 31, 2012, 66,666 RSUs were redeemed for a total of $0.1 million (December 31, 2011 – nil).
 
 Liquidity and capital resources
 
 December 31

December 31($ thousands)

2012

2011Cash and cash equivalents

19,695

3,743Accounts receivable

4,683

7,436Prepaid expenses and deposits

733

1,528Accounts payable and accrued liabilities

(6,850)

(17,655)Stock based compensation liability

(1,074)

(2,448)Provisions

--

(12,730)Derivative  financial  liabilities

--

(781)Working capital surplus (deficit)

17,187

(20,907)
 
 At December 31, 2012, the Company had $19.7 million in cash and cash equivalents (December 31, 2011 – $3.7 million). 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, and by the proceeds from the sale of Trinidad and Tobago assets in 2011, which resulted in a gain of $5.3 million.
 
 As at December 31, 2012, the Company had working capital of $17.2 million (December 31, 2010 – $20.9 million deficit) and had issued two letters of credit for $0.2 million (December 31, 2011 – two letters of credit of $0.1 million) against the $30.0 million (December 31, 2011 - $40.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75% as at December 31, 2012 and at December 31, 2011.
 
 Credit Facility A is 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. Credit Facility A has covenants, as defined in the Company’s credit agreement, that require the Company to maintain an adjusted working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative and capital expenditures are funded from cash flow, equity and proceeds from foreign asset sales. The Company can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility.
 
 On February 22, 2011, the Company obtained an additional $20.0 million development demand loan (“Credit Facility B”) at a variable interest rate of 50 basis points above the variable interest rate on Credit Facility A. Credit Facility B was to be used to assist in the acquisition of producing petroleum and natural gas reserves and/or development of proved producing/undeveloped petroleum and natural gas reserves. On August 16, 2011, the Company repaid the $6.3 million balance on the loan.
 2012 Annual MD&A|12
 On October 12, 2011, the Company cancelled this facility in order to reduce standby fees. Subject to availability and review, Credit Facility B can be reopened should the Company require access to additional debt financing. As at December 31, 2012 and December 31, 2011 the Company was in compliance with all of its debt covenants. The Company is subject to the next semi-annual review of its credit facilities on or before May 1, 2013.
 
 The Company’s cash flow from operations is directly related to underlying commodity prices and production volumes. A significant decrease in commodity prices or production volumes could materially impact the Company's future cash flow from operations and liquidity. In addition, a substantial decrease in commodity prices or production volumes could impact the Company’s borrowing base under its credit facilities, therefore reducing funds available for Western Canada investment, and in some instances, requiring a portion of the credit facilities to be repaid. The Company currently has no risk management contracts to mitigate commodity prices. Management continues to review various other risk mitigating options.
 
 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 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 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.
 
 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.
 
 Contingencies and commitments
 
 (a)
North Africa EPSA
  On August 27, 2008, the Company entered into the EPSA. The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, the Company is the operator. Under the EPSA, the minimum work program for the first phase (four years) of the seven year exploration period includes the Zarat North – 1 appraisal well, three exploration wells and 500 square kilometres of 3D seismic.
  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 to secure its minimum work program obligations. The potential cost of drilling the three wells could exceed US$100.0 million.
  In January 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North – 1 well. In December 2011, the Company commenced the acquisition of 513 square kilometres of 3D seismic in accordance with the requirements of the EPSA and completed the acquisition in January 2012.
 2012 Annual MD&A|13
 On January 30, 2012, the Company engaged an advisor to identify and evaluate alternatives to finance the Company’s remaining North Africa obligations. New information obtained during the process adversely impacted the available financing alternatives and delayed the outcome and drilling of the three exploratory wells. The Company recorded an impairment of $21.0 million to the Joint Oil Block during the six months ended June 30, 2012, charged to exploration and evaluation expense. This was a result of the following information obtained during the second quarter of 2012:
  ·
Inert and Acid Gas Initiative –On June 12, 2012, 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 is focused on early development of the Sonde Zarat Discovery, which contains approximately 60% inert and acid gases. This initiative will ensure that the Zarat Plan of Development and other developments in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments vis-à-vis international organizations like the Kyoto Accord on greenhouse gas emissions. This study is anticipated to take eighteen months.
  ·
Drilling Rig Availability –The initial results indicated that the global demand for offshore drilling units was higher in other parts of the world than North Africa. During the period ended September 30, 2012, one contractor submitted a bid for a technically acceptable jack up drilling rig that would have been available in the second quarter of 2013. The commercial terms of their offer were unacceptable to Sonde.
  ·
Unitization and Plan of Development –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 Entreprise 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.
  ·
Exploratory Well Obligations –The Company planned to discuss with Joint Oil the timing of the three well exploratory commitment due to lack of availability of a suitable drilling rig and pending resolution of the inert and acid gases sequestration issue. Neither the Company nor interested parties could find merit in an additional discovery of high inert and acid gases at this time without a clear commercialization path that includes a solution to this issue. As discussed below, on December 24, 2012 the Company received an extension on its exploratory well obligations until December 23, 2015.
  (b)
North Africa exploratory well extension & farm-out
  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 kilometers of 3D seismic in the Libyan sector 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 covering the Joint Oil Block. The farm-out agreement contains the following terms:
 2012 Annual MD&A|14
  ·
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 and credited against exploration and evaluation assets, 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 3D seismic data 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 Viking expenditures, the revenue will be split 33.33% to Sonde and 66.67% to Viking;
 ·
Sonde retains the option 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 pending farm-out agreement is subject to the following conditions:
 
 ·
Viking (or one of its affiliates) provides Sonde with a corporate guarantee sufficient to offset the current US$45 million guarantee for the potential penalties in respect of the three well drilling commitment and 3D seismic; 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.
  (c)
Zarat Unit Plan of Development
  Viking and Sonde are preparing an amended Unit Plan of Development to Joint Oil. The unit production will be shared on an initial fifty – fifty allocation with the license holder to the south until such time as the last development wells are drilled and a redetermination of unit ownership can be established on a permanent basis, at which time all costs, expenses and production will be adjusted accordingly between the unit parties. This Plan of Development utilizes a Floating Production Storage and Offloading vessel (“FPSO”), 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 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 the Fisal prospect (if proven productive), which is outside of the unit area, 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.
 
 (d)
Commitments and financial liabilities
  At December 31, 2012, the Company has committed to future payments over the next five years and thereafter, as follows:
 2012 Annual MD&A|15
  2013

2014

2015

2016

Thereafter

TotalAccounts payable and accrued liabilities

6,850

--

--

--

--

6,850Stock based compensation liability

1,074

--

--

--

--

1,074North Africa exploration commitments

16,514

14,924

14,924

--

--

46,362Office rent

1,212

1,212

1,217

1,233

7,159

12,03325,650

16,136

16,141

1,233

7,159

66,319
 
 Subsequent to the year ended December 31, 2012, the Company entered into an office sublease with a third party. The sublease is intended to reduce the future obligations of the Company. The terms of the arrangement dictate that the Company will retain half of its office space until 2015, at which time the entire lease will become the responsibility of the third party. The sublease reduces the future obligations of the company by $9.2 million from 2015 onward.
 
 The Company generally relies on a combination of cash flow from operating activities, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for domestic and international operations.
  (e)
Swap agreement
  At the time it entered into the North Africa EPSA, the Company also signed a "Swap Agreement" awarding an overriding royalty interest and optional participating interest to Joint Oil in the Company's "Mariner" Block, offshore Nova Scotia, Canada. No well was drilled on the Mariner Block and Joint Oil had the right to put back the overriding royalty to the Company for US$12.5 million. Joint Oil exercised its put rights and the Company made a payment of US$12.5 million on January 15, 2012. Prior to the payment, the Company confirmed that the EPSA remains in full force and effect.
 
 (f)
Litigation and claims
  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.
  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, 2012, the Company has estimated $281.3 million in tax pools (2011 - $349.2 million) including $137.4 million in non-capital losses (2011 - $98.4 million) that are available for future deduction against taxable income. Non-capital losses expire in the years 2026 – 2032.
  2012

2011Canadian exploration expense

56,802

57,861Canadian oil and gas property expense

--

49,230Canadian development expense

21,791

45,579Undepreciated capital costs

29,041

29,945Foreign exploration expense

4,354

34,163Non-capital losses

137,414

98,429Capital losses

30,094

30,234Share issue costs and other

1,767

3,726281,263

349,167
 
 Share capital
  As at March 22, 2012, the Company had 62,301,446 common shares and 4,728,691 stock options issued and outstanding.
 2012 Annual MD&A|16
  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, 2012, and is based on the balances disclosed in this MD&A and the consolidated financial statements for the year ended December 31, 2012:
  ($ thousands)

Petroleum and Natural Gas Sales(1)Change in average sales price for natural gas by $1.00/mcf

3,559Change in the average sales price for oil and gas liquids by $1.00/bbl

277Change in natural gas production by 1 mmcf/d (2)

916Change in crude oil and natural gas liquids production by 100 bbls/d (2)

4,254
 (1)
Reflects the change in petroleum and natural gas sales for the twelve months ended December 31, 2012.
 (2)
Reflects the change in production multiplied by the Company’s average sales prices for the twelve months ended December 31, 2012.
 
 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, 2012. 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
 
 The Company’s allowance for doubtful accounts is currently $1.7 million (December 31, 2011 – $2.0 million). This amount offsets $1.8 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2011 – $1.8 million) and nil of Western Canada joint interest and miscellaneous receivables (December 31, 2011 – $0.2 million). The Company considers all amounts greater than 90 days to be past due. As at December 31, 2012, $0.9 million of accounts receivable are past due, all of which are considered to be collectible (December 31, 2011 - $0.5 million).
 
 December 31

December 31(CDN$ thousands)

2012

2011Western Canada joint interest billings

2,310

2,830Goods and Services Tax receivable

--

740North Africa recoverable expenses

--

113Revenue accruals and other receivables

2,373

3,753Accounts receivable

4,683

7,436Cash and cash equivalents

19,695

3,743Maximum credit exposure

24,378

11,179
 
 Commodity price risk
 
 The Company enters 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 entered into a commodity swap contract from March to December on a portion of the Company’s natural gas production. In return for this fixed price the Company sold a call option on a portion of the Company’s oil production from March 2011 through December 2012. There are no commodity sales agreements or derivative financial instruments currently in place.
 2012 Annual MD&A|17
  Year ended







December 31, 2012

December 31, 2011Term

Contract

Volume

Fixed Price

Realized gain

(loss)

Unrealized gain

(loss)

Realized gain

(loss)

Unrealized gain

(loss)March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

--

--

$1,093

--March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($92)

$781

($105)

($781)
 
 Foreign exchange risk
 
 The Company is exposed to foreign currency fluctuations as oil and gas prices received are referenced to U.S. dollar denominated prices. The Company’s foreign exchange risk denominated in U.S. dollars is as follows:
 
 December 31

December 31(US$ thousands)

2012

2011Cash and cash equivalents

2,184

1,020North Africa receivables

1

111Foreign denominated financial assets

2,185

1,131
 
 December 31

December 31(US$ thousands)

2012

2011North Africa payables

566

1,720Mariner swap provision

--

12,500Foreign denominated financial liabilities

566

14,220
 
 These balances are exposed to fluctuations in the U.S. dollar. 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 on its comprehensive income assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent is $0.2 million. This analysis assumes all other variables remain constant.
 
 Liquidity Risk
 
 The Company generally relies on a combination of cash flow from operations, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for operations. At December 31, 2012, the Company has committed to future payments over the next five years, as follows:
 
 2013

2014

2015

2016

Thereafter

TotalAccounts payable and accrued liabilities

6,850

--

--

--

--

6,850Stock based compensation liability

1,074

--

--

--

--

1,074North Africa exploration commitments

16,514

14,924

14,924

--

--

46,362Office rent

1,212

1,212

1,217

1,233

7,159

12,03325,650

16,136

16,141

1,233

7,159

66,319
 
 Subsequent to the year ended December 31, 2012, the Company entered into an office sublease with a third party. The sublease is intended to reduce the future obligations of the Company. The terms of the arrangement dictate that the Company will retain half of its office space until 2015, at which time the entire lease will become the responsibility of the third party. The sublease reduces the future obligations of the company by $9.2 million from 2015 onward.
 
 Related party transactions
  During the year ended December 31, 2012, in the normal course of business, the Company purchased $0.2 million of processing services (December 31, 2011 – $0.1 million) from a company with a common director.
 2012 Annual MD&A|18
 These services were purchased under normal industry terms and have been measured and disclosed at their settlement value. As of December 31, 2012 and December 31, 2011, there were no amounts outstanding in accounts payable to this service provider.
  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, 2012. 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, 2012 were effective. In addition, during the period beginning January 1, 2012 and ending December 31, 2012, 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, 2012 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, 2012 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
 
 ($ thousands except per share and production amounts)
 Twelve months ended December 31

2012

2011

2010Petroleum & natural gas sales (2)

24,896

34,952

34,132Net income (loss) from continuing operations

21,483

(43,475)

(66,906)Net income (loss) from continuing operations per share – basic

0.34

(0.70)

(1.09)Net income (loss)(1)

21,483

(40,571)

(100,224)Net loss per share – basic and diluted(1)

0.34

(0.65)

(1.64)Funds (used for) from operations (3)

(1,317)

7,597

6,549Funds (used for) from operations per share – basic and diluted (3)

(0.02)

0.12

0.03Total assets

186,486

186,887

264,692Short term debt

--

--

35,048Production (boe/d)

2,376

2,796

2,870Operating netback ($/boe)

8.88

19.04

20.14
 (1)
This table includes both continuing operations and discontinued operations.
 (2)
Petroleum and natural gas sales and realized gains on financial instruments net of royalties and transportation.
 (3)
Non-IFRS measures.
 2012 Annual MD&A|19
 
 Quarterly financial summary
 
 ($ thousands except per share and production amounts)
 2012

2012

2012

2012

2011

2011

2011

2011Q4

Q3

Q2

Q1

Q4

Q3

Q2

Q1ProductionNatural gas (mcf/d)

8,940

8,757

9,665

11,553

12,186

12,673

11,509

12,377Crude oil and natural gas liquids (bbl/d)

761

695

745

820

880

834

666

677Total (boe/d)

2,251

2,155

2,356

2,746

2,911

2,946

2,584

2,740Petroleum & natural gas sales (2)

6,792

5,631

5,487

6,986

9,445

9,011

7,747

8,749Net (loss) income from continuing operations

(3,870)

(2,073)

(28,030)

55,456

(36,483)

(847)

(1,110)

(5,035)Net (loss) income from continuing operations per share – basic and diluted

(0.01)

(0.03)

(0.45)

0.89

(0.58)

(0.01)

(0.02)

(0.08)Net (loss) income(1)

(3,870)

(2,073)

(28,030)

55,456

(36,500)

(591)

2,781

(6,261)Net (loss) income per share – basic and diluted(1)

(0.01)

(0.03)

(0.45)

0.89

(0.58)

(0.01)

0.04

(0.10)Funds from (used for)operations (3)

123

494

(1,267)

(667)

3,155

1,945

853

1,644Funds from (used for) operations per share – basic and diluted (3)

0.01

0.01

(0.02)

(0.01)

0.05

0.03

0.01

0.03
 (1)
This table includes both continuing operations and discontinued operations.
 (2)
Petroleum and natural gas sales and realized gains on financial instruments net of royalties and transportation.
 (3)
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.
 ·
Fluctuations in the Company’s petroleum and natural gas sales and net income (loss) 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 and twelve months ending December 31, 2012.
 
 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.
 2012 Annual MD&A|20
 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.
 
 Significant accounting estimates and judgments
  The timely preparation of the condensed consolidated financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant estimates used in the preparation of the financial statements include, but are not limited to, those areas discussed below.
 
 Oil and gas reserves and resources
 
 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 is an inherently complex process and involves the exercise of professional judgment. Reserves have been evaluated at December 31, 2012 and December 31, 2011 by independent petroleum consultants in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The reserves and resources estimates 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.
 
 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.
 2012 Annual MD&A|21
 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.
 
 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 existing 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.
 
 Impairment of assets
 
 The allocation of assets into CGUs requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, 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.
 
 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. Accordingly, those amounts are subject to measurement uncertainty.
 
 Future accounting changes
 
 The Company has reviewed new and revised accounting pronouncements that have been issued but are not yet effective and determined that the following may have an impact on the Company:
 
 As of January 1, 2015, the Company will be required to adopt IFRS 9 “Financial Instruments”, which is the result of the first phase of the International Accounting Standards Board (“IASB”) project to replace IAS 39 “Financial Instruments: Recognition and Measurement”. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. Portions of the standard remain in development and the full impact of the standard on the Company’s Consolidated Financial Statements will not be known until the project is complete.
 2012 Annual MD&A|22
 In May 2011, the IASB released the following new standards: IFRS 10, “Consolidated Financial Statements”, IFRS 11, “Joint Arrangements”, IFRS 12, “Disclosures of interests in other entities” and IFRS 13, “Fair Value Measurement”. Each of these standards is to be adopted for fiscal years beginning January 1, 2013 with earlier adoption permitted. A brief description of each new standard follows below:
 
 ·
IFRS 10, “Consolidated Financial Statements” supersedes IAS 27 “Consolidation and Separate Financial Statements” and SIC-12 “Consolidation – Special Purpose Entities”. This standard provides a single model to be applied in control analysis for all investees including special purpose entities.
 ·
IFRS 11, “Joint Arrangements” divides joint arrangements into two types, joint operations and joint ventures, each with their own accounting model. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting.
 ·
IFRS 12, “Disclosure of Interests in Other Entities” combines in a single standard the disclosure requirements for subsidiaries, associates and joint arrangements as well as unconsolidated structured entities.
 ·
IFRS 13, “Fair Value Measurement” defines fair value, establishes a framework for measuring fair value and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
 
 The adoption of these standards is not expected to have a material impact on the Company’s financial statements.
 
 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 3200, 500 – 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6 and on the Company’s website at www.sonderesources.com.
 2012 Annual MD&A|23