Exhibit 1.3





SONDE RESOURCES CORP.


MANAGEMENT'S DISCUSSION AND ANALYSIS





This Management's Discussion and Analysis ("MD&A") has been prepared by management as of March 25, 2011 and reviewed and approved by the Board of Directors (the “Board”) of Sonde Resources Corp. (formerly Canadian Superior Energy Inc.)  (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") and a review of financial results of the Company based on Canadian Generally Accepted Accounting Principles ("GAAP"). The reporting currency is the Canadian dollar.  This MD&A should be read in conjunction with the audited consolidated financial statements for the years ended December 31, 2010 and 2009.





Non-GAAP Measures – This MD&A contains the term cash flow from (used for) operations, cash flow per share and operating netback, which are non-GAAP financial measures that do not have any standardized meaning prescribed by GAAP and are, therefore, unlikely to be comparable to similar measures presented by other issuers.  Management believes cash flow from (used for) operations, cash flow per share and operating netback are relevant indicators of the Company’s financial performance, ability to fund future capital expenditures and repay debt.  Cash flow 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 GAAP, as an indicator of the Company's performance.  In the operating netback and cash flow from (used for) operations section of this MD&A, reconciliation has been prepared of cash flow from (used for) operations and operating netback to cash from operating activities, the most comparable measure calculated in accordance with GAAP.





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.  This conversion ratio of 6:1 is based on an energy equivalent wellhead value for the individual products.  Such disclosure of boe’s may be misleading, particularly if used in isolation.  Readers should be aware that historical results are not necessarily indicative of future performance.





Share Presentation - On June 3, 2010, the Company’s shareholders approved the consolidation of the Company’s shares on a five for one basis effective on the close of business June 4, 2010. The effect of the consolidation was to reduce to one-fifth the number of common shares, warrants, stock options and stock unit awards outstanding. The number of shares into which the preferred shares are convertible were also reduced to one-fifth. In addition, the conversion price of the preferred shares, the weighted average exercise price and fair value per options, warrants and stock unit awards have been adjusted to five times the pre-consolidation prices. All share and per share amounts included in this MD&A have been adjusted retroactively for the consolidation.





Going concern – The Company’s consolidated financial statements have been prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business.





Forward-Looking Statements – Certain information regarding the Company presented in this document, including management's assessment of the Company's future plans and operations, may constitute forward-looking statements under applicable securities law and necessarily involve risk associated with oil and gas exploration, production, marketing and transportation such as loss of market, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risk, competition from other producers and ability to access capital from internal and external resources, and as a consequence, actual results may differ materially from those anticipated in the forward-looking statements.





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.






2010 MD&A
Page 1













Business Overview and Strategy





The Company is a Calgary, Alberta; Canada based diversified global energy company engaged in the exploration and production of oil and natural gas. The Company’s operations are located in Western Canada and North Africa. The Company is currently in the process of selling its operations offshore the Republic of Trinidad and Tobago (“Trinidad and Tobago”). It has recently sold its interest in Liberty Natural Gas LLC (“Liberty”), a wholly owned subsidiary of the Company which has been involved in the development of a proposed liquefied natural gas project (the “LNG Project”) in U.S. federal waters offshore the state of New Jersey.  The Trinidad and Tobago operations and LNG Project have been classified as discontinued operations in accordance with GAAP.





The Company derives all of its production and cash flow from its operations in Western Canada. The Company’s Western Canadian oil and gas assets are primarily high working interest properties that are geographically concentrated in four areas with multi-zone opportunities, the most significant being Greater Drumheller, Alberta, which accounts for approximately 65% of the Company’s production.  The balance of production largely comes from the Kaybob/Windfall and Boundary Lake/Eaglesham areas, with minor production in North-eastern British Columbia.





No wells were drilled in Western Canada wells in 2010, concentrating instead on an extensive portfolio of standing suspended wells. The Company re-entered and re-completed 12 wells (all operated) and performed 42 (31 net) additional work-over’s. Despite the lack of drilling, this program effectively increased production and eliminated base declines during the third and fourth quarters of 2010.  At December 31, 2010, The Company had approximately 700 gross boe per day awaiting tie-in and held 446,222 gross (316,760 net) acres in Western Canada at December 31, 2010.




The Company is focused on the maximization of long-term sustainable value to its shareholders by:





·
Developing the Western Canadian asset base to increase daily average production and replace production, with a focus on increasing oil and gas liquids production through re-development of existing fields in the Company’s portfolio;·
Expanding on the success of the appraisal well on the “7th of November Block” in North Africa through additional development and exploration. The Company is currently seeking a partner to jointly explore the "7th of November Block" and is exploring other alternatives to finance its activities;·
Disposing its Trinidad and Tobago assets to fund growth in Western Canada and North Africa; and·
Synergistic growth through consolidating working interests in existing reservoirs, and expansion into new reservoirs, in the Company’s core areas in Western Canada.





On October 21, the Company announced the appointment of a Chief Executive Officer and a Chief Operating Officer which supports the Company’s goal of establishing a strategic vision to extract value from the Company’s assets while pursing new areas of growth.





The success of the Company’s ongoing operations are dependent upon several 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, capital spending allocations, disposing of its Trinidad and Tobago assets, the ability to attract equity investment, hiring and retaining qualified personnel and managing political and government risk, particularly with respect to its interests in North Africa.






2010 MD&A
Page 2














Operating netback and cash flow from (used for) operations


(see note 1 below)





($ thousands)
($ per boe)Three months ended December 31
2010
2009
% change
2010
2009
% changeRevenuePetroleum and natural gas sales
9,738
10,242
(5)
34.29
36.40
(6)Realized gain on financial instruments
1,065
--
n/a
3.75
--
n/aTransportation
(315)
(307)
3
(1.11)
(1.09)
2Royalties
(486)
(565)
(14)
(1.71)
(2.01)
(15)10,002
9,370
7
35.22
33.30
6Operating
(4,378)
(3,232)
35
(15.42)
(11.49)
34Operating netback(2)
5,624
6,138
(8)
19.80
21.81
(9)General and administrative
(3,473)
(2,685)
29
(12.23)
(9.54)
28Foreign exchange loss
(312)
(529)
(41)
(1.10)
(1.88)
(41)Interest and other income
(1)
658
(100)
--
2.34
(100)Interest
(303)
105
(389)
(1.07)
0.37
(389)Bad debt expense
(1,831)
(49)
(3,637)
(6.45)
(0.17)
(3,694)Asset retirement expenditures
(249)
--
n/a
(0.88)
--
n/aPart VI.1 tax on preferred share dividends
(46)
--
n/a
(0.16)
--
n/aRestructuring costs
--
34
n/a
--
0.12
n/aCash flow from (used for) operations(1)(2)
(591)
3,672
(116)
(2.09)
13.05
(116)Changes in non-cash working capital
(309)
1,370
(123)
(1.09)
4.87
(122)Cash from (used for) operating activities
(900)
5,042
(118)
(3.18)
17.92
(118)





($ thousands)
($ per boe)Twelve months ended December 31
2010
2009
% change
2010
2009
% changeRevenuePetroleum and natural gas sales
36,880
34,582
7
35.22
31.37
12Realized gain on financial instruments
3,197
--
n/a
3.05
--
n/aTransportation
(1,304)
(810)
61
(1.25)
(0.73)
71Royalties
(4,641)
(2,678)
73
(4.43)
(2.43)
8234,132
31,094
10
32.59
28.21
16Operating
(13,036)
(13,546)
(4)
(12.45)
(12.29)
1Operating netback(2)
21,096
17,548
20
20. 14
15.92
27General and administrative
(12,742)
(13,507)
(6)
(12.17)
(12.25)
(1)Foreign exchange (loss) gain
(91)
1,434
(106)
(0.09)
1.30
(107)Interest and other income
274
1,456
(81)
0.26
1.32
(80)Interest
(1,076)
(5,663)
(81)
(1.03)
(5.14)
(80)Bad debt expense
(2,698)
(161)
1,576
(2.58)
(0.15)
1,620Asset retirement expenditures
(284)
(462)
(39)
(0.27)
(0.42)
(36)Part VI.1 tax on preferred share dividends
(470)
--
n/a
(0.45)
--
n/aRestructuring costs
--
(18,821)
n/a
--
(17.07)
n/aCash flow from (used for) operations(1)(2)
4,009
(18,176)
122
3.81
(16.49)
123Changes in non-cash working capital
(5,842)
(6,092)
(4)
(5.58)
(5.53)
1Cash used for operating activities
(1,833)
(24,268)
(92)
(1.77)
(22.02)
(92)


(1)Tables include both continuing and discontinued operations.


(2)Non-Canadian GAAP measure






2010 MD&A
Page 3













For the three months ended December 31, 2010, cash flow from operations was ($0.6) million compared to cash flow from operations of $3.7 million in 2009.  The change from prior year is due to the Company:





·
Realizing higher operating expenses related to work-over activities which reduced the Company’s operating netbacks.·
Incurring increased general and administrative costs (“G&A”) for legal fees on corporate matters and higher salaries and benefits expense due to staffing increases in 2010.·
Recording a provision $1.8 million to bad debt expense in 2010 for value added tax receivable from the government of the Republic of Trinidad and Tobago.




For the twelve months ended December 31, 2010, cash flow from operations was $4.0 million compared to cash flow used for operations of ($18.2) million in 2009.  The change from prior year is due to the Company:





·
Realizing increased commodity prices and realized hedging gains, which partially offset the impact of decreased natural gas production.·
Incurring one time interest, G&A and restructuring costs during the Company’s proceedings under the Companies Creditors Arrangement Act (“CCAA”) and receivership in 2009.·
Recording a provision $1.8 million to bad debt expense in 2010 for value added tax receivable from the government of the Republic of Trinidad and Tobago.




Production





Three months ended

December 31
Twelve months ended

December 312010
2009
2010
2009Natural gas (mcf/d)
14,140
14,428
13,324
14,569Crude oil and natural gas liquids(bbls/d)
730
653
649
592Total production (boe/d) (6:1)
3,087
3,058
2,870
3,020





For the three months ended December 31, 2010, production averaged 3,087 boe per day and for the twelve months ended December 31, 2010, production averaged 2,870 boe per day.  The decrease in 2010 year to date natural gas production is mainly due to natural declines, which more than offset the favourable results from the Company’s well re-activation program and tie-ins of new gas wells. Crude oil and natural gas liquid production increased due to new production brought on stream in 2010.





Petroleum and natural gas sales, net of transportation





Three months ended

December 31
Twelve months ended

December 31($ thousands, except where otherwise noted)
2010
2009
2010
2009Petroleum and natural gas sales, net of transportationNatural gas
4,979
6,402
19,597
21,741Realized gains on financial instruments
1,065
--
3,197
--6,044
6,402
22,794
21,741Crude oil and natural gas liquids
4,444
3,410
15,979
11,908Total
10,488
9,812
38,773
33,649Average sales priceNatural gas ($/mcf)
4.65
4.82
4.69
4.09Crude oil and natural gas liquids($/bbl)
66.16
56.73
67.55
55.09Total($/boe)
36.93
34.87
37.02
30.52





For the three months ended December 31, 2010, petroleum and natural gas sales, net of transportation was $10.5 million, consisting of $5.0 million in natural gas, $1.1 million in realized gains on a natural gas hedge and $4.4 million of crude oil and natural gas liquids sales. The Company realized an average sales price of $36.93 per boe during the three months ended December 31, 2010 compared to $34.87 per boe for the same period in 2009.






2010 MD&A
Page 4














For the twelve months ended December 31, 2010, petroleum and natural gas sales, net of transportation was $38.8 million, consisting of $19.6 million in natural gas, $3.2 million in realized gains on a natural gas hedge and $16.0 million of crude oil and natural gas liquids sales. The Company realized an average sales price of $37.02 per boe during the twelve months ended December 31, 2010 compared to $30.52 per boe for the same period in 2009.





The increase in natural gas sales for the year is mainly due to the impact of realized hedging gains on the Company’s average sales price which more than offset the 9% decrease in natural gas production in 2010 compared to 2009. Crude oil and natural gas liquids sales increased during 2010 due to a 22% increase in realized prices and a 10% increase in production compared to the same period in 2009.





Royalties





Three months ended

December 31
Twelve months ended

December 31($ thousands, except where otherwise noted)
2010
2009
2010
2009RoyaltiesCrown
299
319
3,273
1,811Freehold and overriding
187
246
1,368
867Total
486
565
4,641
2,678Royalties per boe ($)
1.71
2.01
4.43
2.43Average royalty rate (%)
4.6
5.8
12.0
8.0





The Company pays royalties to provincial governments, freehold landowners and overriding royalty owners. Royalties are contractually 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, which impacts the average royalty rate. In addition, various items, including cost of service credits and other royalty credit programs, impact the average royalty rate paid.





For the twelve months ended December 31, 2010, royalties were $4.6 million or 12.0% of total petroleum and natural gas sales compared to $2.7 million or 8.0% in 2009.  In 2009, the Company incurred lower royalty rates compared to 2010 due to favourable prior period adjustments realized in 2009 on crown royalties and reduced royalty rates under the new Alberta royalty framework.  In addition, the Company recorded $0.5 million of favourable payout related royalty adjustments ($0.2 million to Crown royalties and $0.3 million to gross overriding royalties) as part of the CCAA creditor claims process.





Operating expenses





For the three months ended December 31, 2010, operating expenses were $4.4 million or $15.42 per boe compared to $3.2 million or $11.49 per boe for the same period in 2009. The increase is mainly due to the Company completing  23 (20 net) work-overs during the fourth quarter of 2010.





For the twelve months ended December 31, 2010, operating expenses were $13.0 million or $12.45 per boe compared to $13.5 million or $12.29 per boe for the same period in 2009.  During 2010, the Company completed a total of 42 (31 net) work-over’s for a total cost of $1.7 million ($1.60 per boe) compared to 8 (7 net) and $0.6 million ($0.50 per boe) in 2009.  In addition, the Company incurred decreased labour and processing fees in 2010 as part of a comprehensive review of the Company’s properties and operations. In 2009, the Company incurred $0.9 million in one-time operating expenses related to the CCAA claims process.






2010 MD&A
Page 5











General and administrative expenses





Three months ended

December 31
Twelve months ended

December 31($ thousands, except where otherwise noted)
2010
2009
2010
2009Continuing operationsGross general and administrative expense
6,048
3,215
17,410
15,980Capitalized general and administrative expense
(3,303)
(530)
(5,396)
(2,473)2,745
2,685
12,014
13,507Discontinued operationsGross general and administrative expense
3,945
1,916
13,609
8,477Capitalized general and administrative expense
(3,217)
(1,916)
(12,881)
(8,477)728
--
728
--Total net general and administrative expense
3,473
2,685
12,742
13,507General and administrative expense ($/boe)
12.23
9.54
12.17
12.25





Continuing operations





During 2010, gross G&A from continuing operations increased to $17.4 million from $16.0 million in 2009. Gross G&A from continuing operations consists of $3.9 million (2009 – $0.5 million) relating to North Africa and $13.5 million (2009 – $15.5 million) related to Western Canada operations and corporate head office. During 2010, the Company continued to implement its rationalization program to reduce corporate G&A costs. The Company’s corporate gross G&A expenditures decreased mainly due to one time executive contract settlements paid in 2009. Further decreases were due to a reduction in 2010 office costs from subleasing agreement recoveries. These decreases were partially offset by increased legal fees in 2010 related to general corporate matters.  The increase in North Africa gross G&A expenditures were due to the commencement of the 7th of November drilling program during the fourth quarter of 2010, all of which were capitalized.





Discontinued operations





During 2010, gross G&A from discontinued operations increased to $13.6 million from $8.5 million in 2009. Gross G&A from discontinuing operations consists of $12.2 million (2009 – $7.4 million) relating to the LNG Project and $1.4 million (2009 – $1.1 million) related to Trinidad and Tobago. The increase in gross G&A expenditures is primarily due to increased costs incurred in relation to the permit application process on the LNG Project.  In addition, net G&A from discontinued operations in 2010 reflects accrued transaction costs for the disposition of the Company’s Trinidad and Tobago assets.





Restructuring costs





On March 5, 2009, the Company made an application for protection under the Companies’ Creditors Arrangement Act (“CCAA”), emerging from CCAA on September 15, 2009.  In 2009, the Company incurred $18.8 million (2010 – nil) in restructuring costs related to the receivership of the Block 5(c) asset in Trinidad and Tobago and CCAA proceedings.  The majority of these costs were related to legal costs incurred directly by the Company and associated with the CCAA process, receiver legal costs and other reimbursed costs.





Stock based compensation





During the twelve months ended December 31, 2010, the Company incurred stock based compensation expenses of $3.0 million compared to $3.1 million in 2009. In 2010, the Company granted 981,850 (2009 – 915,600) stock options at an weighted average fair value of $2.54 (2009 – $2.05) per option.





As at December 31, 2010, the Company has issued 729,800 stock unit awards to the Company’s executive officers and members of the Board of Directors. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company. The stock units have time and share based performance vesting terms which vary depending on whether the holder is an executive officer or director.  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 units may be paid in cash or common shares.  At December 31, 2010, the Company recorded a liability of $0.5 million to recognize the fair value of the vested stock units (December 31, 2009 - $0.1 million).





On June 3, 2010, 5,666 stock unit awards were exercised and 23,334 expired due to the departure of a former director of the Company.






2010 MD&A
Page 6











On January 12, 2011, the Company issued 211,900 stock unit awards to members of the Board of Directors and 288,000 stock unit awards to the Chief Operating Officer of the Company.





Depletion, depreciation and accretion





Depletion, depreciation and accretion expense ("DD&A") was $27.7 million or $26.50 per boe for the twelve months ended December 31, 2010 compared to $33.6 million or $30.83 per boe in 2009.The calculation of depletion and depreciation included an estimated $11.2 million (December 31, 2009 - $13.2 million) for future development capital associated with proven undeveloped reserves and excluded $133.8 million (December 31, 2009 - $123.0 million) related to unproved properties and projects under development.  Of the costs excluded $2.6 million (December 31, 2009 - $9.0 million) relates to Western Canada, nil (December 31, 2009 - $20.7 million) to East Coast Canada, $46.9 million (December 31, 2009 – $3.6 million) for offshore North Africa and $84.3 million (December 31, 2009 - $89.7 million) to discontinued operations related to Trinidad and Tobago and the LNG Project. The Company's DD&A is lower in 2010 due to the impact on depletion of ceiling test impairments on the carrying value of the Company’s Canadian petroleum and natural gas assets of $57.5 million recognized at December 31, 2009 and $9.7 million at June 30, 2010.





On December 31, 2010, the Company applied a ceiling test to its petroleum and natural gas properties. The application of this test required an adjustment to the carrying value of the Company’s Canadian petroleum and natural gas properties of $29.1 million, for a cumulative ceiling test impairment recognized of $38.8 million in 2010 (December 31, 2009 – $57.5 million). The ceiling test impairments incurred during 2010 were primarily due to a significant decrease in forecasted natural gas prices combined with an extension of the estimated timing of the Company’s future development of its Western Canadian oil and gas properties.





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, 2010, the Company has estimated $302.1 million in tax pools (2009 - $236.9 million) and $54.7 million in non-capital losses (2009 - $71.7 million) that are available for future deduction against taxable income.





December 31($ thousands)
2010Canadian exploration expense
58,368Canadian oil and gas property expense
44,086Canadian development expense
34,469Undepreciated capital costs
32,269Share issue costs
4,253Foreign exploration expense
127,896Other
757Total
302,098





Non-capital losses expire as follows:





($ thousands)2011 - 2020
--2021 - 2025
652026 - 2030
54,67254,737






2010 MD&A
Page 7











Capital expenditures





Three months ended

December 31
Twelve months ended

December 31($ thousands)
2010
2009
2010
2009Continuing operationsAcquisitions
125
--
785
--Exploration and development
36,098
13,145
47,084
16,065Plants, facilities and pipelines
638
1,363
2,927
2,348Land and lease
775
224
2,827
1,195Capitalized general and administrative expenses
3,303
350
5,396
2,668Exploration and development expenditures
40,939
15,263
59,019
22,276Exploration and development divestitures
(8)
--
(8)
(8,521)40,931
15,263
59,011
13,755Discontinued operations
15,791
4,097
26,506
(64,864)Net capital expenditures
56,722
19,360
85,517
(51,109)




Three months ended

December 31
Twelve months ended

December 31($ thousands)
2010
2009
2010
2009Continuing operationsCanada
4,347
14,897
15,581
12,323North Africa
36,581
181
43,342
1,087Corporate Assets
3
185
89
34540,931
15,263
59,012
13,755Discontinued operationsTrinidad and Tobago
12,830
2,494
14,353
(72,295)United States
2,961
1, 603
12,152
7,43115,791
4,097
26,505
(64,864)Net capital expenditures
56,722
19,360
85,517
(51,109)





Continuing operations





Western Canada





In 2010, no wells were drilled in Western Canada. The Company instead focused on the Company’s well re-activation program which concentrated on the company’s extensive portfolio of suspended wells.  The Company re-entered and re-completed 12 wells (all operated), invested $2.8 million in land and lease acquisitions and completed and tied-in successful wells from the Company’s 2009 winter drilling program.





In 2009, the Company expended $13.5 million in Western Canada to drill 13 gross wells (11.4 net) to satisfy the Company’s flow-through commitment. In addition, the Company sold gross overriding royalties and seismic data in Western Canada for proceeds of $9.1 million.





North Africa





During 2010, the Company incurred $30.9 million in North Africa on costs related to the drilling and testing of the successful Zarat-1 North appraisal well.  The Company commenced drilling in November 2010 and completed drilling and production testing of the appraisal well on the Zarat discovery extension in January 2011. The Company has temporarily abandoned the appraisal well in a manner allowing it to be utilized for future development purposes. The Company is currently evaluating the commercial development potential of the feature, as well as discussing unitization options with owners of an adjacent concession.






2010 MD&A
Page 8











In addition, the Company recorded $12.4 million expenditure for the Company’s “Swap agreement” obligation under the 7th of November Block Exploration and Production Sharing Agreement ("EPSA").  The swap agreement was signed at the time the Company entered into the EPSA. The "Swap Agreement" awarded an overriding royalty interest and optional participating interest to Joint Exploration, Production, and Petroleum Services Company ("Joint Oil"), a Tunisian/Libyan company, in the Company's "Mariner" Block, offshore Nova Scotia, Canada. If at August 27, 2011, no royalty has been drilled on the Mariner Block, Joint Oil has the right to put back and sell the overriding royalty to the Company for US$12.5 million. On December 31, 2010, the Company chose not to renew the Mariner Block license and no longer holds any interest in offshore Nova Scotia, Canada. As a result, Joint Oil would be eligible to exercise its option on or after August 27, 2011.





Discontinued operations





Trinidad and Tobago





During 2010, the Company recognized the US$12.0 million Mayaro-Guayaguayare block (“MG Block”) performance guarantee and incurred an additional $2.4 million of Trinidad Block 5(c) costs related to the planning of the next exploration phase.  In 2009, the Company expended $14.3 million of which the majority was spent to drill, test and evaluate the third offshore Trinidad and Tobago Block 5(c) well “Endeavour”.





Due to the large capital expenditure requirements and an unclear development timeline, the Company determined that selling its interests in Trinidad and Tobago would best capitalize the Company to pursue its future growth plans in Western Canada and North Africa. On December 22, 2010 the Company entered into an agreement with Niko Resources Ltd. (“Niko”) to sell its remaining 25% interest in Block 5(c) and its MG Block exploration and production license for an aggregate purchase price of US$87.5 million. The purchase price is to be satisfied via US$75.5 million and the assumption of the Company’s performance guarantee provided for the MG Block of US$12.0 million. On February 8, 2011, as part of the agreement, the Company issued a US$20.0 million debenture to Niko. The debenture accrues interest at 6.0% per annum and is secured against the Company’s Block 5(c) interests. Upon closing of the agreement, the US$20.0 million will be applied against the proceeds of US$75.5 million.  If the agreement does not close, the Company will be required to repay the US$20.0 million plus accrued interest to Niko. The closing of this agreement will result in the Company to reclaim US$20.0 million held as restricted cash with BG International Limited (“BG”) that was required under the CCAA Plan of Arrangement. The Niko sale agreement closing is subject to the satisfaction of certain conditions including approval from the Trinidad and Tobago Ministry of Energy and Energy Industries. To date, the Company has not received the approval.





The following summarizes the acquisition and disposition presented as discontinued operations of Trinidad and Tobago:





(i) Challenger acquisition





On September 15, 2009, the Company completed the acquisition of Challenger Energy Corp (“Challenger”) for consideration of approximately 5.5 million common shares of the Company. The acquisition of Challenger allowed the Company to sell a 45% interest in Block 5(c) to BG for sufficient proceeds to satisfy its creditor claims, thereby allowing the Company to emerge successfully from CCAA. It also ensured the Company retained a 25% interest in Block 5(c). The Company acquired control of Challenger through the execution of a court and shareholder approved plan of arrangement.  The Company recorded a gain on corporate acquisition due to the fair value of the net identifiable assets and liabilities assumed by the Company exceeding the total consideration paid.  The purchase price for this transaction has been allocated as follows:





ConsiderationCommon shares (5,545,669)
22,183






2010 MD&A
Page 9











Net assets received at fair valueCash
215Working capital
(53,244)Property, plant and equipment
86,950Asset retirement obligation
(3,068)Warrants
(147)30,706Gain on corporate acquisition
(8,523)22,183


2010 MD&A
Page 10











(ii) Block 5(c) disposition





On June 30, 2009, BG gave notice to the Company of its intent to exercise a right of first refusal in respect of the agreement of purchase and sale dated June 1, 2009 between the Company and Centrica Resources Limited. On September 15, 2009, the Company completed the sale to BG of an undivided 45% of the Company’s 70% interest in Block 5(c) for gross proceeds of US$142.5 million. The sale was executed as part of the Company’s CCAA Plan of Arrangement.





Proceeds from dispositionCash
155,377Transaction costs
(8,733)Net proceeds
146,644Net assets disposed at carrying valueProperty, plant and equipment
(116,530)Asset retirement obligation
5,522Net assets
(111,008)Gain on disposition
35,636





LNG project





On February 22, 2011, the Company completed the sale of Liberty which owns a 100% working interest in the LNG Project to an entity related to West Face Capital Inc. (“West Face”). The sale of the LNG Project was initiated with West Face in alignment with the Company’s strategy of focusing on the development of its interests in Western Canada and North Africa. Pursuant to the sale, the Company received US$1.0 million for reimbursable costs between January 1, 2011 and the date of closing. The Company is entitled to receive deferred cash consideration of US$12.5 million payable upon West Face’s first successful gas delivery. No amounts have been recorded in these consolidated financial statements related to this contingent consideration.





At December 31, 2010, the Company evaluated the carrying amount of the LNG Project compared to the fair value less cost to sell resulting in a $31.9 million impairment.





Liquidity and capital resources





December 31
December 31($ thousands)
2010
2009Cash and cash equivalents
2,649
3,305Restricted cash
--
1,364Accounts receivable
7,147
11,340Prepaid expenses and deposits
1,686
3,185Assets of discontinued operations
104,299
23,819Accounts payable and accrued liabilities
(18,126)
(26,443)Mariner swap liability
(12,433)
--Stock unit awards
(530)
(55)Revolving credit facility
(20,251)
(24,067)Convertible preferred shares
(14,797)
--Liabilities of discontinued operations
(15,212)
(1,793)Working capital surplus (deficit)
34,432
(9,345)







2010 MD&A
Page 11











As at December 31, 2010, the Company had a working capital surplus of $34.4 million (December 31, 2009 – ($9.3) million deficit), the Company had drawn $20.3 million (December 31, 2009 – $24.1 million) against the $40.0 million (December 31, 2009 - $40.0 million) demand revolving credit facility (the “Credit Facility A”) at a variable interest rate of prime plus 0.75% (December 31, 2009 – prime plus 0.75%).  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 its working capital ratio at 1:1 or greater and to ensure that non-domestic G&A expenditures in excess of $7.0 million per year and all foreign capital expenditures are not funded from the Credit Facility A or domestic cash flow while the Credit Facility A is outstanding. In January 2011 the Company and its creditor completed their quarterly review of Credit Facility A, resulting in continued approval of the $40.0 million 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 will 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. Subject to availability, review, and the Company’s creditor’s right of demand, principle and interest shall be repaid over the half-life of the reserves being financed.




As at December 31, 2010, the Company was in violation of one of its debt covenants. This covenant placed a ceiling on foreign expenditures which has been exceeded with the pending approval of the Trinidad and Tobago asset sale. The Company sought and received a waiver from its lender on this violation and it does not impact the Company’s borrowing ability.
  The Company is subject to the next semi-annual review on Credit Facility A and Credit Facility B on or before April 30, 2011.


At December 31, 2010, the Company had $2.6 million in cash and cash equivalents (December 31, 2009 - $3.3 million) and $19.9 million classified as restricted cash (December 31, 2009 – $22.3 million).




On January 19, 2010, the Company completed a private placement of 22,884,848 common shares at $2.60 per share for gross proceeds of $59.5 million.





On February 3, 2010, the Company restructured the terms of the Series A, 5.0% US Cumulative Redeemable Convertible Preferred Shares (the “Series A Shares”). Pursuant to the terms of the restructuring, the Series A Shares were exchanged on a share for share basis for 150,000 First Preferred Shares, Series B shares (the “Series B Shares”) pursuant to which the redemption date was extended from December 31, 2010 to December 31, 2011, the conversion price was reduced from US$12.50 to US$3.00 and the conversion of 150,000 preferred shares into common shares was increased from 1,200,000 to 5,000,000. The terms of the dividend payment under the Series B Shares remain unchanged from the Series A Shares whereby the Company can elect to pay the quarterly dividend by way of issuance of common shares at market, based on a 5.75% annualized dividend rate in lieu of the 5.0% annualized cash dividend rate. The dividend rate shall be increased by 1/30 of 1% per day restricted to the 150 day period after December 31, 2010 resulting in a maximum applicable annual dividend rate of 6.25% and thereafter reverts to 5%.  In addition, the Company granted 500,000 common share purchase warrants exercisable at a price of US$3.25 for each common share and expiring December 31, 2011. The Series B Shares are redeemable by the Company on or after December 31, 2011 and retractable by the Series B Shareholders on December 31, 2011.  The Company can force conversion of the Series B Shares at anytime in the future if its common shares close at a price of at least a 100% premium to the conversion price of US$3.00 on a major US exchange for 20 out of any 30 consecutive trading days while the common shares underlying the Series B Shares are registered.  The extension provided the Company with additional flexibility as the Company continues to advance its domestic and international capital programs and work towards improving its liquidity and capital resources.





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 domestic and international operations.





The Company’s cash flow from operations is directly related to underlying commodity prices and production volumes. A significant decrease in commodity prices could materially impact the Company's future cash flow from operations and liquidity. In addition, a substantial decrease in commodity prices could impact the Company’s borrowing base under its credit facilities, therefore reducing funds available for Western Canadian investment, and in some instances, requiring a portion of the credit facilities to be repaid. The Company has entered into risk management contracts to mitigate commodity prices. Management continues to review various other risk mitigating options.






2010 MD&A
Page 12














The Company’s future liquidity is also dependent on its ability to close its proposed sale of its Trinidad and Tobago interests. Whether and when the Company can complete the disposition of its Trinidad and Tobago assets is uncertain. This uncertainty may cast significant doubt about the Company’s ability to continue as a going concern. If the Trinidad and Tobago asset deal does not close, the Company intends to finance future Western Canada capital expenditures, to the extent it can, with existing cash flow and available debt capacity. In addition, the Company has limited its North Africa activities in compliance with the political issues and Libyan sanctions as required.  In addition, the Company will limit other expenditures during the interim period pending the final approval of the sale. The Company will work with a combination of strategic investors and/or public and private debt and equity markets to source funding.  Public and private debt and equity markets may not be accessible now or in the foreseeable future and, as such, the Company’s ability to obtain financing cannot be predicted with certainty at this time. Without access to financing, the Company may not be able to continue as a going concern.





Contingencies and commitments





Block 5(c) Trinidad and Tobago





At December 31, 2010, BG held in escrow for the Company US$20.0 million whereby the Company must maintain the lesser of US$20.0 million or 25% of the estimated capital expenditure requirements in respect of Block 5(c) through to the end of the second phase of the exploration period. Any draws made against the US$20.0 million are required to be replenished by the Company within 30 days of the draw date. The Company’s future obligations for the exploration and development of Block 5(c) are largely dependent on BG’s decisions as operator, the Government of Trinidad and Tobago and the closing of the proposed sale of the Company’s 25% working interest to Niko.





On February 24, 2011, The Company received a US$20.0 million initial payment from Niko under the terms of the proposed sale of Block 5(c). The closing of the proposed sale will result in the relinquishment of the US$20.0 million held in escrow by BG to Niko.





MG Block Trinidad and Tobago





In 2007, the Company received an exploration and development license from the Government of Trinidad and Tobago on the MG Block and as a result was committed to conducting 3D seismic by the end of 2009 and to drill two exploration wells on the MG block in a joint venture with The Petroleum Company of Trinidad and Tobago Limited (“Petrotrin”). The first well had to be drilled to a depth of at least 3,000 meters by January 2010 and the second to a depth of at least 1,800 meters by July 2010. The Company agreed to provide a performance security to Petrotrin of US$12.0 million to meet the minimum work program.





The Company has not conducted the 3D seismic or drilled any exploration wells as it believes that the MG Block is not economically viable and that there are significant ecological issues in conducting operations. The Company met with Petrotrin and the Government of Trinidad and Tobago to express its concerns and requested that the work obligations be transferred without penalty to a more prospective area. This request has been denied. The Government has suggested a partnering by the Company in a seismic program earmarked by Petrotrin for its land holdings. The partnering would guarantee the Company has access to the seismic data and an opportunity to participate in other proposed exploration activities set out by Petrotrin.





The Company’s proposed agreement with Niko to sell its remaining interest in Block 5(c) and the MG Block includes the assumption of the performance guarantee. As at December 31, 2010 the Company has recognized the US$12.0 million performance guarantee as a liability of its discontinued operations. Under the circumstances whereby the agreement with Niko is not finalized, the Company may be required to pay the performance security amount in order to relinquish the MG Block. The Niko sale agreement closing is subject to the satisfaction of certain conditions including approval from the Trinidad and Tobago Ministry of Energy and Energy Industries. To date, the Company has not received the approval.  After closing, the Company will cease all operations in Trinidad and completely exit the country.






2010 MD&A
Page 13














North Africa





7th of November block





On August 27, 2008, the Company entered into the 7th of November Block Exploration EPSA with Joint Oil. The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, the Company has been named operator. Under the EPSA, the minimum work program for the first phase (four years) of the seven year exploration period includes three exploration wells and 500 square miles 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 up to US$4.0 million for 3D seismic not completed. The Company has provided a corporate security to a maximum of US$49.0 million to secure its minimum work program obligations. Under the EPSA, the Company has agreed to drill one appraisal well on the Zarat discovery extension within the EPSA contract area. The appraisal well obligation was secured by a fully insured bank guarantee for US$15.0 million to Joint Oil payable if a rig is not moved on location by November 26, 2010.





In April 2010, the Company signed an Assignment and Transfer Agreement with BG Tunisia Limited and ENSCO Offshore International Company related to the ENSCO 105 drilling rig for drilling the Zarat 1 North appraisal well during the fourth quarter of 2010. The Assignment and Transfer Agreement required the payment of US$2.0 million for the Company’s share of third party rig demobilization costs as well as a deposit of US$6.8 million to be held as security for the due performance of the Company’s share of the obligations.





The Company moved the rig on location prior to November 26, 2010, and completed drilling and production testing of the appraisal well on the Zarat discovery extension and the deposit of US$6.8 million was drawn down to nil. On January 11, 2011, the Company temporarily abandoned the appraisal well in a manner allowing it to be utilized for future development purposes. The completion of the drilling and production testing has satisfied all requirements under the EPSA regarding the appraisal well resulting in the relinquishment of the US$15.0 million bank guarantee.





Political issues and Libyan sanctions





The governments of Tunisia and Libya are in political turmoil.  During January 2011, protests in Tunisia led to the overthrow of the government. The Company safely evacuated it’s personnel and the rig and equipment without incident as the turmoil in Tunisia began.  Election of a new national constituent assembly is scheduled to take place on July 24, 2011. While relative calm has been restored, uncertainty remains over the future direction of the country.  Similarly, widespread protests over the government in Libya have occurred and a state of war exists between government and opposition forces. This has led to the cessation of oil production in the country and military intervention by Western forces. On February 26, 2011 the United Nations imposed sanctions on the Libyan government followed by consequent actions of the Canadian Government pursuant to the Special Economics Measures Act(Canada). While this turmoil has not had a direct impact on the Company’s 7th of November Block current activities it may significantly and adversely affect the Company including the functioning of Joint Oil, the pace of future development plans and activities, the ability to secure supplies and personnel, make payments to Joint Oil and the ability to attract joint venture partners or financing.




All of the activity related to this concession will be monitored by the Company to ascertain the impact, if any, of the turmoil in Tunisia and Libya and the impact, if any, of the Libyan Sanctions.




Swap agreement





At the time it entered into the 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. If at August 27, 2011 no well has been drilled on the Mariner Block, Joint Oil has the right to put back and sell the overriding royalty to the Company for US$12.5 million. On December 31, 2010, the Mariner Block licenselapsed resulting in the Company no longer holding any interest in offshore Nova Scotia, Canada. As a result, Joint Oil would be eligible to exercise its option on or after August 27, 2011.





Canadian Sahara Energy Inc.





In July 2008, the Company entered into a Participation Agreement (“PA”) to use reasonable efforts to transfer a 50% interest to Canadian Sahara Energy Inc. (“Canadian Sahara”) upon execution of the EPSA. The interest is to be held in trust until Canadian Sahara is recognized as a party to the EPSA. Canadian Sahara is obligated to pay its share of the project costs incurred after July 5, 2009, but is not obligated under the corporate and bank guarantees. On July 5, 2010, the Company and Canadian Sahara finalized a Joint Operating Agreement (“JOA”) to govern the conduct of operations between the parties. In addition, the two parties entered into a Clarification Agreement which, among other matters, gave Canadian Sahara until September 15, 2010 to pay its share of costs, plus interest, incurred after April 1, 2010.






2010 MD&A
Page 14











The Company issued a Notice of Default to Canadian Sahara on September 16, 2010 due to Canadian Sahara’s failure to pay its share of costs, plus interest, incurred after April 1, 2010.  Under the terms of the JOA, Canadian Sahara had a period of 30 days from the date of the default notice, or until October 16, 2010, to cure its default.





Canadian Sahara failed to cure its default by October 16, 2010 and as a result, Canadian Sahara was notified that the Company is exercising its option to require that Canadian Sahara completely withdraw from the JOA and the EPSA governing the Block, thereby forfeiting its 50% working interest to the Company.  In response, Canadian Sahara had advised that it had filed for creditor protection under the Bankruptcy and Insolvency Act (“BIA”) and made a proposal to its creditors (including the Company) as an insolvent person under the BIA.  The effect of this filing was to put a 30 day hold, which may be extended by the court, on the Company’s foreclosure on Canadian Sahara’s interest.





On November 26, 2010 the court ruled in the Company’s favor, dismissing the BIA protection and lifting the stay protecting Canadian Sahara. As a result, the Company exercised its option to require that Canadian Sahara completely withdraw from the 7th of November Block thereby forfeiting its 50% working interest to the Company. The Company is currently seeking a partner to jointly explore the 7th of November Block and is exploring other alternatives to finance its activities. Without additional sources of capital, funding 100% of the costs of the 7th of November Block could adversely affect the Company’s capital program elsewhere.





Canadian Sahara owed the Company US$6.3 million in outstanding costs, plus interest, associated with its 50% working interest in the 7th of November Block. In view of Canadian Sahara’s default, the Canadian Sahara receivable of US$6.3 million has been re-allocated to property, plant and equipment (US$2.9 million) and prepaid expenses and deposits (US$3.4 million).





Litigation and claims





In December 2009, a class action lawsuit was commenced in the United States District Court of the Southern District of New York against certain former executive officers of the Company for allegedly violating the United States Securities and Exchange Act of 1934 by failing to disclose information concerning its prospects in Trinidad and Tobago. In addition, in May and June 2010, two proposed class action lawsuits were commenced in the Ontario Superior Court of Justice. The actions are made against different groups of former executives and directors of the Company. One of the actions alleges oppression and improper option granting practices and includes the Company and Challenger, a wholly owned subsidiary of the Company, as defendants. The actions contain various claims relating to allegations of misrepresentation and failure to disclose information concerning the Company's activities in Trinidad and Tobago. The class action lawsuits purport to be brought on behalf of purchasers of common shares of the Company from January 14, 2008 to February 17, 2009.





On October 25, 2010, a memorandum of understanding (“MOU”) was entered into whereby the parties to the class action lawsuits and the former executive officers agreed to settle the Litigation upon the terms and conditions set forth in the MOU, subject to court approval and all other conditions to the settlement to be mutually agreed upon in a final stipulation of settlement (the “Stipulation”).





Under the terms of the MOU, the parties have agreed that the Stipulation will provide, among other things, for the full and final disposition of the Litigation, with prejudice and without costs, by the establishment of a US$5.2 million settlement fund by the Defendents’ insurers for the benefit of a settlement class which shall consist of all those who purchased securities of the Company between January 14, 2008 and February 17, 2009.  Pending the negotiation and execution of the Stipulation, the parties to the Litigation will ask the presiding courts to continue the stay of all proceedings in the Litigation, except as necessary to consummate the settlement.  While the Company believes that the Stipulation will ultimately be consummated, no assurance can be provided.





The Defendents continue to deny any and all liability under securities laws and that they committed any violations of law or engaged in any wrongful acts, and that the settlement is being agreed to in order to eliminate the burden and expense of further litigation.





In addition, the Company may be involved in various claims and litigation arising in the ordinary course of business.  In the opinion of the Company the various claims and litigations arising there from are not expected to have a material adverse 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 unforeseen claims.






2010 MD&A
Page 15














Lease obligations





At December 31, 2010, the Company is committed to future payments for office leases and equipment.  Payments required under these commitments for each of the next five years are as follows:





2011
2012
2013
2014
2015
Thereafter
TotalOffice rent
1,985
1,429
168
--
--
--
3,582Equipment
11
8
--
--
--
--
191,996
1,437
168
--
--
--
3,601





Related Party Transactions





On September 15, 2009, the Company acquired all the issued and outstanding common shares of Challenger for consideration of approximately 5.5 million shares of the Company. Challenger was a company which the Company’s former Executive Chairman and director was a shareholder and a director until October 2008. At the time of the transaction, Challenger was no longer considered a related party. Prior to the acquisition, the Company carried a receivable in the amount of $37.8 million and a $14.0 million bridge facility receivable. These receivables pertain to costs incurred on the Company’s Block 5 (c) project in Trinidad and Tobago under normal industry terms and conditions. In addition, prior to the acquisition, the Company carried an accrued interest receivable of $0.9 million from Challenger. The interest payable to the Company was based on an interest rate of 10% per annum on any outstanding balance on the bridge facility. Challenger was permitted to pay interest incurred in common shares. Challenger issued 188,216 common shares for interest payable up to and including January 31, 2009 based on a predetermined calculation. Upon any drawdown of any amounts of the bridge facility, Challenger was obligated to issue a predetermined amount of non-transferable warrants to the Company. Challenger issued 500,000 non-transferable share purchase warrants to the Company which expired unexercised October 2, 2009.





On February 27, 2009, Challenger obtained an order from the Court of Queen's Bench of Alberta granting creditor protection under CCAA. The Initial Order was obtained after the Challenger Board of Directors determined the company was unable to continue to make required payments under a participation agreement with the Company and BG with respect to exploration Block 5(c) or to repay $14.0 million due on February 28, 2009 under a bridge loan facility with the Company.





During the year ended December 31 2009, the Company paid $0.1 million on industry terms, for equipment rentals to a company controlled by the former Executive Chairman and director of the Company.  Also during 2009, the Company invoiced $0.1 million to this related party company for payroll services. Subsequent to March 31, 2009, the Company no longer provides payroll services to this company.





Off-balance sheet arrangements





The Company has no off-balance sheet arrangements.





Share capital





As at March 25, 2011, the Company had 62.3 million common shares, 2.1 million stock options, 0.2 million Series B Preferred Shares and 0.5 million common share purchase warrants issued and outstanding.





Financial Instruments





Cash and cash equivalents and restricted cash are classified as financial assets held for trading and are measured at their fair value. Gains or losses related to periodic revaluation at each reporting period are recorded to net income or loss.





Accounts receivables are classified as loans and receivables and are initially measured at their fair value.  Subsequent periodic revaluations are recorded at their amortized cost using the effective interest method.





Accounts payable and accrued liabilities, Mariner swap liability, revolving credit facility and the liability component of the convertible preferred shares are classified as other liabilities and are initially measured at fair value.  Subsequent periodic revaluations are recorded at their amortized cost using the effective interest method.





Derivatives and stock unit awards are classified as held for trading and measured at their fair value.  Gains or losses related to periodic revaluation at each reporting period are recorded to net income or loss.


2010 MD&A
Page 16













The Company uses a fair value hierarchy to categorize the inputs used to measure the fair value of its financial instruments. Cash and cash equivalents and restricted cash are transacted in active markets and have been classified using Level 1 inputs. Stock unit awards do not transact in an active market.  The value is indexed using the Company’s share price as the main input, therefore the awards have been classified as Level 2.





The convertible preferred shares have little or no market activity to support the fair value and have been classified using Level 3 inputs. There was $0.9 million recognized as interest expense related to the convertible preferred shares (2009 - $1.4 million).  A loss of $0.2 million was recognized on the exchange of the Series A Shares for Series B Shares.  For all other assets and liabilities the carrying value approximates the fair value.





Risk management





In order to manage the Company’s exposure to credit risk, foreign exchange risk, interest rate and commodity price risk, the Company developed a risk management policy. Under this policy, it may enter into agreements, including fixed price, forward price, physical purchases and sales, futures, currency swaps, financial swaps, option collars and put options. The Company's Board of Directors evaluates and approves the need to enter into such arrangements.





Credit risk





The Company’s accounts receivable are with natural gas and liquids marketers, the Government of the Republic of Trinidad and Tobago and joint venture partners in the petroleum and natural gas business under substantially normal industry sale and payment terms and are subject to normal credit risks. As at December 31, 2010, the maximum credit risk exposure is the carrying amount of cash and cash equivalents of $2.6 million (December 31, 2009 – $3.3 million), restricted cash of $19.9 million (December 31, 2009 – $22.3 million) and accounts receivables of $7.1 million (December 31, 2009 – $14.2 million). As at December 31, 2010, the Company’s accounts receivables consisted of $3.2 million (December 31, 2009 - $6.7 million) of Western Canada joint interest billings, nil (December 31, 2009 - $2.5 million) in value added tax receivable from the Government of the Republic of Trinidad and Tobago, and $3.9 million (December 31, 2009 - $5.0 million) of revenue accruals and other receivables. Purchasers of the Company’s oil, gas and natural gas liquids are subject to an internal credit review to minimize the risk of nonpayment. The Company mitigates risk from joint venture partners by obtaining partner approval of capital expenditures prior to starting a project.





The Company’s allowance for doubtful accounts is currently $3.0 million (December 31, 2009 - $0.4 million).





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. At December 31, 2010, the Company has US$1.7 million in cash and cash equivalents (December 31, 2009 – US$0.6 million), US$20.0 million in restricted cash (December 31, 2009 – US$20.9 million), nil (December 31, 2009 – US$2.4 million) in value added tax receivable from the Government of the Republic of Trinidad and Tobago, US$0.3 million (December 31, 2009 – US$1.0 million) of Block 5(c) payables, US$12.0 million (December 31, 2009 – nil) of MG Block payables, US$20.4 million (December 31, 2009 – nil) of Tunisa payables, US$2.2 million (December 31, 2009 – US$0.5 million) of LNG Project payables, and US$14.9 million (December 31, 2009 – US$14.6 million) of convertible preferred shares. These balances are exposed to fluctuations in the U.S. dollar.  In addition, the Company is exposed to fluctuations between U.S. dollars and the domestic currencies of Trinidad and Tobago and Tunisia. 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 net loss and comprehensive loss, assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- 10% is $2.8 million. This analysis assumes all other variables remain constant.





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, 2010.  The Company has no interest rate swaps or hedges to mitigate interest rate risk at December 31, 2010. The Company’s exposure to fluctuations in interest expense on its net loss and comprehensive loss, assuming reasonably possible changes in the variable interest rate of +/- 1% is $0.2 million. This analysis assumes all other variables remain constant.





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






2010 MD&A
Page 17








and are not used for trading or other speculative purposes. The following natural gas price risk contract was in place during the year ended December 31, 2010:





Term
Contract
Volume (GJs/d)
Fixed price  ($/GJ)
2010 realized gainsJanuary 1, 2010 – December 31, 2010
Swap
5,500
$5.50
$3,197





The following natural gas price risk contract was in place during the year ended December 31, 2008:





Term
Contract
Volume (GJs/d)
Fixed price ($/GJ)
2008 realized lossesFebruary 1, 2008 – October 31, 2008
Swap
2,000
$7.05
($496)





On February 14, 2011, the Company entered into the following natural gas swap agreement:





Term

Contract
VolumeGJs/d)
Fixed price ($/GJ)March 1, 2011 – December 31, 2011

Swap
5,000
$4.11





In exchange for receiving the fixed price on the February 14, 2011 swap agreement, the Company sold a call option on 250 bbls per day at US$100 per bbl commencing March 1, 2011 through to 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.





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.


2010 MD&A
Page 18














IFRS Implementation





On February 13, 2008, the Canadian Accounting Standards Board (“AcSB”) confirmed the mandatory changeover date to International Financial Reporting Standards (“IFRS”) for Canadian profit-oriented publicly accountable entities (“PAE’s”).  The AcSB requires that IFRS compliant financial statements be prepared for annual and interim financial statements commencing on or after January 1, 2011.  For PAE’s with a December 31 year end, the first unaudited interim financial statements under IFRS will be for the quarter ending March 31, 2011, with comparative financial information for the quarter ending March 31, 2010.  The first audited annual financial statements will be for the year ending December 31, 2011, with comparative financial information for the year ending December 31, 2010. This means that all opening balance sheet adjustments relating to the adoption of IFRS must be reflected in the January 1, 2010 opening balance sheet which will be issued as part of the comparative financial information in the March 31, 2011 unaudited interim financial statements.





The Company commenced its transition project during the second quarter of 2010 which is comprised of three key phases: initial assessment, design and development and implementation.  The Company has completed the initial assessment phase, which includes a high level analysis of the differences between current Canadian GAAP and IFRS and the potential effects of the IFRS conversion on the Company’s existing accounting policies, financial reporting, external disclosures, information system, internal controls and business processes.  The Company has substantially completed the second phase, including a detailed analysis of differences in accounting policies, required adjustments to the balance sheet on transition to IFRS, changes in disclosures included in the Company’s financial statements and determining required changes of information systems.  While the second phase has not yet been completed, the following provides an indication of the expected impact of those items having the most significant impact on the Company’s financial reporting:





·
Property, Plant and Equipment – the full-cost method of accounting applied under current GAAP will no longer be allowed to be used under IFRS.  Instead, accounting for oil and gas operations will have to be compliant with requirements in IFRS 6 Exploration for and Evaluation of Mineral Resources when it relates to exploration activities and IAS 16 Plant, Property and Equipment for development and production assets.  It is expected $130 - $160 million will be classified as oil and gas assets under tangible fixed assets, while $60 - $80 million will be classified as intangible exploration assets on January 1, 2010. The adjustment, except for the impact of adjustments described below, is not expected to have a significant impact on 2010 depletion expense under IFRS;·
Property, Plant and Equipment – the Company will derecognize certain costs previously capitalized as part of the full cost pool in relation to the Company’s LNG project in the United States, as these costs do not meet criteria for capitalization under IFRS.  The impact is expected to be $18 - $22 million on transition.  The 2010 expense will be increased as costs incurred during the year are expensed immediately instead of being capitalized;·
Asset retirement obligations – requirements for discounting future asset retirement obligations differ between current Canadian GAAP and IFRS.  Under Canadian GAAP a credit-adjusted rate was used to discount the obligation.  Under IFRS a risk-free rate will be used to discount the obligation.  This adjustment is expected to result in an increase of asset retirement obligations of $4 - 6 million at January 1, 2010.  The increase is expected to result in lower accretion expense under IFRS in 2010;·
Impairment testing – testing for impairment is performed at a more detailed component level under IFRS.  This has resulted in the identification of impairments of $7 - 11 million at January 1, 2010.  The impairment is expected to result in lower IFRS depletion expense for 2010; and·
Financial instruments – accounting for financial instruments differ between current Canadian GAAP and IFRS. Certain instruments recorded as equity under Canadian GAAP will be liability classified under IFRS.  As a result of the valuations of the financial instruments, the equity portion of preferred shares and warrants will decrease by a maximum of $2.9 million and $0.3 million respectively, with the balance being adjusted against the Company’s deficit at January 1, 2010.





The above overview is subject to change based on new facts and circumstances and considerations by management.  It is intended to highlight the areas expected to be impacted on transaction date.  Most adjustments required on transition to IFRS will be made retrospectively against opening retained deficit in the first comparative balance sheet.  The Company will complete its determination of the transition date adjustments prior to the finalization of the 2011 first quarter interim financial statements.  At that time, management will also have determined the impact the above changes have on the comparative information for 2010.






2010 MD&A
Page 19














IFRS 1 provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application. Management is analyzing the various options available and will implement those determined to be the most appropriate for the Company, which at this time are summarized as follows:





·
Oil and gas assets previously accounted for using full cost accounting will be transitioned to IFRS compliant accounting using the exemption provided in IFRS 1 instead of applying IFRS retrospectively;·
Business combination rules will be applied prospectively from January 1, 2010, rather than retrospectively restating all business combinations prior to January 1, 2010; and·
Capitalization of borrowing costs will be applied to qualifying assets on or after January 1, 2010.




In accordance with the transition plan, the Company is continuing the process of evaluating its accounting policy choices, quantifying their expected effects and making recommendations of chosen accounting policies to senior management for approval and presenting to the Audit Committee of the Board of Directors for their review. Continued development of draft financial statement formats and quantification of changes are included in this second phase and will continue through the first quarter of 2011.





The IFRS impact on internal control over financial reporting disclosure controls and procedures, business activities, financial reporting expertise and IT systems are also to be addressed in the manner as follows:





·
The Company will ensure controls are sufficiently robust to address the resulting changes and that accurate information about the conversion process is communicated to its stakeholders;·
The Company has been cognizant of the upcoming transition to IFRS and as such there are no foreseen issues with its counterparties or lenders;·
Training has been provided to key employees impacted by the conversion process and will continue throughout the transition. Technical training and information sessions will be presented to the Board and/or audit committee as required;·
The Company will continue to monitor standards development as issued by the International Accounting Standards Board and the AcSB, as well as regulatory developments as issued by the Canadian Securities Administrators which may affect the timing, nature or disclosure of the adoption of IFRS; and·
The final implementation phase includes the integration of the identified solutions into processes and financial systems required for the conversion to IFRS and the comparative reporting required for the year of transition. The required system and process changes will be integrated as confirmed and validated.





As the transition project progresses and outcomes are identified, the Company may change its intentions between the time of communication of these key milestones and the changeover date. Further, changes in regulation or economic conditions at the date of the changeover or throughout the project may result in changes to the transition plan communicated above.





Sensitivities





The following sensitivity analysis is provided to demonstrate the impact of changes in commodity prices in 2010 petroleum and natural gas sales and is based on the balances disclosed in this MD&A and the audited consolidated interim financial statements for the twelve months ended December 31, 2010:





($ thousands)
Petroleum and Natural Gas Sales (1)Change in average sales price for natural gas by $1.00/mcf
4,863Change in the average sales price for crude oil and natural gas liquids by $1.00/bbl
237Change in natural gas production by 1 mmcf/d (2)
1,712Change in crude oil and natural gas liquids production by 100 bbls/d (2)
2,466




(1)
Reflects the change in petroleum and natural gas sales for the twelve months ended December 31, 2010.


(2)
Reflects the change in production multiplied by the Company’s average sales prices for the twelve months ended December 31, 2010.






2010 MD&A
Page 20











Quarterly financial summary


(see note 1 below)


($ thousands except per share and production amounts)


2010
2009Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1ProductionNatural gas (mcf/d)
14,140
12,417
13,631
13,104
14,428
11,794
15,094
17,016Crude oil and natural gas liquids (bbl/d)
730
646
620
595
653
582
601
531Total (boe/d)
3,087
2,716
2,892
2,779
3,058
2,548
3,117
3,367Petroleum & natural gas sales (2)
10,488
8,868
9,310
10,107
9,935
5,913
8,132
9,792Net income (loss)
(71,263)
(6,910)
(17,663)
(2,164)
(63,903)
29,456
(9,888)
(8,986)Net income (loss) per share – basic
(1.17)
(0.11)
(0.28)
(0.04)
(1.62)
0.85
(0.29)
(0.27)Cash flow from (used for) operations (3) (4)
(589)
1,199
481
2,918
3,671
(13,133)
(7,092)
(1,623)Cash flow from (used for) operations per share – basic (3) (4)
0.00
0.02
0.01
0.05
0.09
(0.38)
(0.21)
(0.05)


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


(2)Petroleum and natural gas sales and realized gains on financial instruments net of transportation costs


(3)Non-GAAP measures


(4)Prior period cash flow from (used for) operations has been revised to reflect the impact of foreign exchange on cash and cash equivalents





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 declining production and add incremental production through its on-going 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.·
From March 2009 to September 2009 the Company was under CCAA protection which negatively affected the Company’s net income (loss).·
In Q3 2009, the Company acquired Challenger and recorded a bargain purchase gain of $8.5 million and disposed of an undivided 45% interest in Block 5 (c) to a third party for a gain of $35.6 million.·
In Q4 2009, the Company recorded a write-down of $57.5 million related to its Canadian petroleum and natural gas properties.·
In Q2 2010, the Company recorded a write-down of $9.7 million related to its Canadian petroleum and natural gas properties.·
In Q4 2010, the Company recorded a write-down of $29.1 million related to its Canadian petroleum and natural gas properties.·
In Q4 2010, the Company recorded an impairment on assets held for sale of $31.9 million related to the LNG project, which was sold in Q1 2011.




Please refer to the other sections of this MD&A for the detailed discussions on changes for the fourth quarter ending December 31, 2010, and to the Company’s previously issued interim and annual MD&A for changes in prior quarters.






2010 MD&A
Page 21











The following table summarizes the Company’s key financial results over the past three years:





For the years ending December 31
2010
2009
2008($ thousands except per share amounts)Petroleum and natural gas sales
36,880
34,582
75,730Net loss from continuing operations
(62,324)
(92,400)
(26,831)Net income (loss) from discontinued operations
(35,676)
39,079
3,073Net loss
(98,000)
(53,321)
(23,758)Loss per share from continuing operations – basic and diluted
($1.02)
($2.61)
($0.89)Income (loss) per share from discontinued operations – basic and diluted
($0.58)
$1.10
$0.10Loss per share – basic and diluted
($1.60)
($1.51)
($0.79)Total assets
268,381
291,832
420,216Total liabilities
95,111
81,637
178,494Dividends on preferred shares
774
718
941





The Company’s petroleum and natural gas sales and net income (loss) are impacted by production levels and commodity pricing. These production performance measures have all fluctuated throughout 2008, 2009 and 2010 as result of volatile oil and natural gas prices combined with increased cost of the Company’s operations.





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 Interim 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, 2010. 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, 2010 were effective.





In addition, during the quarter, there were no changes which would materially impact the Company’s internal control 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, 2010 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, 2010 and has concluded that such controls were effective as at that date.





Critical accounting estimates





To prepare the financial statements in accordance with GAAP, management is required to make judgments and estimates that could influence the financial results of the Company.  Management continually reviews its estimates, but changes in facts or circumstances may result in revised estimates and actual results may differ from these estimates. A summary of the Company’s critical accounting polices has been provided in Note 3 of the consolidated financial statements.  The Company's critical accounting estimates are discussed below.


2010 MD&A
Page 22











Petroleum and Natural Gas Reserves





The Company uses the full cost method of accounting for its oil and gas activities, which are dependent on estimated reserves that management believes, are recoverable from its oil and gas properties.  The process for estimating reserves is complex and subjective.  The Company's determination of reserves is based on a combination of:





·
geological, geophysical and engineering estimates;·
future production rates;·
future commodity prices; and,·
future development and operating costs.




Management believes these factors to be reasonable based on the information that is available as of the time of the estimate of reserves and is subsequently reviewed by its independent engineers.  Estimates of these factors can significantly change over time as additional data relating to development, production, pricing and costs is received for its oil and gas properties.





All of the Company’s reserves are evaluated and reported on by independent engineers in accordance with NI 51-101. In addition, the Company has established a Reserves Committee to assist the Board and the Audit Committee to review its oil and gas reserves and other related disclosures.  The Reserves Committee is comprised of three members of the Board.





The Company’s estimate of reserves impacts the accounting for depletion and impairment expense.  In addition,the Company’s borrowing base for the credit facility is determined based on estimates of proved reserves.


Full Cost Impairment





The Company evaluates its oil and gas properties for impairment if a significant event or change occurs.  This can include a significant decrease in oil and gas prices, revisions to proved reserves, changes in operating expenses or changes in its operating environment.





The Company’s oil and gas properties are evaluated for impairment by comparing the undiscounted future net cash flows of the property against its carrying value.  The property is written down to its fair value if the carrying value is greater than the calculated fair value.  The Company calculates the fair value based on the discounted cash flow approach.





The calculation of undiscounted future net cash flows by management requires significant assumptions to be made for future prices and reserves. The Company's estimates for future prices are based on benchmark prices compiled by independent engineers, adjusted to reflect risk management contracts, transportation expense or quality differentials.





Management believes the assessment of impairment of oil and gas properties is a critical accounting estimate primarily due to the complexity of the assumptions used in the calculation.





The Company’s oil and gas properties were evaluated for impairment.  Based on the Company’s estimates, the Company recorded an adjustment to the carrying value of the Company’s Canadian petroleum and natural gas properties of $29.1 million, for a cumulative ceiling test impairment recognized of $38.8 million in 2010 (December 31, 2009 – $57.5 million).





Goodwill Impairment





The Company tests goodwill for impairment whenever an event or circumstances occurs that may reduce the fair value of a reporting unit below its carrying amount and at least on an annual basis. The Company’s goodwill impairment test consists of a two-step process. In step one, the fair value of a reporting unit is compared to the carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds fair value the second step is required. The second step allocates the fair value of the reporting unit to its underlying assets and liabilities resulting in an implied fair value of goodwill. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss equal to the excess is recorded in the statement of operations.





The process of assessing goodwill for impairment involves determining the fair values of the Company’s assets using one or more valuation techniques including present value calculations of estimated future cash flows. This process involves various assumptions and judgments about future commodity prices, future income, operating






2010 MD&A
Page 23








costs and discount rates. Changes in these assumptions or judgments could result in an impairment of all or a portion of goodwill.





The Company’s goodwill was tested for impairment as at December 31, 2008. Based on this review, an impairment of goodwill of $10.4 million was recorded as a non-cash charge to the statement of operations at December 31, 2008.





Asset Retirement Obligations





The Company has a legal obligation associated with the retirement of present and former operating sites.  Management is required to make significant estimates and assumptions to calculate the estimated fair value of future retirement of its tangible assets.  This includes making estimates of future activities and environmental rules and regulations that could potentially impact the Company’s future retirement obligation.





The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred and records a corresponding increase in the carrying value of the related long-lived asset.  The fair value is determined through a review of engineering studies, industry guidelines and management’s estimate on a site-by-site basis.  The liability is subsequently adjusted for the passage of time and is recognized as accretion expense in the statement of operations.  The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability.  The increase in the carrying value of the asset is amortized using the unit-of-production method based on estimated proved developed reserves as determined by independent engineers.  Actual costs incurred upon settlement of the asset retirement obligations are charged against the asset retirement obligation to the extent of the liability recorded.  Any difference between the actual costs incurred upon settlement of the asset retirement obligations and the recorded liability is recognized as a gain or loss in the Company’s statement of operations in the period in which the settlement occurs.





Convertible preferred shares





The Company’s convertible debt instruments are segregated into their debt and equity components at the date of issue, based on the relative fair market values of these components in accordance with the substance of the contractual agreements. The debt component of the instruments is classified as a liability, and recorded at the present value of the Company’s obligation to make future interest payments in cash or in a variable number of shares and  to settle the redemption value of the instrument in cash or at a fixed amount of approximately 33.33 common shares per one preferred share. The carrying value of the debt component is accreted to the original face value of the instruments, over their deemed life, using the effective interest method. The conversion option, which makes up the equity component of the instruments, is recorded using the residual value approach.





Income Taxes





The calculation of the Company’s income tax provision and future income tax liability is complex and requires making certain judgments and constant review of laws and regulations in multiple jurisdictions.  Changes in facts and circumstances as a result of income tax audits, reassessments and changes in existing legislation could result in a corresponding increase or decrease in the Company's provision for income taxes.





Risk assessment





There are a number of risks facing participants in the oil and gas industry.  Some of the risks are common to all business, while others are specific to a sector.  The following reviews the general and specific risks to which the Company is exposed.  The Company's management realizes that these risks cannot be eliminated; however they are committed to monitoring and mitigating these risks.


Risk Management
 
 In order to manage the Company’s exposure to commodity price, interest rate and foreign exchange risk, the Company developed a risk management policy.  Under this policy, it may enter into agreements, including fixed price, forward price, physical purchases and sales, futures, currency swaps, financial swaps, option collars and put options.  The Board evaluates and approves the need to enter into such arrangements.
 
 Environmental and Safety


The oil and natural gas industry is subject to environmental regulations pursuant to municipal, provincial and federal legislation in Canada and similar legislation in other countries.  Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and gas operations.  The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of the applicable regulatory authorities.  A breach of such






2010 MD&A
Page 24








legislation may result in the imposition of fines or penalties, some of which could be material.  The Company is committed to meeting and exceeding environmental and safety standards.





The Board and the Company’s management team monitor, develop and implement policies and procedures to mitigate the environmental and safety risks of the Company.





Reserve Replacement





The Company is dependent on its ability to find, acquire, develop and produce oil and natural gas reserves.  The Company will need to continually add new reserves to offset the natural decline and production from existing reserves.  The Company’s ability to increase reserves is dependent on its ability to explore and develop its existing properties as well as its ability to select and acquire new properties or projects.  There is no assurance that the Company will continue to be able to explore, develop or acquire the reserves necessary to offset the natural decline and production from its existing reserves.





To mitigate this risk, the Company has assembled a team of experienced technical professionals who have expertise operating and exploring in the core areas of the Company.  In addition, the Company targets prospects that have multi-zone potential and employs advanced geological and geophysical techniques to increase the likelihood of finding additional reserves.





Reserve Estimates





There is significant uncertainty inherent in the estimating of economically recoverable oil and gas reserves (including natural gas liquids) and the future net cash flows to be derived from these reserves.  The Company’s reserves are estimated by an independent engineering firm.  Estimates are made based on a number of variable factors and assumptions, including future oil and gas prices, projected production rates, timing and amount of capital expenditures, future operating expenses and royalties and impact of regulation by government agencies.  The Company’s actual production and future cash flows may vary from its estimates, and such variations could be material.





Operational





Oil and gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas release and oil spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or in personal injury.  In accordance with industry practice, the Company is not fully insured against all of these risks, nor are all such risks insurable.  The Company maintains liability insurance in an amount that it considers consistent with industry practice.  However, due to the nature of these risks it is possible that liabilities could exceed policy limits, which could cause the Company to incur significant costs that could have a materially adverse effect on its financial condition.  Oil and natural gas operations are also subject to additional risks, including premature decline of reservoirs and the invasion of water into producing formations.





The Company’s future oil and gas exploration and development activities are dependent on the Company’s ability to engage drilling and related equipment in the particular areas where the activities will be conducted.  Demand for limited equipment or access restrictions may affect the Company's ability to complete future exploration and development activities.  The Company is exposed to additional risks associated with oil and gas properties where the Company is not the operator, and is dependent on the timing and success of such operators as the Company will largely be unable to direct or control the activities.  The Company attempts to mitigate these risks by developing strong relationships with existing and potential partners, suppliers and contractors.





Commodity Prices and Marketing





The Company is exposed to fluctuations in prices for natural gas, crude oil and natural gas liquids, as the majority of the Company's production is currently sold at spot prices that are subject to volatile trading activity.  Commodity prices fluctuate in response to, among other things, domestic and foreign supply and demand, import andexport balances, government regulations, weather, and fluctuations in the availability and price of other replacement energy sources.  A significant drop in commodity prices could materially impact the Company's petroleum and natural gas sales, the volume of production it could produce economically, require downward adjustments to proved reserves and could materially impact the Company's financial condition.
 
 In addition, a substantial decrease in commodity prices could impact the Company’s borrowing base under the credit facility, therefore reducing the credit facility available, and in some instances, require a portion of the credit facility to be repaid.
   2010 MD&A
Page 25













The Company’s ability to market its natural gas may depend on its ability to acquire space on pipelines that deliver natural gas to commercial markets.  The Company may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and facilities as well as extensive government and regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.





Liquidity and Capital Resources


The Company will continue to require significant capital expenditures for the exploration, development, acquisition and production of oil and gas reserves in the future.  The Company's capital program is currently funded by cash flow from operations and credit facilities.  The Company is currently dependent on completing the sale of the Trinidad and Tobago assets for $US75.5 million less transactions costs to implement its business strategy. In the event the proposed sale does not take place, the Company will be required to defer some of its Western Canada drilling program and activities in North Africa.  From time to time, the Company will review alternatives for raising additional debt or equity, on favourable terms, to finance its exploration, development, acquisition and production of oil and gas reserves. Cash flow from operations, equity financing and credit facility utilization may not be sufficient to fund the necessary capital requirements to undertake or complete future drilling programs, including key joint venture partners’ ability to fund their share of expenses and if so, there can be no assurance that additional debt or equity financing will be available to meet the requirements on acceptable terms. The level of indebtedness of the Company, from time to time, could impair its ability to obtain additional financing in the future and to take advantage of future business opportunities.


Technology
 
 The Company relies on information technology to manage its day-to-day operations and perform reporting obligations, including the preparation of financial statements, reporting to joint venture partners and various governments in relation to payment of royalties and taxes.
 
 Regulatory
 
 Oil and gas operations, both domestically and internationally, are subject to extensive controls and regulations imposed by various levels of government that may be amended from time to time.  The Company’s operations may require licenses and permits from various governmental authorities.  There can be no assurance that the Company will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development of its projects.


Title to Properties





Although title reviews may be conducted prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat a claim of the Company, which could result in a reduction of the revenue received by the Company.





Conflicts of Interest





Certain of the directors and officers of the Company are also directors and officers of other oil and gas companies involved in oil and gas exploration and development, and as such may, in certain circumstances, have a conflict of interest requiring them to abstain from certain decisions.





Reliance on Key Personnel





The Company is largely dependent on the performance of its management and key employees.  The Company does not carry any key person insurance in effect for management or key employees, and therefore, there is a risk that the loss of services of such key personnel could have a material adverse effect on the Company.  In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Company can continue to attract and retain all personnel necessary to ensure the continued exploration, development and operation of its business.  Investors must rely on the ability, expertise, judgment, discretion, integrity and good faith of management.






2010 MD&A
Page 26











Advisories





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





·
obtaining Trinidad and Tobago Ministry of Energy and Energy Industries (“MEEI”) approval of the Niko Sale Agreement and closing the transactions contemplated therein;·
volume and product mix of the Company's oil and gas production;·
future oil and gas prices and interest rates in respect of the Company's commodity risk management programs;·
future liquidity, creditworthiness and financial capacity;·
volumes and estimated value of the Company's oil and gas reserves;·
future results from operations and operating metrics;·
the life of each of the Company's reserves;·
future interest rates;·
future costs, expenses and royalty rates;·
future development, exploration and other expenditures;·
the amount and timing of future asset retirement obligations, and·
the Company's tax pools.




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





·
the ability to obtain MEEI approval of the Niko Sale Agreement and close the transactions contemplated therein;·
the ability of the Company of the Company to implement a plan of development for the 7th of November Block;·
the ability of the Company to obtain financing on acceptable terms;·
field production rates and decline rates;·
the ability of the Company to secure adequate product transportation;·
the impact of increasing competition in or near the Company's properties;·
the timely receipt of any required regulatory approvals;·
the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner to develop its business;·
the Company's ability to operate the properties in a safe, efficient and effective manner;·
the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration;·
the timing and costs of pipeline, storage and facility construction and expansion;·
future oil and natural gas prices;·
currency, exchange and interest rates;·
the regulatory framework regarding royalties, taxes and environmental matters; and·
the ability of the Company to successfully market its oil and natural gas products.




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






2010 MD&A
Page 27













By its nature, forward-looking information is subject to a number of risks and uncertainties, which could cause actual results or other expectations to differ materially from those anticipated, including those material risks set forth under “Risk Assessment” in the MD&A and “Risk Factors” in the Company’s 2010 Annual Information Form. The Company is exposed to several operational risks inherent in exploiting, developing, producing and marketing crude oil and natural gas.  These risks include but are not limited to:





·
the failure to obtain MEEI approval of the Niko Sale Agreement and to close the transactions contemplated therein;·
the unknown impact of the turmoil in Tunisia and Libya on the Company’s rights and obligations for the development of the 7th of November Block;·
the unknown impact of the Libyan Sanctions on the Company's obligations and development of the 7th of November Block;·
the unsettled and volatile political and security situations in Libya and Tunisia;·
sufficient liquidity for future operations;·
cost of capital risk to carry out the Company's operations;·
economic risk of finding and producing reserves at a reasonable cost;·
reliance on reserve estimates for the year as well as on acquisitions;·
financial risk of marketing reserves at an acceptable price given market conditions;·
fluctuations in commodity prices, foreign exchange and interest rates;·
operational matters related to non-operated properties;·
delays in business operations, pipeline restrictions, blowouts;·
debt service and indebtedness may affect the market price of the Common Shares;·
the continued availability of adequate debt and equity financing and cash flow to fund planned expenditures;·
unforeseen title defects;·
aboriginal land claims;·
increased competition and the lack of availability of qualified personnel or management;·
loss of key personnel;·
ability to attract key personnel, including the hiring of a Chief Financial Officer;·
uncertainty of government policy changes;·
the risk of carrying out operations with minimal environmental impact;·
operational hazards and availability of insurance;·
industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced;·
general economic, market and business conditions;·
competitive action by other companies;·
the ability of suppliers to meet commitments;·
stock market volatility;·
obtaining required approvals of regulatory authorities;·
creditworthiness of counterparties; and·
failure to realize anticipated benefits of the Arrangement.




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





Additional Information





Additional information relating to the Company 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.






2010 MD&A
Page 28