Exhibit 1.3






Management's Discussion and Analysis of Financial Condition and Results of Opera­tions for the fiscal year ended December 31, 2009







MANAGEMENT'S DISCUSSION AND ANALYSIS





This Management's Discussion and Analysis ("MD&A") has been prepared by management as ofMarch 29, 2010 and reviewed and approved by the Board of Directors (the “Board”) of Canadian Superior Energy Inc. ("Canadian Superior" or the "Company").  This MD&A is a review of the operational results of the Company with disclosure of oil and gas activities in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") 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 and accompanying notes for the years ended December 31, 2009 and 2008.





Non-GAAP Measures – This MD&A contains the term cash flow from operations 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 operations and operating netback are relevant indicators of the Company’s financial performance, ability to fund future capital expenditures and repay debt.  Cash flow from 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 operations section of this MD&A, reconciliation has been prepared of cash flow from 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 boes may be misleading, particularly if used in isolation.  Readers should be aware that historical results are not necessarily indicative of future performance.





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.





Business Overview and Strategy





Canadian Superior Energy is engaged in the exploration for, and acquisition, development and production of petroleum and natural gas with operations in Western Canada, offshore the Republic of Trinidad and Tobago and North Africa. The Company is also engaged in a proposed development of a liquefied natural gas in U.S. federal waters offshore New Jersey (the “LNG Project”).





Canadian Superior derives all of its production and cash flow from Western Canada. The Company’s Western Canadian oil and gas assets are primarily high working interest properties that are geographically concentrated in three areas with multi-zone opportunities, the most significant being Drumheller, Alberta, which accounts for approximately 65% of the Company’s production.





On March 5, 2009, Canadian Superior made an application for protection under the Companies’ Creditors Arrangement Act (“CCAA”). Canadian Superior remained under CCAA during most of 2009 which precluded drilling and maintenance spending on the Western Canadian assets resulting in a declining production base and decreased reserve adds in the year.





In December 2009 the Company relinquished the majority of its licenses with respect to offshore Nova Scotia but retained a reduced shallow water block located approximately nine kilometers northeast of Sable Island.  Over the years the Company has reviewed alternatives to either sell down its working interest or to dispose of its interests in their entirety. With less than favorable current industry environment and market conditions on the East Coast of Canada, the Company determined the future capital investment required could be of greater significance to long term shareholder value if redeployed into other assets within the Company’s portfolio.








Canadian Superior Energy Inc.
2009 MD&A
Page 1











In Trinidad and Tobago during 2009, operatorship of the Block 5(c) project transferred from the Company to BG International Limited (“BG”). In addition, the Company as part of its restructuring plan to exit CCAA acquired Challenger Energy Corp. (“Challenger”), including their 25% interest in Block 5(c) and subsequently disposed of an undivided 45% interest to BG, reducing the Company’s overall interest from 70%, to 25% by September 2009.





With the Company exiting CCAA in September 2009, constituting a new board, negotiating a new banking arrangement and completing an equity raise in January 2010, the Company is focused on the maximization of long-term sustainable value to its shareholders by:





·
Hiring a Chief Executive Officer with the skills and strategic vision to extract value from the Company’s assets while pursuing new areas of growth;·
Developing the Western Canadian asset base to increase daily average production along with replacement of producing reserves on an economic and cost effective basis;·
Increasing the value of the Company’s interests in Trinidad and Tobago through a vigilant and realistic development plan  in Block 5(c)  with the Company’s partner BG;·
Conducting an appraisal of the “7th of November Block” in Tunisia and Libya for possible development and additional exploration;·
Seeking synergistic growth opportunities in existing and new areas; and·
Re-imaging the Company and building an ethical and transparent business culture.





The success of the Canadian Superior’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, the ability to attract equity investment, hiring and retaining qualified personnel and managing political and government risk.





Business Environment





In 2009, with the Company in CCAA, the Company was significantly impacted operationally and financially due to considerable restructuring and settlement costs incurred to exit CCAA. In addition, the Company faced a reduced demand for natural gas caused by a world-wide recession combined with an increased supply of natural gas which resulted in record natural gas storage levels. These factors lead to extremely low natural gas spot prices for much of the year. These low gas prices along with decreasing production and restructuring costs negatively impacted the cash flow for the Company and its ability to reinvest in Western Canada.





In addition, the Company’s reserve evaluation was negatively impacted by lower gas price forecasts and lack of drilling activity as a result of management’s requirements to operate within cash flow as dictated by the courts during CCAA.





As the Company moves forward, it will emphasize improvements to cash flow through a focus on reducing its cost structure and increasing its operating efficiencies. The Company remains optimistic in the long term supply and demand fundamentals for natural gas.








Canadian Superior Energy Inc.
2009 MD&A
Page 2











Operating netback and cash flow from operations


($ thousands)
($ per boe)Three months ended December 31
2009
2008
% change
2009
2008
% changeRevenuePetroleum and natural gas sales
10,242
13,331
(23)
36.40
45.01
(19)Realized losses on financial instruments
--
40
n/a
--
0.14
n/aTransportation
(307)
(158)
94
(1.09)
(0.53)
106Royalties
(565)
(3,271)
(83)
(2.01)
(11.04)
(82)9,370
9,942
(6)
33.30
33.58
(1)Operating expenses
(3,232)
(2,983)
8
(11.49)
(10.07)
14Operating netback(1)
6,138
6,959
(12)
21.81
23.51
(7)General and administrative
(2,685)
(3,943)
(32)
(9.54)
(13.31)
(28)Asset retirement expenditures
--
(169)
n/a
--
(0.57)
n/aForfeiture of Nova Scotia Term Deposits
--
416
n/a
--
1.40
n/aInterest and other income
658
248
165
2.34
0.84
179Foreign exchange gain (loss)
(535)
1,892
(128)
(1.90)
6.39
(130)Interest
105
(515)
120
0.37
(1.74)
(121)Bad debt
(49)
(218)
(78)
(0.17)
(0.74)
(77)Restructuring costs
34
--
n/a
0.12
--
n/aCapital taxes
--
(16)
n/a
--
(0.05)
n/aCash flow from operations(1)
3,666
4,654
(21)
13.03
15.73
(17)Changes in non-cash working capital
1,370
(1,969)
170
4.87
(6.65)
173Cash from by operating activities
5,036
2,685
88
17.90
9.08
97(1)           Non-GAAP measure








($ thousands)
($ per boe)Twelve months ended December 31
2009
2008
% change
2009
2008
% changeRevenuePetroleum and natural gas sales
34,582
75,730
(54)
31.37
60.12
(48)Realized losses on financial instruments
--
(496)
n/a
--
(0.39)
n/aTransportation
(810)
(771)
5
(0.73)
(0.61)
20Royalties
(2,678)
(14,404)
(81)
(2.43)
(11.43)
(79)31,094
60,059
(48)
28.21
47.69
(41)Operating expenses
(13,546)
(14,197)
(5)
(12.29)
(11.27)
9Operating netback(1)
17,548
45,862
(62)
15.92
36.42
(56)General and administrative
(13,507)
(14,074)
(4)
(12.25)
(11.17)
10Asset retirement expenditures
(462)
(398)
16
(0.42)
(0.32)
31Forfeiture of Nova Scotia Term Deposits
--
416
n/a
--
0.33
n/aInterest and other income
1,456
700
108
1.32
0.56
136Foreign exchange gain
418
3,877
(89)
0.38
3.08
(88)Interest
(5,663)
(2,248)
152
(5.14)
(1.78)
189Bad debt
(161)
(218)
(26)
(0.15)
(0.17)
(12)Restructuring costs
(18,821)
--
n/a
(17.07)
--
n/aCapital taxes
--
(16)
n/a
--
(0.01)
n/aCash flow from (used for) operations(1)
(19,192)
33,901
(157)
(17.41)
26.94
(165)Changes in non-cash working capital
(6,092)
(1,240)
391
(5.53)
(0.98)
464Cash from (used for) operating activities
(25,284)
32,661
(177)
(22.94)
25.96
(188)


(1) Non-GAAP measure





For the three months ended December 31, 2009, cash flow from operations was $3.7 million compared to $4.7 million in 2008. For the twelve months ended December 31, 2009, cash flow used for operations was ($19.2) million compared to cash flow from operations of $33.9 million in 2008. The decrease for the twelve months ended in 2009 is mainly due to the Company incurring approximately $18.8 million in restructuring costs, $2.8 million in interest costs and one time general and administrative expenses (“G&A”) related to its CCAA proceedings and the receivership of the Block 5(c) asset in Trinidad and Tobago. In addition, the Company incurred lower operating netbacks as a result of decreased commodity prices and natural production declines in 2009.








Canadian Superior Energy Inc.
2009 MD&A
Page 3






Production


Three months ended

December 31
Twelve months ended

December 312009
2008
2009
2008Natural gas (mcf/d)
14,428
15,726
14,569
16,685Crude oil and natural gas liquids(bbls/d)
653
599
592
661Total Production (boe/d) (6:1)
3,058
3,220
3,020
3,442





Fourth quarter production averaged 3,058 boe per day and for the twelve months ended December 31, 2009 averaged 3,020 boe per day. The decrease compared to 2008 is due to normal declines in production, the inability to tie-in the successful wells from the 2008 drilling program and the postponement of the 2009 drilling program until the Company exited from CCAA protection on September 15, 2009.





Petroleum and natural gas sales, net of transportation





Three months ended

December 31
Twelve months ended

December 31($ thousands, except where otherwise noted)
2009
2008
2009
2008Petroleum and natural gas sales, net of transportationNatural gas
6,402
10,405
21,741
52,870Realized gain(losses) on financial instruments
--
40
--
(496)6,402
10,445
21,741
52,374Crude oil and natural gas liquids
3,410
2,768
11,908
22,089Total
9,812
13,213
33,649
74,463Average sales priceNatural gas ($/mcf)
4.82
7.22
4.09
8.58Crude oil and natural gas liquids($/bbl)
56.73
50.25
55.09
91.32Total($/boe)
34.87
44.48
30.52
59.51





For the three months ended December 31, 2009, petroleum and natural gas sales, net of transportation (“petroleum and natural gas sales”) were $9.8 million, consisting of $6.4 million in natural gas and $3.4 million of crude oil and natural gas liquids sales. For the twelve months endedDecember 31, 2009, petroleum and natural gas sales were $33.6 million, consisting of $21.7 million in natural gas and $11.9 million of crude oil and natural gas liquids sales.





During the fourth quarter, Canadian Superior realized an average sales price of $34.87 per boe compared to $44.48 per boe in 2008. For the twelve months endedDecember 31, 2009, the Company realized an average sales price of $30.52 per boe compared to $59.51 per boe in 2008.  The decrease in petroleum and natural gas sales is mainly due to the significant decline in commodity prices combined with natural declines in production volumes in 2009 compared to 2008.  In addition, during CCAA the Company was unable to tie-in the successful wells from the 2008 drilling program and was forced to postpone the 2009 drilling program to November and December 2009 until the Company exited from CCAA protection on September 15, 2009.







Canadian Superior Energy Inc.
2009 MD&A
Page 4








Royalties





Three months ended

December 31
Twelve months ended

December 31($ thousands, except where otherwise noted)
2009
2008
2009
2008RoyaltiesCrown
319
2,760
1,811
11,529Freehold and overriding
246
511
867
2,875Total
565
3,271
2,678
14,404Royalties per boe ($)
2.01
11.04
2.43
11.43Average royalty rate (%)
5.8
24.8
8.0
19.3





Canadian Superior pays royalties to provincial governments, freehold landowners and overriding royalty owners.  Royalties are calculated and paid based on petroleum and natural gas sales net of transportation.  Natural gas and liquids royalties for the twelve months ended December 31, 2009 were $2.7 million or 8.0% of total petroleum and natural gas sales compared to $14.4 million or 19.3% in 2008.





The decrease in 2009 crown royalties is mainly due to the Company receiving $1.5 million in favourable custom processing and capital cost deductions in the third quarter and reduced royalty rates under the new Alberta royalty framework.  In addition, the Company recorded $0.5 million of favourable payouts 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.  Lower average realized prices have also contributed to the decrease in royalties.





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.





Operating expenses





Operating expenses were $3.2 million or $11.49 per boe for the fourth quarter of 2009 compared to $3.0 million or $10.07 per boe in 2008. For the twelve months ended December 31, 2009, operating expenses were $13.5 million or $12.29 per boe compared to $14.2 million or $11.27 per boe. The increase in operating expenses during the fourth quarter is attributable to decreased production while fixed costs remained constant. The decrease for the twelve months ended December 31, 2009 is mainly due to reduced costs incurred under the cost rationalization policy implemented by the Company during the CCAA proceedings which was partially offset by the recording of approximately $0.9 million of additional operating costs identified during the CCAA creditor claims process. The operating costs on a per boe basis are higher in 2009 due to decreased production in 2009 compared to 2008.




General and administrative expenses





Three months ended

December 31
Twelve months ended

December 31($ thousands, except where otherwise noted)
2009
2008
2009
2008Gross general and administrative expense
5,131
9,751
24,457
31,019Capitalized general and administrative expense
(2,446)
(5,808)
(10,950)
(16,945)Net general and administrative expense
2,685
3,943
13,507
14,074General and administrative expense ($/boe)
9.54
13.31
12.25
11.17





Fourth quarter G&A was $2.7 million or $9.54 per boe compared to $3.9 million or $13.31 per boe in 2008. For the twelve months ended December 31, 2009, G&A was $13.5 million or $12.25 per boe compared to $14.1 million or $11.17 per boe in 2008. The decrease in gross G&A from 2008 is mainly due to decreased activity related to the LNG Project during CCAA which was partially offset by the payment of one time executive contract settlements in connection with the departures of the Executive Chairman and the President and Chief Executive Officer of the Company in April 2009.








Canadian Superior Energy Inc.
2009 MD&A
Page 5








Restructuring costs





During the twelve months ended December 31, 2009, the Company incurred $18.8 million (December 31, 2008 – 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 and legal costs incurred by the Receiver, BG and the Company’s former banker being charged back to the Company.




Stock based compensation





During the twelve months ended December 31, 2009, Canadian Superior incurred stock based compensation expenses of $3.1 million compared to $6.4 million in 2008. The decrease is due to significant grants of options becoming fully vested in 2008 and the stock option grant price being lower during 2009 compared to the same period in 2008.





On October 16, 2009, the Board of Directors approved a plan to make a substantial portion of the compensation of the directors in the form of long term equity based grants. This plan reflects the Board’s belief that the directors should develop a meaningful equity position in the Company and that a major portion of each director’s compensation should be tied to the long term performance of the Company. Under the plan, the Board granted 1,338,000 stock units to the directors under the terms of the stock unit award agreements. 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 units vest the earlier of December 31, 2012 or the date the Company incurs a change of control. The stock units vest ratably in the event a director leaves the Board for any reason. If subsequent to the grant date, the shareholders of the Company approve an equity compensation plan under which the stock units may be paid with common shares of the Company, then the Board may determine that the stock units may be paid in cash or common shares.  At December 31, 2009, the Company recorded a liability of $0.1 million to recognize the fair value of the vested stock units.





On January 18, 2010, the Company granted an additional 206,000 stock unit awards to a newly appointed director of the Company.





Depletion, depreciation and accretion





Depletion, depreciation and accretion ("DD&A") was $34.0 million or $30.83 per boe for the twelve months ended December 31, 2009.The calculation of depletion and depreciation included an estimated $13.2 million (December 31, 2008 - $12.5 million) for future development capital associated with proven undeveloped reserves and excluded $123.0 million (December 31, 2008 - $123.6 million) related to unproved properties and projects under construction or development.  Of the costs excluded $9.0 million (December 31, 2008 - $22.7 million) relates to Western Canada, $20.7 million (December 31, 2008 - $5.5 million) to East Coast Canada, $70.0 million (December 31, 2008 - $80.6 million) to Trinidad and Tobago, $19.7 million (December 31, 2008 – $12.3 million) to the LNG Project and $3.6 million (December 31, 2008 – $2.5 million) for offshore Libya/Tunisia. Canadian Superior’s DD&Aper boe is higher than expected due to significant prior years expenditures to drill and evaluate the Company’s offshore wells in the East Coast of Canada being included in the depletable base with no associated proven reserves reflected.





At December 31, 2009, the Company recorded an impairment on the carrying value of the Canadian petroleum and natural gas assets of $57.5 million (December 31, 2008 – nil). The write-down was primarily affected by reduced reserve volumes and reduced prices for 2009 compared to 2008. In addition, approximately $40.0 million of unproved properties were added to the full cost pool, including $20.7 million related to East Coast licenses. This write-down should have the effect of reducing the DD&A charge per boe in future periods.





Income taxes





Canadian Superior’s current and future income taxes are dependent on factors such as production, commodity prices and tax classification of drilled exploration and development wells. The Company had a future income tax recovery for the twelve months ended December 31, 2009 of $14.7 million (December 31, 2008 - $3.0 million)








Canadian Superior Energy Inc.
2009 MD&A
Page 6









For the twelve months ended December 31, 2009, the Company has estimated $236.9 million in tax pools and $71.7 million in non-capital losses that are available for future deduction against taxable income.





December 31($ thousands)
2009Canadian exploration expense
52,502Canadian oil and gas property expense
40,553Canadian development expense
32,643Undepreciated capital costs
29,116Share issue costs
6,520Foreign exploration expense
74,843Other
757Total
236,934





Non-capital losses expire as follows:





($ thousands)2010 - 2020
--2021 - 2025
652026 - 2029
71,65771,722





Capital expenditures





Three months ended

December 31
Twelve months ended

December 31($ thousands)
2009
2008
2009
2008Exploration and development
15,327
32,933
89,969
94,071Plants, facilities and pipelines
1,363
3,276
2,348
5,028Land and lease
224
876
1,330
3,775Capitalized general and administrative expenses
2,446
5,808
10,950
16,945Exploration and development expenditures
19,360
42,893
104,597
119,819Proceeds on dispositions
--
--
(155,706)
--Net capital expenditures
19,360
42,893
(51,109)
119,819





The Company invested $104.6 million for capital expenditures during the twelve months ended December 31, 2009, of which the majority was spent to drill, test and evaluate the third offshore Trinidad well “Endeavour”. In addition, during the fourth quarter the Company expended $13.5 million in Western Canada to drill 13 gross wells (11.4 net), which satisfies the flow-through commitment by December 31, 2009. The Company invested $7.4 million (December 31, 2008 - $12.3 million) in the LNG Project. The LNG Project is on budget and moving forward with submission for permitting planned for July of 2010.








Canadian Superior Energy Inc.
2009 MD&A
Page 7











Dispositions





Block 5(c) Trinidad and Tobago





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 2, 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) Trinidad for gross proceeds of US$142.5M. The sale was executed as part of the Company’s CCAA Plan of Arrangement.





Proceeds from disposition


$CDNCash


155,377Transaction costs


(8,733)Net proceeds


146,644Net assets disposed at carrying valueProperty, plant and equipment


(116,530)Asset retirement obligation


5,522(111,008)Gain on disposition


35,636





Western Canada - Gross overriding royalty and seismic data





During the first quarter of 2009, the Company sold gross overriding royalties and seismic data in Western Canada for proceeds of $9.1 million of which $7.5 million of the proceeds were applied as a permanent reduction to the Company’s credit facility with its former bank.





Business Combinations





Challenger





On September 15, 2009, the Company completed the acquisition of Challenger for consideration of approximately 27.7 million common shares of Canadian Superior. 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 (27,728,346)


22,183





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








Canadian Superior Energy Inc.
2009 MD&A
Page 8








Seeker Petroleum Ltd.





On March 26, 2008, Canadian Superior completed the acquisition of Seeker Petroleum Ltd. for consideration of approximately $51.6 million.  The purchase was funded through the issuance of common shares of the Company and advances from the credit facility.





The acquisition was accounted for under the purchase method as follows:





ConsiderationCash


22,211Common shares (7,651,866)


28,465Transaction costs


88751,563





Net assets received at fair valueCash


1,716Working capital


(387)Fair value of financial instruments


(796)Property, plant and equipment


40,953Goodwill


10,365Asset retirement obligation


(1,243)Future income taxes


95551,563





Liquidity and capital resources





December 31
December 31($ thousands)
2009
2008Working capital surplus excluding revolving credit facility
14,722
2,034Revolving credit facility
(24,067)
(43,263)Working capital deficit
(9,345)
(41,229)





The Company was under CCAA creditor protection from March 5, 2009 to September 14, 2009 and emerged from CCAA protection on September 15, 2009.




As at December 31, 2009, Canadian Superior had a working capital deficiency of $9.3 million (December 31, 2008 – $41.2 million), the Company had drawn $24.1 million (December 31, 2008 - nil) against the $40.0 million (December 31, 2008 - nil) credit facility at a variable interest rate of prime plus 0.75% (December 31, 2008 – nil).  At December 31, 2008, the Company had drawn $43.3 million on a $45 million credit facility with its former bank. All amounts outstanding to its former bank were repaid on exiting from CCAA. The existing credit facility is secured by a $100 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company. The credit facility has covenants that require the Company to maintain its working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative expenditures in excess of $7.0 million per year and all foreign capital expenditures are neither funded from the credit facility nor domestic cash flow while the credit facility is outstanding. On October 28, 2009, the Company’s lender increased the credit facility from $25.0 million to $40.0 million.  The credit facility is subject for the next scheduled review in April 2010.





The Company had $3.3 million in cash and short-term deposits (December 31, 2008 - $6.0 million), $22.3 million is classified as restricted cash (December 31, 2008 – nil). At December 31, 2009, the Company forfeited its proportionate share of $15.2 million in the remaining Nova Scotia term deposits relating to the unexpended work commitment.





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.





Canadian Superior Energy Inc.
2009 MD&A
Page 9











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 the credit facility, therefore reducing the credit facility available for Western Canadian investment, and in some instances, require a portion of the credit facility to be repaid. Canadian Superior has entered into risk management contracts to mitigate its commodity price.   Management continues to review various other risk mitigating options. The Company’s future liquidity is also dependent on its ability to increase reserves and production through successful drilling activity and acquisitions. Canadian Superior’s 2010 exploration and development program for Western Canada will be financed through a combination of cash flow from operations and credit facility utilization. International operations will be funded to a certain extent of cash flow from operations and through additional equity financings, potential farm outs or joint ventures.





Contingencies and commitments





Block 5(c) Trinidad and Tobago





The Company is committed to participate as a 25% working interest partner in the future exploration and development of the “Intrepid” Block 5(c) project operated by BG. At December 31, 2009, BG held in escrow for Canadian Superior US$20 million whereby the Company must maintain the lesser of US$20 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 and the Government of Trinidad and Tobago.





MG Block Trinidad and Tobago





In 2007, the Company received an exploration and development license from the Government of Trinidad and Tobago on the Mayaro-Guayaguayare block (“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 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 estimates that its share of the cost of these wells to be approximately US$15.0 million per well. The estimated cost of the 3D seismic program is approximately US$30.0 million. The Company has 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 has 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. While the Company believes that its request remains under consideration, it is possible that the request will be denied and the Company may be required to pay some portion of the performance security amount in order to relinquish the MG Block.





Libya/Tunisia





On August 27, 2008, Canadian Superior entered into the 7th of November Block Exploration Production Sharing Agreement ("EPSA") with a Tunisian/Libyan company, Joint Exploration, Production, and Petroleum Services Company ("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 300 square miles of 3D seismic. The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15 million per exploration well and up to US$4 million for 3D seismic not completed. The Company has provided a corporate security to a maximum of US$49 million to secure its minimum work program obligations. Under the EPSA, the Company has also agreed to drill one appraisal well on the Zarat discovery extension within the EPSA contract area. The appraisal well obligation is secured by a fully insured bank guarantee for US$15 million to Joint Oil payable if a rig is not moved on location by August 26, 2010. This guarantee will be reduced upon the Company meeting specified milestones with respect to the appraisal well.





In July 2008, the Company entered into a Participation Agreement to use reasonable efforts to transfer a 50% interest to a third party upon execution of the EPSA. The interest is to be held in trust until the third party is recognized as a party to the EPSA. The third party 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.







Canadian Superior Energy Inc.
2009 MD&A
Page 10








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 Canadian Superior's "Mariner" Block, offshore Nova Scotia, Canada. If at the end of August 2011, no royalty well has been spud 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.





Litigation and claims





In December 2009, a class action lawsuit commenced in the United States District Court of the Southern District of New York against certain former executive officers and a current executive officer 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. The Company has not been named as a defendant in the case. The class action lawsuit purports to be brought on behalf of purchasers of common shares from January 14, 2008 to February 17, 2009. The defendants may seek indemnification from the Company for the expenses and costs of the lawsuit and in respect of any damages that may be awarded to the plaintiffs.  In such event, the Company will assess the indemnification obligations, if any, in respect of the amounts claimed. The Company carries director and officer liability insurance which may limit the indemnification obligations, if any, of the Company.





In addition, the Company may be involved in various claims and litigation arising in the ordinary course of business.  In the opinion of Canadian Superior the various claims and litigations arising there from are not expected to have a material adverse effect on the Company’s financial position.  The Company maintains insurance, which in the opinion of the Company, is in place to address any unforeseen claims.





Lease obligations


At December 31, 2009, 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:





2010
2011
2012
2013
Thereafter
TotalOffice rent

2,585
2,042
1,477
174
--
6,278Equipment

11
8
--
--
--
192,596
2,050
1,477
174
--
6,297





Subsequent Events





On January 19, 2010, the Company completed a private placement of 114,424,238 common shares at $0.52 per common share for gross proceeds of $59.5 million and appointed a new member to the Board effective January 18, 2010.





On February 3, 2010 the Company restructured the terms of the Preferred Shares. Pursuant to the terms of the restructuring, the Series A Preferred Shares were exchanged on a share for share basis for 150,000 series B preferred shares (the “Series B Shares”) pursuant to which the redemption date was extended from December 31, 2010 to December 31, 2011 and the conversion price was reduced from USD $2.50 to USD $0.60. In addition, the Company granted 2,500,000 common share purchase warrants exercisable at a price of USD $0.65 for each common share and expiring 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 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.





Related party transactions





On September 15, 2009, the Company acquired all the issued and outstanding common shares of Challenger for consideration of approximately 27.7 million common shares of Canadian Superior. Challenger is a company which Canadian Superior’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, Canadian Superior carried a receivable in the amount of $37.8 million (December 31, 2008 – $35.4 million), a $14.0 million bridge facility receivable and accrued interest receivable of $0.9 million from Challenger. These receivables pertain to costs incurred on Canadian Superior’s “Intrepid” Block 5(c) project incurred under normal industry terms and conditions.








Canadian Superior Energy Inc.
2009 MD&A
Page 11










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 Canadian Superior 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 Canadian Superior.





On September 23, 2008, Canadian Superior entered into a short-term $14.0 million bridge facility with Challenger to enable Challenger to close on a $30 million equity financing. During the fourth quarter of 2008, $14.0 million had been drawn and was used to satisfy Challenger’s share of direct and indirect costs in connection with the exploration program on the Block 5(c) project. The interest payable to Canadian Superior was based on an interest rate of 10% per annum on any outstanding balance. Challenger may pay interest incurred in common shares. During the twelve months ended December 31, 2009, 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 Canadian Superior. Challenger issued 500,000 non-transferable share purchase warrants to Canadian Superior which expired unexercised October 2, 2009. In addition, Challenger paid a standby fee of $0.1 million to Canadian Superior in 2008.  Challenger was in default on repayment of the bridge facility.





During the twelve months ended December 31, 2009, the Company paid $0.1 million (2008 - $2.3 million), on industry terms, for equipment rentals to a company controlled by the former Executive Chairman and director of Canadian Superior.  Also during 2009, the Company invoiced $0.1 million (2008 - $1.1 million), to this related party company for payroll services. Subsequent to March 31, 2009, the Company no longer provides payroll services to this company





On May 20, 2008, Canadian Superior announced its participation in the LNG Project. The LNG Project was to be conducted by a 50/50 joint venture between Canadian Superior and Global LNG Inc. (“Global”), a company controlled by the former Executive Chairman and director of Canadian Superior. Under the terms of the joint venture agreement Canadian Superior agreed to advance the first US$10.0 million of the pre-construction costs for the LNG Project. On August 13, 2009, the Company executed an agreement wherein the Company now owns 100% of the LNG Project and is responsible for 100% of the ongoing costs.  During the twelve months ended December 31, 2009, Canadian Superior incurred under normal industry terms and conditions $7.4 million (2008 – $12.3 million) of costs related to the LNG Project.





Off-balance sheet arrangements





The Company has no off-balance sheet arrangements.





Share capital





As at March 29, 2010 the Company had 311.5 million common shares, 9.9 million stock options, 150,000 Series B Preferred Shares and 200,000 common share purchase warrants issued and outstanding.





Financial Instruments





The carrying values of financial assets and liabilities approximate their fair value due to their short periods of maturity and the credit facility bearing interest at market rates.





Cash, short-term investments, restricted cash and Nova Scotia offshore term deposits are classified as financial assets held for trading and are measured at their fair value.  Gains or losses related to periodic revaluation are recorded to net income or loss.





Accounts receivable and the bridge facility 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 rate method.





Accounts payable, accrued liabilities, revolving credit facility and 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 rate method.





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








Canadian Superior Energy Inc.
2009 MD&A
Page 12








Risk Management





The Company’s main financial risks include credit risk, foreign exchange risk, interest rate risk and commodity price risk, and are discussed in detail in the notes to the Company’s December 31, 2009 financial statements, other sections of the MD&A as well as the 2009 Annual Information Form.
 
 In order to manage the Company’s exposure to these risks, 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.





a)      Credit risk





The Company’s accounts receivable and bridge facility 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, 2009, the maximum credit risk exposure is the carrying amount of the accounts receivable and accruals of $14.2 million (December 31, 2008 – $83.2 million). As at December 31, 2009, the Company’s receivables consisted of nil (December 31, 2008 - $51.8 million) of Block 5(c) joint interest receivables, $6.7 million (December 31, 2008 - $7.4 million) of Western Canada joint interest billings, $2.5 million (December 31, 2008 - $18.3 million) in value added tax receivable from the Government of the Republic of Trinidad and Tobago and $5.0 million (December 31, 2008 - $5.6 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 $0.4 million (December 31, 2008 - $0.3 million).





b)      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, 2009, the Company has US$0.6 million in cash and short-term investments (December 31, 2008 – US$3.6 million), US$20.9 million in restricted cash (December 31, 2008 – nil) nil (December 31, 2008 – US$31.1 million) of Block 5(c) joint interest receivables, US$2.4 million (December 31, 2008 – US$15.0 million) in value added tax receivable from the Government of the Republic of Trinidad and Tobago, US$1.0 million (December 31, 2008 – US$42.1 million) of Block 5(c) payables, US$0.5 million (December 31, 2008 – US$2.0 million) of LNG Project payables and US$14.6 million (December 31, 2008 – US$14.1 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 Libya/Tunisia. At this time, the Company has chosen not to enter into any risk management agreements to mitigate foreign exchange risk.





c)      Interest rate risk





The Company is exposed to interest rate risk as the credit facility bears interest at floating market interest rates.  The Company has no interest rate swaps or hedges to mitigate interest rate risk at December 31, 2009.





d)      Commodity price risk





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, geopolitical events, import andexport balances, government regulations, weather, commodity speculators 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.





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 hedging purposes and are not used for trading or other speculative purposes. The following commodity price risk contract was in place during the year ended December 31, 2008:








Canadian Superior Energy Inc.
2009 MD&A
Page 13








Term

Contract
Volume (GJs/d)
Fixed price
2008 realized lossesFeb 1, 2008 – October 31, 2008

Swap
2,000
$7.05
($496)





Effective January 1, 2010, the Company entered into the following natural gas price risk contract:





Term

Contract
Volume (GJs/d)
Fixed priceJan 1, 2010 – December 31, 2010

Swap
5,500
$5.50





Supplementary environmental disclosures





Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol which was established thereunder to set targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other emissions, all of which are collectively referred to as "greenhouse gases" or "GHGs".  The Canadian federal government indicated an intention to regulate the emissions of industrial GHG emissions from a range of industries in the Regulatory Framework for Air Emissions (the "Framework"), which Framework was supplemented on March 10, 2008 by the Federal Government via the release of "Turning the Corner - Taking Action to Fight Climate Change" (the "Update").  The Framework, as amended by the Update (collectively, the "Federal Plan"), outlines a number of policies to reduce GHG emissions intensity of certain regulated facilities (including oil and gas facilities) which were to implemented for 2010.  Under the Federal Plan, existing facilities are subject to mandatory GHG reductions of 18% from the 2006 baseline starting in 2010 with an additional 2% reduction for each subsequent year; new facilities (which are defined as those facilities whose first year of operation is 2004 or later) are to face intensity reduction requirements beginning in their fourth year of commercial production, of 2% per year from their "baseline" emissions intensity (which baseline is the emissions intensity for such facility's third year of commercial production) until at least 2020.  For the upstream oil and gas industry, the Federal Plan also provides for a company threshold of 10,000 boe per day and a facility threshold of 3,000 tonnes of C02. The proposed compliance options for facilities under the Federal Plan include: making emissions intensity improvements; making investments in certified carbon capture and storage projects; buying offsets or emissions performance credits; and for a portion of each entity's emissions reduction obligations, making payments of $15 per tonne until 2012, $20 per tonne in 2013 and an escalating annual rate per tonne thereafter; to the federal technology fund.  Draft regulations adopting the Federal Plan were expected to be available for public comment in the fall of 2008 but have not yet been released, and it is not known whether such regulations will be released or implemented.





The Canadian federal government is also working with the provinces and territories to develop a cap and trade system which is to ultimately be aligned with the emerging cap and trade system being developed by the United States.  No assurance can be given that either a modified Federal Plan or a North American cap and trade system will or will not be implemented, or what kinds of obligations will be imposed under such a system.





In February 2009, the United States and Canada established the 'Clean Energy Dialogue' in order for the two countries to collaborate on the development of clean energy science and technologies to reduce GHG emissions and combat climate change.  A number of working groups have been created to develop recommendations for joint initiatives.





At the July 2009 G8 Summit in Italy, Canada and the other G8 members agreed to work together toward achieving at least a 50% reduction of global GHG emissions by 2050.





In December 2009, Canada participated in COP 15 in Denmark, the goal of which was to reach a new agreement for fighting global climate change.  COP 15 resulted in the Copenhagen Accord, which committed Canada and the other participating countries to implement the quantified economy-wide emissions targets by 2020.  Canada submitted its non-legally binding target on January 30, 2010, noting that: (a) the emissions reduction target it set of 17% for the baseline year of 2005 is aligned with the final economy-wide emissions target and base year of the United States; and (b) its submission is dependent on the other parties to the Copenhagen Accord submitting emissions targets and mitigation actions in accordance with such Accord.  It is unclear how the new proposed national emission reduction target is to be met and whether the previous announced proposed Federal Plan will proceed or be replaced with a new framework.







Canadian Superior Energy Inc.
2009 MD&A
Page 14











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





The Company does not own any facilities that currently emit 50,000 tonnes or more of GHG and therefore is not currently impacted by this legislation. Accordingly, the Company has not incurred, nor does it anticipate incurring material costs relating to this GHG reduction program. However, no certainty exists that current thresholds upon which contributions are based under existing regulations, or the regulations as a whole will not change in the future. Such changes could materially impact the Company.





As at December 31, 2009, the Company has not recorded any significant costs and liabilities relating to the above initiatives and regulations, any other environmental protection laws and regulations, or environmental disasters. However, the Company has recognized, in its financial statements, asset retirement obligations representing estimates of costs to retire its assets at the end of their useful lives, which include estimated abandonment, surface reclamation and groundwater protection costs. Additional information on asset retirement obligation is disclosed in the Company’s financial statements and in other sections of this MD&A.





Adoption of new accounting policies





On January 1, 2009, the Company prospectively adopted CICA section 1582 Business Combinations. This section establishes principles and requirements of the acquisition method for business combinations and related disclosures. The acquisition of Challenger was accounted for in accordance with CICA section 1582.





On January 1, 2009, the Company adopted CICA sections 1601 Consolidated Financial Statements and 1602 Non-Controlling Interests. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for non-controlling interests in consolidated financial statements subsequent to a business combination. Adoption of the statement did not have a material impact on the Company’s statement of operations.





Effective December 31, 2009, the Company adopted the amendments to CICA section 3862 Financial Instruments – Disclosures. The amendments include enhanced disclosures relating to the fair value of financial instruments and the liquidity risk associated with financial instruments.




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 also 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. At this time the Company cannot reasonably estimate the impact of adopting IFRS on the Company’s consolidated financial statements.








Canadian Superior Energy Inc.
2009 MD&A
Page 15














Possible differences between current accounting policies under Canadian GAAP and expected accounting policies under IFRS include the following:





·
Depletion and depreciation of property, plant and equipment (“PP&E”) will be based on significant components. Under IFRS 1, the net book value of the PP&E will be allocated to the new cost centres on the basis of the Company’s reserve volumes or values as per the deemed cost election. Depletion of resource properties will generally continue to be calculated using the unit-of-production method but the Company has the option to base the calculation using proved reserves or proved and probable reserves. The Company has not concluded at this time which method it will use and will continue to monitor its peers to ensure comparability.·
Oil and gas properties will be classified as either PP&E or Exploration and Evaluation assets (E&E). Upon transition to IFRS, the Company will reclassify all E&E expenditures that are currently included in the PP&E balance on the Consolidated Balance Sheet. These assets will be measured at cost and will not be depleted but will be assessed for impairment when indicators suggest the possibility of impairment. E&E will primarily consist of undeveloped land and exploratory drilling costs.·
Under Canadian GAAP, impairment testing on oil and gas properties is performed at a cost centre level, while under IFRS, it will be performed at a lower level, referred to as a cash generating unit. This will result in a greater number of impairment tests.·
Under Canadian GAAP, the Company’s Asset Retirement Obligation calculation utilizes a credit adjusted risk free rate; however, IFRS requires the use of a discount rate that reflects the risks specific to the obligation.





Analysis is still in process and not all decisions have been made where choices of accounting policies are available. Until the analysis is complete, the Company is not able at this time to reasonably quantify the impact expected on its consolidated financial statements for these differences.





The Company’s IFRS conversion project consists of three phases: Phase 1 involves scoping and diagnostic work which includes planning and the identification of differences between current Canadian GAAP and IFRS; Phase 2 involves the detailed evaluation of relevant IFRS and their impact to financial disclosures, internal controls and operational and other business processes. Phase 2 also involves staff training and audit committee orientation; Phase 3 involves the recommendation, approval, implementation and review of the policies selected under IFRS and the related changes in processes and controls.





It is anticipated that the adoption of IFRS will have some impact on information systems requirements. The Company continues to assess its systems and implement the functionality requirements, upgrades and modifications that IFRS requires and to ensure an efficient conversion to IFRS.





In accordance with the Company’s approach to certification of internal controls required, all entity level information technology disclosure and business process controls will require updating and testing to reflect changes arising from the conversion to IFRS. Where material changes are identified, these changes will be mapped and tested to ensure that no material deficiencies exist as a result of the conversion to IFRS.




Sensitivities
 
 The following sensitivity analysis is provided to demonstrate the impact of changes in commodity prices on 2009 petroleum and natural gas sales and is based on the balances disclosed in this MD&A and the consolidated financial statements for the twelve months ended December 31, 2009:
 
 ($ thousands)
Petroleum and Natural Gas Sales (1)Change in average sales price for natural gas by $1.00/mcf
5,318Change in the average sales price for crude oil and natural gas liquids by $1.00/bbl
216Change in natural gas production by 1 mmcf/d (2)
1,493Change in crude oil and natural gas liquids production by 100 bbls/d (2)
2,011
  (1)
Reflects the change in petroleum and natural gas sales for the twelve months ended December 31, 2009.
 (2)
Reflects the change in production multiplied by the Company’s average sales prices for the twelve months ended December 31, 2009.






Canadian Superior Energy Inc.
2009 MD&A
Page 16










Quarterly financial summary


($ thousands except per share and production amounts)


2009
2008Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1ProductionNatural gas (mcf/d)
14,428
11,794
15,094
17,016
15,726
17,268
18,626
15,123Oil and natural gas liquids (bbl/d)
653
582
601
531
599
689
766
590Total (boe/d)
3,058
2,548
3,117
3,367
3,220
3,567
3,871
3,110Petroleum and natural gas sales
9,935
5,913
8,132
9,792
13,213
20,494
24,824
15,932Net income (loss)
(63,903)
29,456
(9,888)
(8,986)
(18,189)
(2,117)
(1,589)
(1,863)Net Income (loss) per share - basic
(0.32)
0.17
(0.06)
(0.05)
(0.11)
(0.01)
(0.01)
(0.01)Cash flow from operations
3,666
(13,651)
(7,796)
(1,411)
4,654
9,330
10,723
9,194Cash flow per share - basic
0.02
(0.08)
(0.05)
(0.01)
0.03
0.06
0.07
0.07





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 revenue and net 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.·
In Q2 2008 the Company acquired Seeker Petroleum with approximately 1,000 boe per day of production at closing.·
From March 2009 to September 2009 the Company was under CCAA protection which negatively affected petroleum and natural gas sales, general and administrative expenses and operating costs.·
In Q3 2009 the Company acquired Challenger Energy and recorded a bargain purchase gain of $8.5 million and disposed of an undivided 45% interest in Block 5 (c) to BG for a gain of $35.6 million.·
In Q4 the Company recorded a write-down of $57.5 million related to its Canadian petroleum and natural gas properties.





Please refer to the Results of Operations and other sections of this MD&A for the detailed discussions on changes for the fourth quarter and year ending December 31, 2009, and to the Company’s previously issued interim and annual MD&A for changes in prior quarters.





The following table summarizes the Company’s key financial results over the past three years:
 
 For the years ending December 31

$ thousands except per share amounts)
2009
2008
2007Petroleum and natural gas sales
34,582
75,730
48,492Net loss
(53,321)
(23,758)
(9,936)Loss per share – basic and diluted
(0.30)
(0.16)
(0.07)Total assets
291,832
420,216
254,669Total liabilities
81,637
178,494
73,763Dividend on preferred shares
718
941
850
 
 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 and 2009 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 Operating Officer (“COO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding public disclosure.





Canadian Superior Energy Inc.
2009 MD&A
Page 17











Management, including the COO and CFO, has evaluated the effectiveness of the Company’s disclosure control and procedures as of December 31, 2009. 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, 2009 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 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, 2009 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, 2009 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.
 
 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,Canadian Superior’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.


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2009 MD&A
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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 as at December 31, 2009. Based on its estimates, the Company recorded an adjustment of $57.5 million (December 31, 2008 - nil) to the carrying value of the Company’s Canadian petroleum and natural gas properties. The adjustment was recorded as an impairment loss on the Company’s statement of operations.





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 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.
 
 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.







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2009 MD&A
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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 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, Canadian Superior 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.




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2009 MD&A
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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, Canadian Superior is not fully insured against all of these risks, nor are all such risks insurable.  Canadian Superior 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.





Canadian Superior’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 Canadian Superior 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





Canadian Superior is exposed to fluctuations in prices for natural gas, crude oil and natural gas liquids, as all 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.
 
 Canadian Superior’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


Canadian Superior 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 facility utilization for Western Canada and equity financing to fund its international capital requirements. 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.






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2009 MD&A
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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.  Canadian Superior’s operations may require licenses and permits from various governmental authorities.  There can be no assurance that Canadian Superior 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 Canadian Superior, which could result in a reduction of the revenue received by the Company.





Conflicts of Interest





Certain of the directors and officers of Canadian Superior 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





Canadian Superior 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.





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:





·
volumes and estimated value of Canadian Superior's oil and gas reserves;·
the life of each of Canadian Superior's reserves;·
volume and product mix of Canadian Superior's oil and gas production;·
future oil and gas prices and interest rates in respect of Canadian Superior's commodity risk management programs;·
the amount and timing of future asset retirement obligations;·
future liquidity, creditworthiness and financial capacity;·
future interest rates;·
future results from operations and operating metrics;·
future development, exploration and other expenditures;·
future costs, expenses and royalty rates; and


·
Canadian Superior'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:






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2009 MD&A
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·
field production rates and decline rates, for operated and non-operated properties;·
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;·
Canadian Superior's ability to operate the properties in a safe, efficient and effective manner;·
the ability of the Company to obtain financing on acceptable terms;·
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;·
the ability of the Company to successfully market its oil and natural gas products; and·
performance of contractual obligations by government entities and joint venture partners.





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





By its nature, forward-looking information is subject to a number of risks and uncertainties, which could cause actual results or other expectations to differ materially from those anticipated, including those material risks set forth under “Risk Assessment” in the MD&A and “Risk Factors” in the Company’s 2010 Annual Information Form. Canadian Superior 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 ability of Canadian Superior to continue as a going concern;·
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;·
sufficient liquidity for future operations;·
cost of capital risk to carry out Canadian Superior's operations;·
unforeseen title defects;·
aboriginal land claims;·
increased competition and the lack of availability of qualified personnel or management;·
loss of key personnel;·
uncertainty of government policy changes;·
the risk of carrying out operations with minimal environmental impact;·
operational hazards and availability of insurance;·
industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced;·
general economic, market and business conditions;·
competitive action by other companies;·
the ability of suppliers to meet commitments;·
stock market volatility;


·
obtaining required approvals of regulatory authorities;·
creditworthiness of counterparties; and·
failure to realize anticipated benefits of the arrangement with Challenger.
 
 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.






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2009 MD&A
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Additional Information





Additional information relating to Canadian Superior is filed on SEDAR and can be viewed at www.sedar.com.  Information can also be obtained by contacting the Company at Canadian Superior Energy Corp., Suite 3200, 500 – 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6 and on the Company’s website at www.cansup.com.











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2009 MD&A
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