Edgar Filing: SONDE RESOURCES CORP.

form6k.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

For the month of	November	2010
Commission File Number	001-31395
Sonde Resources Corp.
(Translation of registrant’s name into English)
Suite 3200, 500 - 4th Avenue SW, Calgary, Alberta, Canada T2P 2V6
(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40F:

Form 20-F

Form 40-F

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Indicate by check mark whether by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): 82-_______________

DOCUMENTS INCLUDED AS PART OF THIS REPORT

Document	Description


1.	Interim Financial Statements for the three and nine months ended September 30, 2010.
2.	Management's Discussion and Analysis for the three and nine months ended September 30, 2010.
3.	Canadian Form 52-109F2 Certification of Interim Filings – CEO.
4.	Canadian Form 52-109F2 Certification of Interim Filings – CFO.

This Report on Form 6-K is incorporated by reference into the Registration Statement on Form F-3 of the Registrant, which was originally filed with the Securities and Exchange Commission on April 21, 2010 (File No. 333-166209).

Document 1

SONDE RESOURCES CORP.

CONSOLIDATED BALANCE SHEETS

(unaudited)

	September 30 2010	December 31 2009
(CDN$ thousands)
Assets (note 4)
Current
Cash and cash equivalents	1,435	3,305
Restricted cash (note 10)	21,210	22,274
Accounts receivable	8,273	14,164
Fair value of financial instrument (note 9)	1,024	--
Prepaid expenses and deposits (note 10)	9,281	3,270
	41,223	43,013
Long term portion of prepaid expenses and deposits	608	878
Property, plant and equipment, net (note 3)	247,216	247,941
	289,047	291,832

Liabilities
Current
Accounts payable and accrued liabilities	12,205	28,236
Stock unit awards (note 6)	244	55
Revolving credit facility (note 4)	3,097	24,067
	15,546	52,358
Convertible preferred shares (note 5)	15,276	15,301
Asset retirement obligations	15,193	13,978
	46,015	81,637
Contingencies and commitments (note 10)

Shareholders' Equity
Share capital (note 6)	339,183	280,561
Equity portion of preferred shares (note 5)	12,682	1,969
Warrants (notes 5, 6)	303	76
Contributed surplus (note 6)	27,951	26,923
Deficit	(137,087)	(99,334)
	243,032	210,195
	289,047	291,832

See accompanying notes to the unaudited consolidated financial statements

On behalf of the Board,


(Signed) “Marvin Chronister”	(Signed) “Kerry Brittain”

Marvin Chronister	Kerry Brittain
Director	Director

Q3 2010 FS

Page 1

SONDE RESOURCES CORP.

CONSOLIDATED STATEMENT OF OPERATIONS, COMPREHENSIVE INCOME (LOSS) AND DEFICIT

(unaudited)

	Three months ended		Nine months ended
	September 30		September 30
	2010	2009	2010	2009
(CDN$ thousands, except per share amounts)
Revenue
Petroleum and natural gas sales	8,248	6,058	27,142	24,340
Transportation	(379)	(145)	(989)	(503)
Royalties	(1,021)	(70)	(4,155)	(2,113)
	6,848	5,843	21,998	21,724
Gain on financial instrument (note 9)	247	--	3,156	--
	7,095	5,843	25,154	21,724
Interest and other income	131	317	275	1,056
Gain on corporate acquisition	--	8,523	--	8,523
Gain on asset disposition	--	35,636	--	35,636
	7,226	50,319	25,429	66,939

Expenses
Operating	3,091	2,446	8,658	10,314
General and administrative	3,114	3,398	9,269	10,822
Depletion, depreciation and accretion	6,681	7,294	21,051	25,513
Ceiling test impairment (note 3)	--	--	9,712	--
Stock based compensation (note 6)	399	668	1,173	2,042
Interest on preferred shares	226	352	717	1,070
Interest on credit facilities	29	227	187	2,304
Foreign exchange loss (gain)	606	(1,240)	(71)	(3,064)
Loss on abandonment	--	116	7	406
Bad debt expense	(48)	25	867	112
Loss on exchange of preferred shares (note 5)	--	--	172	--
Restructuring costs	--	10,504	--	18,855
Loss on investment	--	68	--	258
Interest on creditor claims and receiver advances	--	2,776	--	2,776
	14,098	26,634	51,742	71,408
Income (loss) before income taxes	(6,872)	23,685	(26,313)	(4,469)
Part VI.1 tax on preferred share dividends	(38)	--	(424)	--
Future income tax recovery	--	5,771	--	15,051
Net income (loss) and comprehensive income (loss)	(6,910)	29,456	(26,737)	10,582
Deficit, beginning of period	(130,177)	(64,887)	(99,334)	(46,013)
Incremental equity on exchange of preferred shares (note 5)	--	--	(11,016)	--
Deficit, end of period	(137,087)	(35,431)	(137,087)	(35,431)
Basic and diluted earnings (loss) per share (note 6)	($0.11)	$0.85	($0.44)	$0.31

See accompanying notes to the unaudited consolidated financial statements

Q3 2010 FS

Page 2

SONDE RESOURCES CORP.

CONSOLIDATED STATEMENT OF CASH FLOWS

(unaudited)

	Three months ended		Nine months ended
	September 30		September 30
	2010	2009	2010	2009
(CDN$ thousands)
Cash provided by (used in):
Operating
Net income (loss)	(6,910)	29,456	(26,737)	10,582
Items not involving cash:
Depletion, depreciation and accretion	6,681	7,294	21,051	25,513
Stock based compensation	399	668	1,173	2,042
Ceiling test impairment	--	--	9,712	--
Accretion expense on preferred shares	33	118	131	382
Unrealized loss (gain) on financial instrument	752	--	(1,024)	--
Unrealized foreign exchange loss (gain)	244	(806)	150	(1,101)
Loss on abandonment	--	116	7	406
Loss on exchange of preferred shares	--	--	172	--
Future income tax recovery	--	(5,771)	--	(15,051)
Loss on investment	--	68	--	258
Shares received for interest on bridge facility	--	--	--	(258)
Gain on corporate acquisition	--	(8,523)	--	(8,523)
Gain on asset disposition	--	(35,636)	--	(35,636)
Asset retirement expenditures	--	(117)	(35)	(462)
	1,199	(13,133)	4,600	(21,848)
Changes in non-cash working capital (note 8)	(992)	(23,065)	(5,533)	(7,462)
	207	(36,198)	(933)	(29,310)

Financing
Issue of common shares, net of share issue costs	13	(13)	58,610	(90)
Revolving credit facility advances	3,017	16,471	3,017	16,471
Revolving credit facility repayments	--	(34,600)	(23,987)	(43,263)
Exercise of stock unit awards	(20)	--	(20)	--
Changes in non-cash working capital (note 8)	190	84	190	(624)
	3,200	(18,058)	37,810	(27,506)

Investing
Exploration and development expenditures	(11,469)	(55,872)	(28,795)	(85,264)
Cash acquired on corporate acquisition	--	215	--	215
Proceeds from dispositions	--	146,644	--	155,706
Increase (decrease) in restricted cash	708	(22,902)	614	(22,902)
Change in non-cash working capital (note 8)	201	(21,062)	(10,538)	5,249
	(10,560)	47,023	(38,719)	53,004
Decrease in cash and cash equivalents	(7,153)	(7,233)	(1,842)	(3,812)
Cash and cash equivalents, beginning of period	8,626	8,923	3,305	5,994
Effect of foreign exchange on cash and cash equivalents (note 8)	(38)	(518)	(28)	(1,010)
Cash and cash equivalents, end of period	1,435	1,172	1,435	1,172

See accompanying notes to the unaudited consolidated financial statements

Q3 2010 FS

Page 3

SONDE RESOURCES CORP.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2010

(unaudited)

(All tabular amounts in CDN$ thousands, except where otherwise noted)

1.	Nature of operations and basis of presentation

a) Nature of operations

Sonde Resources Corp. (formerly Canadian Superior Energy Inc.) (“Sonde” or the “Company”) 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 project in U.S. federal waters offshore New Jersey (the “LNG Project”).

b) Basis of presentation

The Company’s consolidated financial statements have been prepared using Canadian generally accepted accounting principles (“Canadian GAAP”) which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods.

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

2.	Summary of accounting policies

These unaudited interim consolidated financial statements are stated in Canadian dollars and have been prepared in accordance with Canadian GAAP, following the same accounting policies and methods of computation as the audited consolidated financial statements of the Company for the year ended December 31, 2009. In these financial statements, certain disclosures that are required to be included in the notes to the December 31, 2009 audited consolidated financial statements, have been condensed or omitted. These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto as at and for the year ended December 31, 2009.

The Accounting Standards Board of Canada (AcSB) has finalized plans that will require the convergence of Canadian GAAP with International Financial Reporting Standards (“IFRS”) for publicly accountable enterprises, including the Company. The changeover date from Canadian GAAP to IFRS is for annual and interim financial statements relating to fiscal years beginning on or after January 1, 2011.

3.	Property, plant and equipment, net

	September 30, 2010			December 31, 2009
	Cost	Accumulated DD&A	Net book value	Cost	Accumulated DD&A	Net book value
Oil and Gas
Canada	411,604	(275,540)	136,064	399,954	(245,884)	154,070
Trinidad	71,521	--	71,521	69,998	--	69,998
United States	28,930	--	28,930	19,739	--	19,739
Libya/Tunisia	10,319	--	10,319	3,558	--	3,558
	522,374	(275,540)	246,834	493,249	(245,884)	247,365
Corporate assets	1,656	(1,274)	382	1,570	(994)	576
Total PP&E	524,030	(276,814)	247,216	494,819	(246,878)	247,941

Q3 2010 FS

Page 4

3.	Property, plant and equipment, net (continued)

The calculation of depletion and depreciation included an estimated $3.0 million (September 30, 2009 - $12.5 million) for future development capital associated with proven undeveloped reserves and excluded $121.2 million (September 30, 2009 - $121.4 million) related to unproved properties and projects under construction or development. Of the costs excluded $10.5 million (September 30, 2009 - $22.7 million) relates to Western Canada, nil (September 30, 2009 - $5.5 million) to East Coast Canada, $71.5 million (September 30, 2009 - $71.6 million) to Trinidad and Tobago, $28.9 million (September 30, 2009 - $18.1 million) to the LNG Project and $10.3 million (September 30, 2009 – $3.5 million) for offshore Libya/Tunisia.

During the nine months ended September 30, 2010, the Company capitalized $11.8 million of general and administrative expenses (September 30, 2009 - $8.5 million) related to exploration and development activities.

At June 30, 2010, the Company applied a ceiling test to its petroleum and natural gas properties. The application of this test required an adjustment of $9.7 million to the carrying value of the Company’s Canadian petroleum and natural gas properties (December 31, 2009 - $57.5 million).

4.	Revolving credit facility

As at September 30, 2010, the Company had drawn $3.1 million (December 31, 2009 - $24.1 million) against the $40.0 million (December 31, 2009 - $40.0 million) demand revolving credit facility (the “Credit Facility”) at a variable interest rate of prime plus 0.75% (December 31, 2009 – prime plus 0.75%). The Credit Facility is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company. The Credit Facility has covenants, as defined in the Company’s credit agreement, that require the Company to maintain its working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative expenditures in excess of $7.0 million per year and all foreign capital expenditures are not funded from the Credit Facility nor domestic cash flow while the Credit Facility is outstanding. The Company and its creditor completed their semi-annual review of the Credit Facility in June 2010 and it is subject to the next review on or before January 1, 2011.

5.	Convertible preferred shares

On February 3, 2010, the Company restructured the terms of the Series A, 5.0% US Cumulative Redeemable Convertible Preferred Shares (the “Series A Shares”). Pursuant to the terms of the restructuring, the Series A Shares were exchanged on a share for share basis for 150,000 First Preferred Shares, Series B shares (the “Series B Shares”) pursuant to which the redemption date was extended from December 31, 2010 to December 31, 2011, the conversion price was reduced from US$12.50 to US$3.00 and the conversion of 150,000 preferred shares into common shares was increased from 1,200,000 to 5,000,000. The terms of the dividend payment under the Series B Shares remain unchanged from the Series A Shares whereby the Company can elect to pay the quarterly dividend by way of issuance of common shares at market, based on a 5.75% annualized dividend rate in lieu of the 5.0% annualized cash dividend rate. In addition, the Company granted 500,000 common share purchase warrants exercisable at a price of US$3.25 for each common share and expiring December 31, 2011. The Company can force conversion of the Series B Shares at anytime in the future if its common shares close at a price of at least a 100% premium to the conversion price of US$3.00 on a major US exchange for 20 out of any 30 consecutive trading days while the common shares underlying the Series B Shares are registered.

The Company recorded the exchange of the Series A Shares for the Series B Shares as a deemed settlement of the Series A Shares. The liability component of the Series B Shares was recorded at their new fair value based on the revised terms. The increase in the liability of $0.2 million on February 3, 2010, was charged to earnings during the nine months ended September 30, 2010. The incremental equity attributable to the change in the conversion feature and the issuance of common share purchase warrants has been recorded as a capital transaction resulting in an increase in the carrying value of the equity component of $10.7 million and an increase to warrants of $0.3 million with an offset of $11.0 million to the Company’s deficit.

During the nine months ended September 30, 2010, the Company elected to pay cash as opposed to common shares to satisfy its quarterly preferred shares dividend requirements.

Q3 2010 FS

Page 5

5.	Convertible preferred shares (continued)

The following table summarizes the carrying value of the liability and equity component of the convertible preferred shares:

	Liability component		Equity component
Balance, December 31, 2008		17,194	2,320
Foreign exchange		(2,395)	--
Accreted non-cash interest		502	--
Expired warrants		--	(351)
Balance, December 31, 2009		15,301	1,969
Foreign exchange		(328)	--
Accreted non-cash interest		131	--
Loss on exchange of shares		172	--
Incremental equity on exchange of shares		--	10,713
Balance, September 30, 2010		15,276	12,682

6.	Share capital

(a) Authorized

Unlimited number of common shares, no par value.

Unlimited number of preferred shares, no par value.

(b) Common shares and warrants issued

	September 30, 2010		December 31, 2009
	Number (thousands)	Amount	Number (thousands)	Amount
Share capital, beginning of period	39,411	280,561	33,729	261,845
Issued upon private placement	22,885	59,501	--	--
Issued upon acquisition of Challenger	--	--	5,546	22,183
Issued upon the exercise of warrants	5	25	30	146
Issued for preferred share dividend	--	--	106	453
Issue costs, net of future tax reduction	--	(904)	--	(66)
Tax benefits renounced on flow-through shares	--	--	--	(4,000)
Share capital, end of period	62,301	339,183	39,411	280,561

Warrants, beginning of period	825	76	875	3,946
Issued in exchange of preferred shares	500	303	--	--
Assumed upon acquisition of Challenger	--	--	1,985	147
Exercised in exchange for common shares	(10)	(12)	(60)	(71)
Expired	(815)	(64)	(1,975)	(3,946)
Warrants, end of period	500	303	825	76

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

On February 3, 2010, as part of the exchange of the preferred shares, the Company issued 500,000 common share purchase warrants expiring December 31, 2011 and exercisable at a price of US$3.25 for each common share.

Q3 2010 FS

Page 6

6.	Share capital (continued)

On September 15, 2009, the Company issued 5,545,669 common shares to acquire Challenger Energy Corp. (“Challenger”). As part of the transaction, the Company assumed 1,985,000 purchase warrants which are exercisable at a proportionally adjusted exercise price for that portion of a common share of the Company. The warrants have an exercise price ranging from $0.25 to $22.00 per purchase warrant. As at September 30, 2010, none of the assumed purchase warrants remain outstanding, 1,915,000 have expired and 70,000 were exercised.

The Company has a stock option plan for its directors, officers, employees and key consultants. The exercise price for stock options granted is no less than the quoted market price on the grant date with options vesting in increments over a three year period. An option’s maximum term is ten years.

	September 30, 2010		December 31, 2009
	Number of options (thousands)	Weighted average exercise price ($)	Number of options (thousands)	Weighted average exercise price ($)
Balance, beginning of period	1,978	9.10	3,291	11.90
Granted	182	3.15	916	3.30
Cancelled	(257)	11.91	(1,337)	11.35
Forfeited	(229)	8.87	(892)	11.05
Balance, end of period	1,674	8.03	1,978	9.10

The following table summarizes stock options outstanding under the plan at September 30, 2010:

	Options outstanding			Options exercisable
Exercise price ($)	Number of options (thousands)	Average remaining contractual life (years)	Weighted average exercise price($)	Number of options (thousands)	Weighted average exercise price($)
0.00-5.00	903	9.15	3.19	--	--
5.01-7.50	33	1.80	7.20	33	7.20
7.51-10.00	90	4.18	8.94	90	8.94
10.01-12.50	114	5.71	11.38	114	11.38
12.51-15.00	167	7.00	13.80	167	13.80
15.01-17.50	342	7.37	15.91	260	15.89
17.51-20.00	25	7.92	18.98	17	18.98
0.00-20.00	1,674	7.90	8.03	681	13.36

The following table summarizes stock options outstanding under the plan at December 31, 2009:

	Options outstanding			Options exercisable
Exercise price ($)	Number of options (thousands)	Average remaining contractual life (years)	Weighted average exercise price($)	Number of options (thousands)	Weighted average exercise price($)
0.00-5.00	887	9.86	3.20	--	--
5.01-7.50	38	2.65	7.21	38	7.21
7.51-10.00	97	4.81	8.90	97	8.90
10.01-12.50	270	6.54	11.40	270	11.40
12.51-15.00	186	7.74	13.73	181	13.76
15.01-17.50	375	8.12	15.92	187	15.88
17.51-20.00	125	8.16	19.00	55	19.00
0.00-20.00	1,978	8.39	9.10	828	12.94

Q3 2010 FS

Page 7

6.	Share capital (continued)

(d) Stock based compensation

The Company uses the fair value method to account for its stock based compensation plan. Under this method, compensation costs are charged over the vesting period for stock options granted to directors, officers, employees and consultants, with a corresponding increase to contributed surplus.

The following table reconciles the Company’s contributed surplus:

	September 30, 2010	December 31, 2009
Balance, beginning of period	26,923	19,624
Issuance of stock options	964	3,002
Expired warrants	64	4,297
Balance, end of period	27,951	26,923

The fair value of options granted during the period was estimated based on the date of grant using a Black-Scholes option pricing model with weighted average assumptions and resulting values for grants as follows:

	Nine months ended September 30 2010	Twelve months ended December 31 2009
Risk free interest rate (%)	2.9	2.7
Expected life (years)	5.0	5.0
Expected dividend yield (%)	--	--
Expected volatility (%)	85.4	78.1
Weighted average fair value of options granted ($)	1.88	2.05

(e) Employee stock savings plan

The Company has an employee stock savings plan (“ESSP”) in which employees are provided with the opportunity to receive a portion of their salary in common shares, which is then matched on a share for share basis by the Company. The Company purchased approximately 67,891 shares under the ESSP during the nine months ended September 30, 2010 (September 30, 2009 – 273,513).

(f) Stock unit awards

The Company has issued 308,800 stock unit awards to members of the Board of Directors. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company. The units vest at the earlier of the last business day of the calendar year in which the third anniversary of the grant date occurs or the date the Company incurs a change of control. The 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 units may be paid in cash or common shares. At September 30, 2010, the Company recorded a liability of $0.2 million to recognize the fair value of the vested stock units (December 31, 2009 - $0.1 million).

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

Q3 2010 FS

Page 8

6.	Share capital (continued)

(g) Basic and diluted per share

The Company used the treasury stock method to calculate net earnings (loss) per common share.

	Three months ended		Nine months ended
	September 30		September 30
	2010	2009	2010	2009
(thousands, except per share amounts)
Weighted average common shares
Basic	62,297	34,633	60,704	34,034
Diluted	62,297	34,638	60,704	34,035
Earnings (loss) per share
Basic and diluted	($0.11)	$0.85	($0.44)	$0.31

For the calculation of diluted loss per share the Company excluded the following securities that are anti-dilutive:

	Three months ended		Nine months ended
	September 30		September 30
	2010	2009	2010	2009
(thousands)
Stock options	1,674	1,565	1,674	1,570
Convertible preferred shares – Series A	--	1,200	--	1,200
Convertible preferred shares – Series B	5,000	--	5,000	--
Warrants	500	1,870	500	1,870

7.	Capital disclosures

The Company’s primary objectives in managing its capital structure are to:

	·	Maintain a flexible capital structure which optimizes the costs of capital at an acceptable level of risk;
	•	Maintain sufficient liquidity to support ongoing operations, capital expenditure programs, strategic initiatives, and the repayment of debt obligations when due; and
	•	Maximize shareholder returns

The Company manages its capital structure to support current and future business plans and periodically adjusts the structure in response to changes in economic conditions and the risk characteristics of the Company’s underlying assets and operations. The Company monitors metrics such as the Company’s debt-to-equity and debt-to-cash flow ratios, among others to measure the status of its capital structure. The Company has not established fixed quantitative thresholds for such metrics. Depending on market conditions, the Company’s capital structure may be adjusted by issuing or repurchasing shares, issuing or repurchasing debt, refinancing existing debt, modifying capital spending programs and disposing of assets.

The Company’s capital structure consists of the following:

	September 30, 2010	December 31, 2009
Working capital (surplus) deficit	(25,677)	9,345
Convertible preferred shares	15,276	15,301
Share capital	339,183	280,561
Equity portion of preferred shares	12,682	1,969
Warrants	303	76
Contributed surplus	27,951	26,923
Deficit	(137,087)	(99,334)
Total Capital	232,631	234,841

Q3 2010 FS

Page 9

8.	Supplemental cash flow information

a) Changes in non-cash working capital

	Three months ended		Nine months ended
	September 30		September 30
	2010	2009	2010	2009

Accounts receivable	6,648	89,207	5,891	69,621
Prepaid expenses and deposits	(3,567)	630	(6,011)	396
Long term portion of prepaid expenses and deposits	57	145	270	436
Accounts payable and accrued liabilities	(3,739)	(134,025)	(16,031)	(73,290)
Change in non-cash working capital	(601)	(44,043)	(15,881)	(2,837)

The change in non-cash working capital has been allocated to the following activities:

	Three months ended		Nine months ended
	September 30		September 30
	2010	2009	2010	2009

Operating	(992)	(23,065)	(5,533)	(7,462)
Financing	190	84	190	(624)
Investing	201	(21,062)	(10,538)	5,249
	(601)	(44,043)	(15,881)	(2,837)

b) Other cash flow information

	Three months ended		Nine months ended
	September 30		September 30
Interest paid:	2010	2009	2010	2009

Preferred shares	193	--	586	--
Credit facilities	29	227	187	2,304
Creditor claims and receiver advances	--	2,776	--	2,776

c) Changes to prior period cash flow from operating activities

Cash flow from operating activities for the three and nine months ending September 30, 2009 have been adjusted to separately disclose the impact of foreign exchange on cash and cash equivalents. The change is as follows:

	Three months ended		Nine months ended
	September 30		September 30
		2009		2009

Cash flow from operating activities, as previously reported		(36,716)		(30,320)
Change due to foreign exchange impact on cash and cash equivalents		518		1,010
Adjusted cash flow from operating activities		(36,198)		(29,310)

Q3 2010 FS

Page 10

9. Risk management

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

(a) Credit risk

The Company’s accounts receivable are with natural gas and liquids marketers, the Government of the Republic of Trinidad and Tobago and joint venture partners in the petroleum and natural gas business under substantially normal industry sale and payment terms and are subject to normal credit risks. As at September 30, 2010, the maximum credit risk exposure is the carrying amount of cash and cash equivalents of $1.4 million (December 31, 2009 – $3.3 million), restricted cash of $21.2 million (December 31, 2009 – $22.3 million), accounts receivables of $8.3 million (December 31, 2009 – $14.2 million) and fair value of financial instrument of $1.0 million (December 31, 2009 – nil). As at September 30, 2010, the Company’s accounts receivables consisted of $3.6 million (December 31, 2009 - $6.7 million) of Western Canada joint interest billings, $2.0 million (December 31, 2009 - $2.5 million) in value added tax receivable from the Government of the Republic of Trinidad and Tobago, $0.7 million (December 31, 2010 - $nil) of Trinidad and Tobago joint interest billings, and $2.0 million (December 31, 2009 - $5.0 million) of revenue accruals and other receivables. Purchasers of the Company’s oil, gas and natural gas liquids are subject to an internal credit review to minimize the risk of nonpayment. The Company mitigates risk from joint venture partners by obtaining partner approval of capital expenditures prior to starting a project.

The Company’s allowance for doubtful accounts is currently $1.2 million (December 31, 2009 - $0.4 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 September 30, 2010, the Company has US$0.4 million in cash and cash equivalents (December 31, 2009 – US$0.6 million), US$20.3 million in restricted cash (December 31, 2009 – US$20.9 million), US$2.0 million (December 31, 2009 – US$2.4 million) in value added tax receivable from the Government of the Republic of Trinidad and Tobago, US$0.7 million (December 31, 2009 – US$nil) of Trinidad and Tobago receivables, US$6.8 million (December 31, 2009 – US$nil) of prepaid drilling costs related to the Libya/Tunisia drilling program, US$0.4 million (December 31, 2009 – US$1.0 million) of Block 5(c) payables, US$0.8 million (December 31, 2009 – US$nil) of Libya/Tunisia payables, US$1.6 million (December 31, 2009 – US$0.5 million) of LNG Project payables, and US$14.8 million (December 31, 2009 – US$14.6 million) of convertible preferred shares. These balances are exposed to fluctuations in the U.S. dollar. In addition, the Company is exposed to fluctuations between U.S. dollars and the domestic currencies of Trinidad and Tobago and Libya/Tunisia. At this time, the Company has chosen not to enter into any risk management agreements to mitigate foreign exchange 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 September 30, 2010.

(d) Commodity price risk

The Company enters into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility. These financial instruments are entered into solely for risk mitigation purposes and are not used for trading or other speculative purposes. The Company has the following natural gas price risk contract:

	Term		Contract		Volume (GJs/d)		Fixed price ($/GJ)		September 30, 2010 Fair Value
	January 1, 2010 – December 31, 2010		Swap		5,500		$5.50		$1,024

(e) Liquidity risk

The Company’s 2010 exploration and development program will be financed through a combination of cash, cash flow from operating activities, Credit Facility utilization and possible future debt or equity financings, farm outs and joint ventures.

Q3 2010 FS

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10.	Contingencies and commitments

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

b) 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 The Petroleum Company of Trinidad and Tobago Limited (“Petrotrin”). The first well had to be drilled to a depth of at least 3,000 meters by January 2010 and the second to a depth of at least 1,800 meters by July 2010. The Company agreed to provide a performance security to Petrotrin of US$12.0 million to meet the minimum work program.

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

c) Libya/Tunisia

On August 27, 2008, the Company entered into the 7th of November Block Exploration and 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$15.0 million per exploration well and up to US$4.0 million for 3D seismic not completed. The Company has provided a corporate security to a maximum of US$49.0 million to secure its minimum work program obligations. Under the EPSA, the Company has 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$15.0 million to Joint Oil payable if a rig is not moved on location by November 26, 2010. This guarantee will be reduced upon the Company meeting specified milestones with respect to the appraisal well.

At the time it entered into the EPSA, the Company also signed a "Swap Agreement" awarding an overriding royalty interest and optional participating interest to Joint Oil, in the Company's "Mariner" Block, offshore Nova Scotia, Canada. If at 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.

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

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10.	Contingencies and commitments (continued)

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

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

Canadian Sahara failed to cure its default by October 16, 2010 and as a result, Canadian Sahara has been notified that the Company is exercising its option to require that Canadian Sahara completely withdraw from the JOA and the EPSA governing the Block, thereby forfeiting its 50% working interest to the Company. In response, Canadian Sahara has advised that it has filed for creditor protection under the Bankruptcy and Insolvency Act (“BIA”) and intends to make a proposal to its creditors (including the Company) as an insolvent person under the BIA. The effect of this filing is to put a 30 day hold, which may be extended by the court, on the Company’s foreclosure on Canadian Sahara’s interest. Canadian Sahara’s default and the BIA filing will cause the Company to fund 100% of the operations in the 7th of November Block in the near term. A prolonged delay in the ability of the Company to exercise its default rights may impact the ability of the Company to attract joint venture partners. Without additional sources of capital, funding 100% of the costs of the 7th of November Block could adversely affect the Company’s capital program elsewhere.

At September 30, 2010, Canadian Sahara owed the Company US$6.0 million in outstanding costs, plus interest, associated with its 50% working interest in the 7th of November Block. Subsequent to September 30, 2010, the Company has invoiced Canadian Sahara an additional US$0.3 million in joint interest billings.

In view of Canadian Sahara’s default, the Canadian Sahara receivable of US$6.3 million has been re-allocated to property, plant and equipment (US$2.9 million) and prepaid expenses and deposits (US$3.4 million).

d) Litigation and claims

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

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

Under the terms of the MOU, the parties have agreed that the Stipulation will provide, among other things, for the full and final disposition of the Litigation, with prejudice and without costs, by the establishment of a US$5.2 million settlement fund by the Defendents’ insurers for the benefit of a settlement class which shall consist of all those who purchased securities of the Company between January 14, 2008 and February 17, 2009. Pending the negotiation and execution of the Stipulation, the parties to the Litigation will ask the presiding courts to continue the stay of all proceedings in the Litigation, except as necessary to consummate the settlement.

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

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10.	Contingencies and commitments (continued)

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

Q3 2010 FS

Page 14

Document 2

SONDE RESOURCES CORP.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") has been prepared by management as of November 10, 2010 and reviewed and approved by the Board of Directors (the “Board”) of Sonde Resources Corp. (formerly Canadian Superior Energy Inc.) (“Sonde” or the “Company”). This MD&A is a review of the operational results of the Company with disclosure of oil and gas activities in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") 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 unaudited consolidated interim financial statements and accompanying notes for the three and nine months ended September 30, 2010 and the audited consolidated financial statements and MD&A for the year ended December 31, 2009.

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

Boe Presentation – Production information is commonly reported in units of barrel of oil equivalent ("boe"). For purposes of computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet to one barrel of oil. This conversion ratio of 6:1 is based on an energy equivalent wellhead value for the individual products. Such disclosure of boe’s may be misleading, particularly if used in isolation. Readers should be aware that historical results are not necessarily indicative of future performance.

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

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.

Q3 2010 MD&A

Page 1

Business Overview and Strategy

The Company 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 project in U.S. federal waters offshore New Jersey (the “LNG Project”).

The Company derives all of its production and cash flow from its operations in Western Canada. The Company’s Western Canadian oil and gas assets are primarily high working interest properties that are geographically concentrated in three areas with multi-zone opportunities, the most significant being Drumheller, Alberta, which accounts for approximately 55% of the Company’s production.

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

	·	Developing the Western Canadian asset base to increase daily average production and replace producing reserves, with a focus on increasing oil and gas liquids production through re-development of existing fields in the Company’s portfolio;
	·	Drilling an appraisal well on the “7th of November Block” in offshore Tunisia / Libya, with success leading to a significant increase in the Company’s reserves, near-term development options and additional exploration step-out drilling opportunities;
	·	Seeking opportunities to monetize portions of the Company’s International portfolio to fund growth in Western Canada; and
	·	Synergistic growth through consolidating working interests in existing pools, and expansion into new pools, in the core Drumheller, Kaybob and Eaglesham areas in Western Canada.

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

The success of the Company’s ongoing operations are dependent upon several factors, including but not limited to, the price of energy commodity products, the Company’s ability to manage price volatility, increasing production and related cash flows, controlling costs, capital spending allocations, financial capabilities of its international joint venture partners, the ability to attract equity investment, hiring and retaining qualified personnel, managing political and government risk, and the success of the LNG Project permitting process.

Operating netback and cash flow from (used for) operations

	($ thousands)			($ per boe)
Three months ended September 30	2010	2009	% change	2010	2009	% change
Revenue
Petroleum and natural gas sales	8,248	6,058	36	33.01	25.84	28
Realized gain on financial instruments	999	--	n/a	4.00	--	n/a
Transportation	(379)	(145)	161	(1.52)	(0.62)	145
Royalties	(1,021)	(70)	1,359	(4.09)	(0.30)	1,263
	7,847	5,843	34	31.40	24.92	26
Operating	(3,091)	(2,446)	26	(12.37)	(10.43)	19
Operating netback(1)	4,756	3,397	40	19.03	14.49	31
General and administrative	(3,114)	(3,398)	(8)	(12.46)	(14.50)	(14)
Foreign exchange (loss) gain	(362)	434	(183)	(1.45)	1.86	(178)
Interest and other income	131	317	(59)	0.52	1.35	(61)
Interest	(222)	(3,237)	(93)	(0.89)	(13.81)	(94)
Bad debt expense	48	(25)	292	0.19	(0.11)	273
Asset retirement expenditures	--	(117)	n/a	--	(0.50)	n/a
Part VI.1 tax on preferred share dividends	(38)	--	n/a	(0.15)	--	n/a
Restructuring costs	--	(10,504)	n/a	--	(44.81)	n/a
Cash flow from (used for) operations(1)	1,199	(13,133)	109	4.79	(56.03)	109
Changes in non-cash working capital	(992)	(23,065)	(96)	(3.97)	(98.40)	(96)
Cash from (used for) operating activities	207	(36,198)	101	0.82	(154.43)	101

(1) Non-GAAP measure

Q3 2010 MD&A

Page 2

	($ thousands)			($ per boe)
Nine months ended September 30	2010	2009	% change	2010	2009	% change
Revenue
Petroleum and natural gas sales	27,142	24,340	12	35.56	29.65	20
Realized gain on financial instruments	2,132	--	n/a	2.79	--	n/a
Transportation	(989)	(503)	97	(1.30)	(0.61)	113
Royalties	(4,155)	(2,113)	97	(5.44)	(2.57)	112
	24,130	21,724	11	31.61	26.47	19
Operating	(8,658)	(10,314)	(16)	(11.34)	(12.56)	(10)
Operating netback(1)	15,472	11,410	36	20.27	13.91	46
General and administrative	(9,269)	(10,822)	(14)	(12.14)	(13.18)	(8)
Foreign exchange gain	221	1,963	(89)	0.29	2.39	(88)
Interest and other income	275	798	(66)	0.36	0.97	(63)
Interest	(773)	(5,768)	(87)	(1.01)	(7.03)	(86)
Bad debt expense	(867)	(112)	674	(1.14)	(0.14)	714
Asset retirement expenditures	(35)	(462)	(92)	(0.05)	(0.56)	(91)
Part VI.1 tax on preferred share dividends	(424)	--	n/a	(0.56)	--	n/a
Restructuring costs	--	(18,855)	n/a	--	(22.96)	n/a
Cash flow from (used for) operations(1)	4,600	(21,848)	121	6.02	(26.60)	123
Changes in non-cash working capital	(5,533)	(7,462)	(26)	(7.25)	(9.09)	(20)
Cash used for operating activities	(933)	(29,310)	(97)	(1.23)	(35.69)	(97)

(1) Non-GAAP measure

For the three months ended September 30, 2010, cash flow from operations was $1.2 million compared to cash flow used for operations of ($13.1) million in 2009.

For the nine months ended September 30, 2010, cash flow from operations was $4.6 million compared to cash flow used for operations of ($21.8) million in 2009.

In 2010, the Company realized higher operating netbacks due to increased commodity prices, realized hedging gains and lower operating expenses which partially offset the impact of decreased natural gas production. In addition, the Company incurred lower interest, general and administrative (“G&A”) and restructuring costs, related to the Company’s Companies Creditors Arrangement Act (“CCAA”) and restructuring in 2009.

Production

	Three months ended September 30		Nine months ended September 30
	2010	2009	2010	2009

Natural gas (mcf/d)	12,417	11,794	13,048	14,616
Crude oil and natural gas liquids (bbls/d)	646	582	621	571
Total production (boe/d) (6:1)	2,716	2,548	2,796	3,007

For the three months ended September 30, 2010, production averaged 2,716 boe per day and for the nine months ended September 30, 2010, production averaged 2,796 boe per day. The decrease in 2010 year to date natural gas production is mainly due to natural declines which more than offset new gas wells tied-in during 2010. Other factors contributing to the decline in production during 2010 were turnarounds and shut-ins due to workovers and testing throughout the year. Increased natural gas production during the quarter compared to 2009 is due to lower 2009 production related to the Company’s inability to tie-in new wells due to restructuring efforts in 2009. Crude oil and natural gas liquid production increased due to new production brought on stream in 2010.

Q3 2010 MD&A

Page 3

Petroleum and natural gas sales, net of transportation

	Three months ended September 30		Nine months ended September 30
($ thousands, except where otherwise noted)	2010	2009	2010	2009

Petroleum and natural gas sales, net of transportation
Natural gas	3,945	2,794	14,524	15,339
Realized gains on financial instruments	999	--	2,132	--
	4,944	2,794	16,656	15,339
Crude oil and natural gas liquids	3,924	3,119	11,629	8,498
Total	8,868	5,913	28,285	23,837
Average sales price
Natural gas ($/mcf)	4.33	2.57	4.68	3.84
Crude oil and natural gas liquids ($/bbl)	66.03	58.24	68.59	54.47
Total ($/boe)	35.49	25.22	37.05	29.04

For the three months ended September 30, 2010, petroleum and natural gas sales, net of transportation was $8.9 million, consisting of $4.0 million in natural gas, $1.0 million in realized gains on a natural gas hedge and $3.9 million of crude oil and natural gas liquids sales. The Company realized an average sales price of $35.49 per boe during the three months ended September 30, 2010 compared to $25.22 per boe for the same period in 2009.

For the nine months ended September 30, 2010, petroleum and natural gas sales, net of transportation was $28.3 million, consisting of $14.5 million in natural gas, $2.1 million in realized gains on a natural gas hedge and $11.7 million of crude oil and natural gas liquids sales. The Company realized an average sales price of $37.05 per boe during the nine months ended September 30, 2010 compared to $29.04 per boe for the same period in 2009.

The increase in natural gas sales is mainly due to an increase in realized prices and realized hedging gains which offset the Company’s decrease in natural gas production in 2010 compared to 2009. Crude oil and natural gas liquids increased primarily due to increased oil prices and production compared to the same period in 2009.

Royalties

	Three months ended September 30		Nine months ended September 30
($ thousands, except where otherwise noted)	2010	2009	2010	2009

Royalties
Crown	412	98	2,974	1,493
Freehold and overriding	609	(28)	1,181	620
Total	1,021	70	4,155	2,113
Royalties per boe ($)	4.09	0.30	5.44	2.57
Average royalty rate (%)	11.5	1.2	14.7	8.9

The Company pays royalties to provincial governments, freehold landowners and overriding royalty owners. Royalties are calculated and paid based on petroleum and natural gas sales net of transportation.

Crown royalties on Alberta natural gas production are calculated based on the Alberta Reference Price, which may vary from the Company’s realized corporate price, 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.

Natural gas and liquids royalties for the three months ended September 30, 2010 were $1.0 million or 11.5% of total petroleum and natural gas sales compared to $0.1 million or 1.2% in 2009.

Natural gas and liquids royalties for the nine months ended September 30, 2010 were $4.2 million or 14.7% of total petroleum and natural gas sales compared to $2.1 million or 8.9% in 2009.

Q3 2010 MD&A

Page 4

In 2009, the Company incurred lower royalty rates compared to 2010 due to favourable prior period adjustments realized in 2009 on crown royalties and reduced royalty rates under the new Alberta royalty framework. In addition, the Company recorded $0.5 million of favourable payout related royalty adjustments ($0.2 million to Crown royalties and $0.3 million to gross overriding royalties) as part of the CCAA creditor claims process. During 2010 the Company incurred higher royalty rates on increased petroleum and natural gas sales and an unfavourable annual gas cost allowance adjustment of $0.9 million. Freehold and overriding royalties increased during the quarter due to freehold royalty payments on new wells brought on stream.

Operating expenses

For the three months ended September 30, 2010, operating expenses were $3.1 million or $12.37 per boe compared to $2.4 million or $10.43 per boe for the same period in 2009. The increase is due to the Company continuing to complete a significant amount of workovers in 2010. In addition, 2009 operating expenses were lower due to reduced spending during the Company’s CCAA restructuring process.

For the nine months ended September 30, 2010, operating expenses were $8.7 million or $11.34 per boe compared to $10.3 million or $12.56 per boe for the same period in 2009. The Company continues to attain the benefits from an ongoing cost rationalization policy implemented in the latter part of 2009. In 2010, the Company incurred decreased labour and processing fees which were partially offset by an increase in workovers as a result of turnarounds. In 2009, the Company incurred $0.9 million in one-time operating expenses related to the CCAA claims process.

General and administrative expenses

	Three months ended September 30		Nine months ended September 30
($ thousands, except where otherwise noted)	2010	2009	2010	2009

Gross general and administrative expense	6,811	4,846	21,027	19,326
Capitalized general and administrative expense	(3,697)	(1,448)	(11,758)	(8,504)
Net general and administrative expense	3,114	3,398	9,269	10,822
General and administrative expense ($/boe)	12.46	14.50	12.14	13.18

For the three months ended September 30, 2010, net G&A was $3.1 million or $12.46 per boe compared to $3.4 million or $14.50 per boe in 2009.

For the nine months ended September 30, 2010, net G&A was $9.3 million or $12.14 per boe compared to $10.8 million or $13.18 per boe in 2009.

During 2010, the Company continued to implement its rationalization program to reduce G&A costs to a more manageable level, which more than offset increased legal fees related to the Company’s class action lawsuit. In 2009, the Company incurred significant one time payments related to the departures of former executives and directors of the Company.

Increases to gross G&A and capitalized G&A is mainly due to increased activity related to the Tunisia/Libya exploration program.

Stock based compensation

During the nine months ended September 30, 2010, the Company incurred stock based compensation expenses of $1.2 million compared to $2.0 million in 2009. The decrease is due to a significantly lower number of options outstanding during the nine months ended September 30, 2010 compared to 2009.

The Company has issued 308,800 stock unit awards issued to members of the Board of Directors. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company. At September 30, 2010, the Company recorded a liability of $0.2 million to recognize the fair value of the vested stock units (December 31, 2009 - $0.1 million). On July 3, 2010, 5,666 stock unit awards were exercised and 23,334 expired due to the departure of a former director of the Company.

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Page 5

Depletion, depreciation and accretion

Depletion, depreciation and accretion expense ("DD&A") was $21.1 million or $27.58 per boe for the nine months ended September 30, 2010 compared to $25.5 million or $31.07 per boe in 2009. The calculation of depletion and depreciation included an estimated $3.0 million (September 30, 2009 - $12.5 million) for future development capital associated with proven undeveloped reserves and excluded $121.2 million (September 30, 2009 - $121.4 million) related to unproved properties and projects under construction or development. Of the costs excluded $10.5 million (September 30, 2009 - $22.7 million) relates to Western Canada, nil (September 30, 2009 - $5.5 million) to East Coast Canada, $71.5 million (September 30, 2009 - $71.6 million) to Trinidad and Tobago, $28.9 million (September 30, 2009 – $18.1 million) to the LNG Project and $10.3 million (September 30, 2009 – $3.5 million) for offshore Libya/Tunisia. The Company's DD&A is lower in 2010 due to the impact on depletion of ceiling test impairments on the carrying value of the Company’s Canadian petroleum and natural gas assets recognized at December 31, 2009 and June 30, 2010.

On September 30, 2010, the Company applied a ceiling test to its petroleum and natural gas properties. The application of this test required no adjustment to the carrying value of the Company’s Canadian petroleum and natural gas properties.

Income taxes

The Company’s current and future income taxes are dependent on factors such as production, commodity prices and tax classification of drilling costs related to exploration and development wells. At September 30, 2010, the Company has estimated $254.2 million in tax pools and $78.9 million in non-capital losses that are available for future deduction against taxable income.

September 30
($ thousands)	2010
Canadian exploration expense	56,407
Canadian oil and gas property expense	43,193
Canadian development expense	34,192
Undepreciated capital costs	31,149
Share issue costs	7,009
Foreign exploration expense	81,527
Other	757
Total	254,234

Non-capital losses expire as follows:

($ thousands)
2010 - 2020	--
2021 - 2025	65
2026 - 2030	78,852
	78,917

Capital expenditures

	Three months ended September 30		Nine months ended September 30
($ thousands)	2010	2009	2010	2009
Acquisitions	--	--	660	--
Exploration and development	5,005	54,665	12,036	74,669
Plants, facilities and pipelines	1,224	(458)	2,289	985
Land and lease	1,543	217	2,052	1,106
Capitalized general and administrative expenses	3,697	1,448	11,758	8,504
Exploration and development expenditures	11,469	55,872	28,795	85,264
Exploration and development divestitures	--	(146,644)	--	(155,706)
Net capital expenditures	11,469	(90,772)	28,795	(70,442)

Q3 2010 MD&A

Page 6

The Company invested $28.8 million of capital expenditures during the nine months ended September 30, 2010, relating to various projects in progress. The Company invested $11.2 million in Western Canada on completions and tie-ins of wells drilled during the 2009 winter drilling program. In addition, $6.8 million was spent in Libya/Tunisia on third party rig demobilization costs, capitalized G&A costs, geotechnical site surveys and tangible equipment for the purposes of evaluating and drilling the Zarat 1 North well. During 2010, the Company incurred $9.2 million of capitalized G&A relating to the progression of the LNG Project which was submitted for permitting during the third quarter. In addition, the Company incurred $1.5 million of Trinidad Block 5(c) costs related to the planning of the next exploration phase.

Liquidity and capital resources

	September 30	December 31
($ thousands)	2010	2009
Working capital surplus excluding revolving credit facility	28,774	14,722
Revolving credit facility	(3,097)	(24,067)
Working capital surplus (deficit)	25,677	(9,345)

As at September 30, 2010, the Company had a working capital surplus of $25.7 million (December 31, 2009 – deficit of $9.3 million), the Company had drawn $3.1 million (December 31, 2009 – $24.1 million) against the $40.0 million (December 31, 2009 - $40.0 million) demand revolving credit facility (the “Credit Facility) at a variable interest rate of prime plus 0.75% (December 31, 2009 – prime plus 0.75%). The Credit Facility is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company. The Credit Facility has covenants, as defined in the Company’s credit agreement, that require the Company to maintain its working capital ratio at 1:1 or greater and to ensure that non-domestic G&A expenditures in excess of $7.0 million per year and all foreign capital expenditures are not funded from the Credit Facility or domestic cash flow while the Credit Facility is outstanding. The Company and its creditor completed their semi-annual review of the Credit Facility in June 2010 and is subject to the next review on or before January 1, 2011.

At September 30, 2010, the Company had $1.4 million in cash and cash equivalents (December 31, 2009 - $3.3 million) and $21.2 million classified as restricted cash (December 31, 2009 – $22.3 million).

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

On February 3, 2010, the Company restructured the terms of the Series A, 5.0% US Cumulative Redeemable Convertible Preferred Shares (the “Series A Shares”). Pursuant to the terms of the restructuring, the Series A Shares were exchanged on a share for share basis for 150,000 First Preferred Shares, Series B shares (the “Series B Shares”) pursuant to which the redemption date was extended from December 31, 2010 to December 31, 2011, the conversion price was reduced from US$12.50 to US$3.00 and the conversion of 150,000 preferred shares was increased from 1,200,000 to 5,000,000. The Company can force conversion of the Series B Shares at anytime in the future if its common shares close at a price of at least a 100% premium to the conversion price of US$3.00 on a major US exchange for 20 out of any 30 consecutive trading days while the common shares underlying the Series B Shares are registered. The extension provided the Company with additional flexibility as the Company continues to advance its domestic and international capital programs and work towards improving its liquidity and capital resources.

The Company generally relies on a combination of cash flow from operations, Credit Facility availability and equity financings to fund its capital requirements and to provide liquidity for domestic and international operations.

The Company’s cash flow from operating activities 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. The Company has entered into risk management contracts to mitigate commodity prices. 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. The Company’s 2010 exploration and development program will be financed through a combination of cash, cash flow from operations, Credit Facility utilization, possible future debt or equity financings, farm outs and joint ventures.

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Contingencies and commitments

Block 5(c) Trinidad and Tobago

MG Block Trinidad and Tobago

Libya/Tunisia

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

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Litigation and claims

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Page 9

Off-balance sheet arrangements

The Company has no off-balance sheet arrangements.

Share capital

As at November 10, 2010, the Company had 62.3 million common shares, 2.1 million stock options, 0.2 million Series B Preferred Shares and 0.5 million common share purchase warrants issued and outstanding.

Risk Management

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

Credit risk

The Company’s accounts receivable are with natural gas and liquids marketers, the Government of the Republic of Trinidad and Tobago and joint venture partners in the petroleum and natural gas business under substantially normal industry sale and payment terms and are subject to normal credit risks. As at September 30, 2010, the maximum credit risk exposure is the carrying amount of cash and cash equivalents of $1.4 million (December 31, 2009 – $3.3 million), restricted cash of $21.2 million (December 31, 2009 – $22.3 million), accounts receivables of $8.3 million (December 31, 2009 – $14.2 million) and fair value of financial instrument of $1.0 million (December 31, 2009 – nil). As at September 30, 2010, the Company’s accounts receivables consisted of $3.6 million (December 31, 2009 - $6.7 million) of Western Canada joint interest billings, $2.0 million (December 31, 2009 - $2.5 million) in value added tax receivable from the Government of the Republic of Trinidad and Tobago, $0.7 million (December 31, 2009 – nil) of Trinidad and Tobago joint interest billings and $2.0 million (December 31, 2009 - $5.0 million) of revenue accruals and other receivables. Purchasers of the Company’s oil, gas and natural gas liquids are subject to an internal credit review to minimize the risk of nonpayment. The Company mitigates risk from joint venture partners by obtaining partner approval of capital expenditures prior to starting a project.

The Company’s allowance for doubtful accounts is currently $1.2 million (December 31, 2009 - $0.4 million).

Foreign exchange risk

The Company is exposed to foreign currency fluctuations as oil and gas prices received are referenced to U.S. dollar denominated prices. At September 30, 2010, the Company has US$0.4 million in cash and cash equivalents (December 31, 2009 – US$0.6 million), US$20.3 million in restricted cash (December 31, 2009 – US$20.9 million), US$2.0 million (December 31, 2009 – US$2.4 million) in value added tax receivable from the Government of the Republic of Trinidad and Tobago, US$0.7 million (December 31, 2009 – nil) of Trinidad and Tobago receivables US$6.8 million (December 31, 2009 – nil) of prepaid drilling costs related to the Libya/Tunisia drilling program, US$0.4 million (December 31, 2009 – US$1.0 million) of Block 5(c) payables, US$0.8 million (December 31, 2009 – US$nil) of Libya/Tunisia payables, US$1.6 million (December 31, 2009 – US$0.5 million) of LNG Project payables, and US$14.8 million (December 31, 2009 – US$14.6 million) of convertible preferred shares. These balances are exposed to fluctuations in the U.S. dollar. In addition, the Company is exposed to fluctuations between U.S. dollars and the domestic currencies of Trinidad and Tobago and Libya/Tunisia. At this time, the Company has chosen not to enter into any risk management agreements to mitigate foreign exchange risk.

Interest rate risk

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Commodity price risk

Term	Contract		Volume (GJ/d)		Fixed price ($/GJ)		September 30, 2010 Fair Value
January 1, 2010 – December 31, 2010	Swap		5,500		$5.50		$1,024

Critical accounting estimates

There were no material changes to the Company’s critical accounting estimates during the quarter ended September 30, 2010. For a full discussion of critical accounting estimates, please refer to the Company’s discussion in its MD&A for the year ended December 31, 2009.

IFRS Implementation

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

The Company commenced its transition project during the second quarter of 2010 which is comprised of three key phases: initial assessment, design and development and implementation. The Company has completed the initial assessment phase, which includes a high level analysis of the differences between current Canadian GAAP and IFRS and the potential effects of the IFRS conversion on the Company’s existing accounting policies, financial reporting, external disclosures, information system, internal controls and business processes. The Company has commenced the second phase, including a detailed analysis of differences in accounting policies, required adjustments to the balance sheet on transition to IFRS, changes in disclosures included in the Company’s financial statements and determining required changes of information systems. The Company has not yet finalized this analysis and is currently unable to determine the impact of the conversion to IFRS on its financial statements at this time.

While the second phase has not yet been completed, the following items have been identified as potentially having the most significant impact on the Company’s financial reporting:

	·	Property, Plant and Equipment – the full-cost method of accounting applied under current Canadian GAAP will no longer be allowed to be used under IFRS. Instead accounting for oil and and gas operations will have to be compliant with requirements in IFRS 6 Exploration for and Evaluation of Mineral Resources when it relates to exploration activities and IAS 16 Plant, Property and Equipment for development and production assets;
	·	Asset retirement obligations – requirements for discounting future asset retirement obligations differ between current Canadian GAAP and IFRS, potentially resulting in increased liabilities under IFRS;
	·	Impairment testing – testing for impairment is potentially performed at a more detailed component level under IFRS;
	·	Financial instruments – accounting for financial instruments differ between current Canadian GAAP and IFRS, potentially leading to different accounting under IFRS;
	·	Functional currency – the functional currencies of the Company’s activities outside Canada may change from Canadian dollar to US dollar based on the IFRS requirements; and
	·	Income tax – impacts are expected from transition adjustments recorded.

This should not be regarded as a complete list, and is subject to change based on new facts and circumstances, but is intended to highlight the areas expected to have an effect. At this stage, the Company has not completed quantification of the impact expected on the consolidated financial statements for these differences. Most

Q3 2010 MD&A

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adjustments required on transition to IFRS will be made retrospectively against opening retained earnings in the first comparative balance sheet.

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

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

In accordance with the transition plan, the Company is continuing the process of evaluating its accounting policy choices, quantifying their expected effects and making recommendations of chosen accounting policies to senior management for approval and presenting to the audit committee of the Board of Directors for their review. Development of draft financial statement formats and quantification of changes are included in this second phase and will continue through the fourth quarter of 2010.

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

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

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

Sensitivities

The following sensitivity analysis is provided to demonstrate the impact of changes in commodity prices in 2010 petroleum and natural gas sales and is based on the balances disclosed in this MD&A and the unaudited consolidated interim financial statements for the nine months ended September 30, 2010:

($ thousands)	Petroleum and Natural Gas Sales (1)
Change in average sales price for natural gas by $1.00/mcf	3,562
Change in the average sales price for crude oil and natural gas liquids by $1.00/bbl	170
Change in natural gas production by 1 mmcf/d (2)	1,114
Change in crude oil and natural gas liquids production by 100 bbls/d (2)	1,873

(1)	Reflects the change in petroleum and natural gas sales for the nine months ended September 30, 2010.

(2)	Reflects the change in production multiplied by the Company’s average sales prices for the nine months ended September 30, 2010.

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Quarterly financial summary

($ thousands except per share and production amounts)

		2010				2009		2008
	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Production
Natural gas (mcf/d)	12,417	13,631	13,104	14,428	11,794	15,094	17,016	15,726
Crude oil and natural gas liquids (bbl/d)	646	620	595	653	582	601	531	599
Total (boe/d)	2,716	2,892	2,779	3,058	2,548	3,117	3,367	3,220

Petroleum & natural gas sales (1)	8,868	9,310	10,107	9,935	5,913	8,132	9,792	13,213
Net income (loss)	(6,910)	(17,663)	(2,164)	(63,903)	29,456	(9,888)	(8,986)	(18,189)
Net income (loss) per share – basic	(0.11)	(0.28)	(0.04)	(1.62)	0.85	(0.29)	(0.27)	(0.56)
Cash flow from (used for) operations (2) (3)	1,199	481	2,918	3,671	(13,133)	(7,092)	(1,623)	2,422
Cash flow per share – basic (2)	0.02	0.01	0.05	0.09	(0.38)	(0.21)	(0.05)	0.08

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

(2) Non-GAAP measures

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

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

	·	Revenue is directly impacted by the Company’s ability to replace existing declining production and add incremental production through its on-going capital expenditure program.
	·	Fluctuations in the Company’s petroleum and natural gas sales and net income (loss) from quarter to quarter are primarily caused by variations in production volumes, realized oil and natural gas prices and the related impact of royalties.
	·	From March 2009 to September 2009 the Company was under CCAA protection which negatively affected the Company’s net income (loss).
	·	In Q3 2009, the Company acquired Challenger and recorded a bargain purchase gain of $8.5 million and disposed of an undivided 45% interest in Block 5 (c) to BG for a gain of $35.6 million.
	·	In Q4 2009, the Company recorded a write-down of $57.5 million related to its Canadian petroleum and natural gas properties.
	·	In Q2 2010, the Company recorded a write-down of $9.7 million related to its Canadian petroleum and natural gas properties.

Please refer to the other sections of this MD&A for the detailed discussions on changes for the third quarter ending September 30, 2010, and to the Company’s previously issued interim and annual MD&A for changes in prior quarters.

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 as appropriate to allow timely decisions regarding public disclosure.

The Company is required to disclose any change in the Company's internal controls over financial reporting that occurred during the period beginning on January 1, 2010 and ending on September 30, 2010 that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial reporting. Management concluded during the interim period ended September 30, 2010, no material changes in the Company’s internal controls and procedures have occurred during the Company’s most recent interim period, which have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

Additional Information

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

Q3 2010 MD&A

Page 13

Document 3

Form 52-109F2

Certification of Interim Filings

Full Certificate

I, Marvin M. Chronister, the Chairman of the Board of Directors of Sonde Resources Corp., in the capacity of Chief Executive Officer, certify the following:

1.	Review: I have reviewed the interim financial statements and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended September 30, 2010.

2.	No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3.	Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4.	Responsibility: The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings

	(a)	designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

		(i)	material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

		(ii)	information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

	(b)	designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1	Control framework: The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is the Internal Control over Financial Reporting - Guidance for Smaller Public Companies published by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

5.2	N/A

5.3	N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July1, 2010 and ended on September 30, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 12, 2010

Marvin M. Chronister

Chairman of the Board, in the capacity as Chief Executive Officer

Sonde Resources Corp.

Document 4

Form 52-109F2

Certification of Interim Filings

Full Certificate

I Michael C. Barkwell, the Chief Financial Officer of Sonde Resources Corp., certify the following:

1.	Review: I have reviewed the interim financial statements and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended September 30, 2010.

2.	No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

3.	Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

4.	Responsibility: The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer and I have, as at the end of the period covered by the interim filings

	(a)	designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

		(i)	material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

		(ii)	information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

	(b)	designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1	Control framework: The control framework the issuer’s other certifying officer and I used to design the issuer’s ICFR is the Internal Control over Financial Reporting - Guidance for Smaller Public Companies published by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

5.2	N/A

5.3	N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2010 and ended on September 30, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: November 12, 2010

Michael C. Barkwell

Chief Financial Officer

Sonde Resources Corp.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		SONDE RESOURCES CORP.
		(Registrant)
Date:	November 12, 2010	By:	/s/ Michael C. Barkwell
			Name:	Michael C. Barkwell
			Title:	Chief Financial Officer