Edgar Filing: SONDE RESOURCES CORP.

sonde_6k.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	2011

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 months ended September 30, 2011.
2.	Management's Discussion and Analysis for the three months ended September 30, 2011.
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 Statements on Form F-3 and Form S-8 of the Registrant, which were originally filed with the Securities and Exchange Commission on April 21, 2010 (File No. 333-166209) and August 8, 2011 (File No. 333-176261), respectively.

Document 1

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(unaudited)

	September 30 2011			December 31 2010			January 1 2010 (Restated - note 18e)
(CDN$ thousands)
Assets
Current
Cash and cash equivalents (note 16)		30,672			2,649			3,305
Restricted cash (note 5a)		--			--			1,364
Accounts receivable		8,059			7,147			11,340
Derivative financial assets (note 8)		306			--			--
Prepaid expenses and deposits		1,430			1,686			3,185
Assets of discontinued operations (note 5)		--			100,692			23,819
		40,467			112,174			43,013
Long term portion of prepaid expenses and deposits		469			555			878
Exploration and evaluation assets (note 6)		64,519			49,361			12,526
Property, plant and equipment, net (note 6)		129,750			102,603			145,678
Assets of discontinued operations (note 5)		--			--			88,972
		235,205			264,693			291,067

Liabilities
Current
Accounts payable and accrued liabilities		12,333			18,126			26,443
Stock based compensation liability (note 15)		1,732			530			55
Provisions (note 10)		13,126			12,692			1,146
Derivative financial liabilities (note 8)		1,015			5,099			--
Short term debt (note 11)		15,781			35,048			39,368
Liabilities of discontinued operations (note 5)		--			16,650			1,793
		43,987			88,145			68,805
Decommissioning provision		25,820			18,197			15,905
Liabilities of discontinued operations (note 5)		--			--			2,763
		69,807			106,342			87,473
Contingencies and commitments (note 17)

Shareholders’ Equity
Share capital		369,892			369,892			311,270
Warrants		--			--			76
Contributed surplus		34,469			31,068			28,494
Foreign currency translation reserve		1,928			(5,789	)		--
Deficit		(240,891	)		(236,820	)		(136,246	)
		165,398			158,351			203,594
		235,205			264,693			291,067

See accompanying notes to the unaudited condensed consolidated financial statements

On behalf of the Board,

(Signed) “Jack Schanck”	(Signed) “W. Gordon Lancaster”
Jack Schanck	W. Gordon Lancaster
Director and Chief Executive Officer	Director

Sonde Resources Corp.

Q3 2011 FS

Page 1

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS & COMPREHENSIVE INCOME (LOSS)

(unaudited)

	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
(CDN$ thousands, except per share amounts)
Revenue
Revenue, net of royalties (note 12)		8,988			7,227			25,814			22,987
Gain on commodity derivatives (notes 8, 9)		898			247			355			3,156
		9,886			7,474			26,169			26,143
Expenses
Operating (note 13)		4,130			3,091			11,039			8,658
Transportation		271			379			787			989
Exploration		784			336			1,154			535
General and administrative		2,303			2,893			6,692			8,603
Depletion and depreciation		4,409			3,872			10,652			12,611
Stock based compensation (note 15)		804			516			4,603			1,569
Property, plant and equipment impairment		--			--			--			15,238
Bad debt		(121	)		(48	)		(123	)		867
Loss on abandonment		24			--			799			7
		12,604			11,039			35,603			49,077
Operating loss		(2,718	)		(3,565	)		(9,434	)		(22,934	)

Other
Financing costs (note 14)		(502	)		(413	)		(1,955	)		(1,420	)
Gain (loss) on foreign exchange		433			552			(115	)		364
Gain (loss) on financial derivatives		1,930			--			4,563			(1,779	)
Other income		27			131			86			411
Loss on exchange of preferred shares		--			--			--			(172	)
		1,888			270			2,579			(2,596	)
Loss from continuing operations before income taxes		(830	)		(3,295	)		(6,855	)		(25,530	)
Current income taxes		17			38			137			424
Loss from continuing operations		(847	)		(3,333	)		(6,992	)		(25,954	)
Income (loss) from discontinued operations, net tax (note 5)		256			(29	)		2,921			(93	)
Net income (loss)		(591	)		(3,362	)		(4,071	)		(26,047	)

Other comprehensive income (loss)
Foreign currency translation adjustment		3,598			327			2,480			283
Foreign currency translation adjustment relating to assets and liabilities of discontinued operations (note 5)		--			(4,555	)		(1,128	)		(2,409	)
Foreign currency translation reclassified to net earnings (note 5)		--			--			6,365			--
Other comprehensive income (loss)		3,598			(4,228	)		7,717			(2,126	)
Total comprehensive income (loss)		3,007			(7,590	)		3,646			(28,173	)

Net loss per common share
Basic and diluted loss per common share from continuing operations	$	(0.01	)	$	(0.05	)	$	(0.11	)	$	(0.43	)
Basic and diluted income per common share from discontinued operations		--			--		$	0.04			--
	$	(0.01	)	$	(0.05	)	$	(0.07	)	$	(0.43	)

See accompanying notes to the unaudited condensed consolidated financial statements

Sonde Resources Corp.

Q3 2011 FS

Page 2

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
(CDN$ thousands)
Cash provided by (used in):
Operating
Net loss		(591	)		(3,362	)		(4,071	)		(26,047	)
Items not involving cash:
Depletion and depreciation		4,409			3,872			10,652			12,611
Stock based compensation		804			516			4,603			1,569
Property, plant and equipment impairment		--			--			--			15,238
Unrealized (gain) loss on commodity derivatives		(604	)		752			125			(1,024	)
Unrealized (gain) loss on financial derivatives		(1,930	)		--			(4,563	)		1,779
Unrealized gain on foreign exchange		(2,128	)		(912	)		(229	)		(143	)
Financing costs		502			413			2,448			1,420
Loss on abandonment		24			--			799			7
Loss on exchange of preferred shares		--			--			--			172
Gain on disposition of discontinued operations		(318	)		--			(4,918	)		--
Interest paid		(266	)		(193	)		(1,850	)		(680	)
Decommissioning expenditures		(24	)		--			(870	)		(35	)
		(122	)		1,086			2,126			4,867
Changes in non-cash working capital (note 16)		(4,641	)		(1,214	)		(3,552	)		(6,199	)
		(4,763	)		(128	)		(1,426	)		(1,332	)
Financing
Revolving credit facility repayments		(6,901	)		--			(41,463	)		(20,970	)
Revolving credit facility advances		--			3,017			21,343			--
Issue of common shares, net of share issue costs		--			13			--			58,609
Exercise of stock unit awards		--			(20	)		--			(20	)
Change in non-cash working capital (note 16)		--			190			--			190
		(6,901	)		3,200			(20,120	)		37,809
Investing
Capital and exploration expenditures		(13,966	)		(11,134	)		(36,864	)		(28,396	)
Property acquisition (note 7)		(6,088	)		--			(6,088	)		--
Proceeds on disposition (note 5)		283			--			87,908			--
Decrease in restricted cash		19,892			708			19,892			614
Change in non-cash working capital (note 16)		(303	)		202			(16,027	)		(10,538	)
		(182	)		(10,224	)		48,821			(38,320	)
Increase (decrease) in cash and cash equivalents		(11,846	)		(7,152	)		27,275			(1,843	)
Cash and cash equivalents, beginning of period		40,837			8,626			2,649			3,305
Effect of foreign exchange on cash and cash equivalents		1,681			(39	)		748			(27	)
Cash and cash equivalents, end of period		30,672			1,435			30,672			1,435

See accompanying notes to the unaudited condensed consolidated financial statements

Sonde Resources Corp.

Q3 2011 FS

Page 3

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(unaudited)

(CDN$ thousands)	Share capital		Contributed surplus		Warrants			Foreign currency translation			Deficit			Total
At January 1, 2010		311,270		28,494		76			--			(136,246	)		203,594
Total comprehensive loss		--		--		--			(2,126	)		(26,047	)		(28,173	)
Issue of common shares, net of share issue costs		58,597		--		--			--			--			58,597
Issued under exercise of warrants		25		--		(12	)		--			--			13
Warrant expiry		--		64		(64	)		--			--			--
Stock based compensation expense		--		1,360		--			--			--			1,360
September 30, 2010		369,892		29,918		--			(2,126	)		(162,293	)		235,391


At December 31, 2010		369,892		31,068		--			(5,789	)		(236,820	)		158,351
Total comprehensive income		--		--		--			1,352			2,294			3,646
Foreign currency translation reclassified to net earnings		--		--		--			6,365			(6,365	)		--
Stock compensation expense (note 15)		--		3,401		--			--			--			3,401
September 30, 2011		369,892		34,469		--			1,928			(240,891	)		165,398

See accompanying notes to the unaudited condensed consolidated financial statements

Sonde Resources Corp.

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Page 4

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2011

(unaudited)

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

1.	Reporting entity

	Sonde Resources Corp. (“Sonde Resources” or the “Company”) is a Canadian based energy company with its registered office located at Suite 3200, 500 – 4th Avenue S.W., Calgary, Alberta. The Company is engaged in the exploration for and production of oil and natural gas. The Company’s operations are located in Western Canada and offshore North Africa. All of the Company’s revenues are generated from its operations in Western Canada. On June 22, 2011, the Company completed the sale of its offshore operations in the Republic of Trinidad and Tobago (“Trinidad and Tobago”). These condensed consolidated financial statements (the “Financial Statements”) comprise the Company and its wholly owned subsidiaries, which include Seeker Petroleum Ltd., Sonde Resources Trinidad and Tobago Ltd. and Challenger Energy Corp. The Company’s shares are publicly traded on both the Toronto Stock Exchange and the American Stock Exchange.

2.	Basis of preparation

	(a)	Statement of compliance

	In conjunction with the Company’s annual audited consolidated financial statements to be issued under International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board for the year ended December 31, 2011, the Financial Statements present the Company’s results of operations and financial position under IFRS as at and for the three and nine months ended September 30, 2011, including 2010 comparative periods. As a result, the Financial Statements have been prepared in accordance with IFRS 1, First-time Adoption of International Financial Reporting Standards (IFRS 1), and with International Accounting Standard 34, Interim Financial Reporting, using the accounting policies the Company expects to adopt in its consolidated financial statements for the year ending December 31, 2011. They are condensed as they do not include all of the necessary annual disclosures required for full annual financial statements under IFRS.

	In previous years, the Company prepared its consolidated financial statements in accordance with Canadian generally accepted accounting principles in effect prior to January 1, 2011 (Canadian GAAP). Comparative information has been restated from Canadian GAAP to IFRS. The impact of the transition to IFRS on the Company’s previously reported financial statements is presented in Note 18.

	These unaudited interim condensed consolidated financial statements have been prepared in accordance with those IFRS standards and International Financial Reporting Interpretations Committee (“IFRIC”) interpretations required to be applied for annual periods beginning on or after January 1, 2011, which were issued and effective as of the date of approval by the Company’s Board of Directors of these interim financial statements. The IFRS standards and IFRIC interpretations that will be applicable at December 31, 2011, including those that will be applicable on an optional basis, are not known with certainty at the time of the Financial Statements. Accordingly, the accounting policies for the annual period that are relevant to these unaudited interim condensed consolidated financial statements will be determined only when the first annual IFRS financial statements are prepared for the year ending December 31, 2011. The statements were approved and authorized for issue by the Board of Directors on November 9, 2011, and should be read in conjunction with the Audited Consolidated Financial Statements for the year ended December 31, 2010, which have been prepared in accordance with Canadian GAAP.

	(b)	Basis of measurement

	The Financial Statements have been prepared on the historical cost basis except as detailed in the Company’s accounting policies disclosed in the condensed consolidated financial statements for the quarter ended March 31, 2011. The accounting policies have been applied consistently to all periods presented in the Financial Statements except for the opening IFRS consolidated statement of financial position, which has utilized optional exemptions available and mandatory exemptions under IFRS 1 as described in Note 18.

	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 into which the preferred shares are convertible were also reduced to one-fifth. In addition, the conversion price of the preferred shares, the weighted average exercise price and fair value per options, warrants and stock unit awards have been adjusted to five times the pre-consolidation prices. All share and per share amounts included in these financial statements have been adjusted retroactively for the consolidation.

Sonde Resources Corp.

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Page 5

2.	Basis of preparation (continued)

	The Financial Statements have been prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business.

	(c)	Functional and reporting currencies

	The Financial Statements are presented in Canadian dollars, which is the Company’s functional currency.

	(d)	Use of estimates and judgment

	The timely preparation of financial statements requires that management make estimates and assumptions and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as at the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant accounting estimates and judgments used in the preparation of the financial statements are described in Note 4.

3.	Significant accounting policies

	There have been no changes to the Company’s principal accounting policies disclosed in the condensed consolidated financial statements for the quarter ended March 31, 2011.

	The Company has not applied the following new and revised IFRSs that have been issued but are not yet effective.

		IFRS 7 (revised)	“Financial Instruments: Disclosures”
		IFRS 9 (revised)	“Financial Instruments: Classification and Measurement”
		IAS 12 (revised)	“Income Taxes”
		IFRS 10 (new)	“Consolidated Financial Statements”
		IFRS 11 (new)	“Joint Arrangements”
		IFRS 12 (new)	“Disclosure of Interests in Other Entities”
		IAS 27 (revised)	“Separate Financial Statements”
		IAS 28 (revised)	“Investments in Associates and Joint Ventures”
		IFRS 13 (new)	“Fair Value Measurement”
		IAS 1 (revised)	“Presentation of Financial Statements”

4.	Significant accounting estimates and judgments

	The timely preparation of financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant estimates used in the preparation of the financial statements include, but are not limited to, those areas discussed below.

	(a)	Oil and gas reserves

	Certain depletion, depreciation, impairment and decommissioning and restoration charges are measured based on the Company’s estimate of oil and gas reserves. The estimation of reserves and resources is an inherently complex process and involves the exercise of professional judgment. Reserves and resources have been evaluated at December 31, 2010, by independent petroleum consultants in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The reserves and resources estimates are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook.

	Oil and gas reserves and resources estimates are based on a range of geological, technical and economic factors, including projected future rates of production, estimated commodity prices, engineering dates, and the timing and amount of future expenditures, all of which are subject to uncertainty. Assumptions reflect market and regulatory conditions existing at each annual reporting date, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Sonde Resources Corp.

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Page 6

4.	Significant accounting estimates and judgments (continued)

	(b)	Exploration and evaluation costs

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

	(c)	Decommissioning liabilities and other provisions

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

	(d)	Deferred income taxes

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

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

	(e)	Impairment of assets

	The allocation of assets into cash generating units (“CGU’s”) requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, shared infrastructures, and the way in which management monitors the operations.

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

	(f)	Stock based compensation

	Expenses recorded for stock based compensation are based on the historical volatility of the Company’s share price which may not be indicative of the future volatility. Accordingly, those amounts are subject to measurement uncertainty.

Sonde Resources Corp.

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Page 7

5.	Discontinued operations

	(a)	Trinidad and Tobago

	On December 22, 2010, the Company entered into an agreement to sell its remaining 25% interest in Block 5(c) and the Mayaro-Guayaguayare block (“MG Block”) exploration and production license for an aggregate purchase price of US$87.5 million plus interest on the outstanding balance prior to closing. The transaction closed on June 22, 2011, for gross proceeds of US$78.1 million and the assumption of the Company’s performance guarantee provided for the MG Block of US$12.0 million. The purchaser guaranteed the performance guarantee, resulting in a receivable with the right to offset the Company’s obligation regarding the MG Block. The Company has recorded this as a receivable offsetting the MG block performance guarantee liability as further discussed in Note 17.

	On February 8, 2011, as part of the agreement, the Company issued a US$20.0 million debenture to the purchaser. The debenture accrued interest at 6.0% per annum and was secured against the Company’s Block 5(c) interests. Upon closing of the agreement, the US$20.0 million was applied against the proceeds of US$78.1 million. Upon closing of the agreement the Company was eligible to reclaim US$20.0 million ($19.3 million in Canadian dollars) held as restricted cash with BG International Limited (“BG”). On August 4, 2011, the Company received payment of the US$20.0 million.

Proceeds from disposition	(CDN$ thousands)
Cash received		56,877
Debenture retired		19,898
MG Block Performance Guarantee Assumed By Purchaser		11,716
Transaction costs		(583	)
Net proceeds		87,908

Net assets disposed at carrying value
Exploration and evaluation assets		79,665
Decommissioning provisions		(3,040	)
Net assets		76,625
Gain before understated		11,283
Realized foreign currency translation reserve, reclassified from shareholders' equity		(5,976	)
Net gain on disposition		5,307

	(b)	LNG Project

	On February 22, 2011, the Company completed the sale of its wholly owned subsidiary Liberty Natural Gas LLC which owns a 100% working interest in the LNG Project to an entity related to West Face Capital Inc. (“West Face”). Pursuant to the sale, the Company received US$1.0 million for reimbursable costs between January 1, 2011, and February 22, 2011. The Company is entitled to receive deferred cash consideration of US$12.5 million payable upon West Face’s first successful gas delivery. No amounts have been recorded in these consolidated financial statements related to this contingent consideration.

Sonde Resources Corp.

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Page 8

5.	Discontinued operations (continued)

	(c)	Financial information from discontinued operations

	The assets and liabilities of discontinued operations presented on the consolidated statements of financial position are as follows:

	Trinidad and Tobago						LNG Project						Total
	Sept. 30 2011		Dec. 31 2010		Jan. 1 2010		Sept. 30 2011		Dec. 31 2010		Jan. 1, 2010		Sept. 30 2011		Dec. 31, 2010		Jan. 1 2 010
(CDN$ thousands)
Assets
Restricted cash		--		19,892		20,910		--		--		--		--		19,892		20,910
Accounts receivable		--		--		2,824		--		--		--		--		--		2,824
Prepaid expenses and deposits		--		20		48		--		36		37		--		56		85
Exploration and evaluation assets		--		80,744		69,998		--		--		--		--		80,744		69,998
Property, plant and equipment		--		--		--		--		--		18,974		--		--		18,974
		--		100,656		93,780		--		36		19,011		--		100,692		112,791
Liabilities
Accounts payable and accrued liabilities		--		12,638		752		--		1,069		1,041		--		13,707		1,793
Decommissioning provision		--		2,943		2,763		--		--		--		--		2,943		2,763
		--		15,581		3,515		--		1,069		1,041		--		16,650		4,556

Income (loss) from discontinued operations reported in the consolidated statement of operations, comprehensive loss and deficit is as follows:

	Trinidad and Tobago						LNG Project						Total
For the nine months ending September 30	2011			2010			2011			2010			2011			2010
(CDN$ thousands)
Expenses
General and administrative		(626	)		--			(879	)		--			(1,505	)		--
Finance costs		(493	)		(93	)		--			--			(493	)		(93	)
Gain (loss) on disposition of foreign operations, net of realized foreign currency translation		5,308						(389	)					4,919
Income (loss) from discontinued operations		4,189			(93	)		(1,268	)		--			2,921			(93	)
Foreign currency translation gain (loss) relating to assets and liabilities held for sale		(1,148	)		(1,813	)		20			(596	)		(1,128	)		(2,409	)
Reclassified from foreign currency translation to net earnings		5,976			--			389			--			6,365			--
Total comprehensive income (loss) from discontinued operations		9,017			(1,906	)		(859	)		(596	)		8,158			(2,502	)

	Trinidad and Tobago						LNG Project					Total
For the three months ending September 30	2011			2010			2011		2010			2011			2010
(CDN$ thousands)
Expenses
General and administrative		(92	)		--			30		--			(62	)		--
Finance costs		--			(29	)		--		--			--			(29	)
Gain (loss) on disposition of foreign operations, net of realized foreign currency translation		318			--			--		--			318			--
Income (loss) from discontinued operations		226			(29	)		30		--			256			(29	)
Foreign currency translation gain (loss) relating to assets and liabilities held for sale		--			(3,094	)		--		(1,461	)		--			(4,555	)

Total comprehensive income (loss) from discontinued operations		226			(3,123	)		30		(1,461	)		256			(4,584	)

Sonde Resources Corp.

Q3 2011 FS

Page 9

6.	Exploration and evaluation assets & Property, plant and equipment, net

	September 30, 2011									December 31, 2010
	Cost			Accum DD&A			Carrying value			Cost			Accum DD&A			Carrying value
Exploration and evaluation assets
Beginning of period		49,361			--			49,361			12,526			--			12,526
Additions		13,054			--			13,054			46,443			--			46,443
Transfers to PP&E assets		(35	)		--			(35	)		--			--			--
Impairments, to exploration expense		(1,158	)		--			(1,158	)		(9,114	)		--			(9,114	)
Foreign exchange		3,297			--			3,297			(494	)		--			(494	)
End of period		64,519			--			64,519			49,361			--			49,361

Property, plant and equipment
Beginning of period		161,165			(58,562	)		102,603			146,672			(994	)		145,678
Additions		25,849			--			25,849			14,493			--			14,493
Acquisitions		11,917			--			11,917			--			--			--
Transfers from E&E assets		35			--			35			--			--			--
Depreciation and depletion		--			(10,652	)		(10,652	)		--			(16,795	)		(16,795	)
Impairments		--			--			--			--			(40,773	)		(40,773	)
End of period		199,964			(69,214	)		129,750			161,165			(58,562	)		102,603

	During the nine month period ended September 30, 2011, the Company capitalized $2.4 million (year ended December 31, 2010 – $5.4 million) of general and administrative expenses related to exploration and development activities of continuing operations and nil (December 31, 2010 - $12.9 million) of general and administrative expenses related to exploration and development activities of discontinued operations.

	Exploration and evaluation assets consist of the Company’s exploration projects which are pending the determination of proved or probable reserves. Additions represent the Company’s share of costs incurred on exploration and evaluation assets during the period. All property, plant and equipment are held in Canada. Exploration and evaluation assets are divided geographically as follows:

	September 30 2011		December 31 2010		January 1 2010
Canada		5,070		2,956		8,968
North Africa		59,449		46,405		3,558
		64,519		49,361		12,526

Sonde Resources Corp.

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Page 10

7.	Property acquisition

	On September 23, 2011, the Company completed a property acquisition consisting of oil and gas assets located in the Drumheller region of Alberta. The net purchase price paid by Sonde was $6.1 million consisting of $6.3 million of cash and $0.2 million accrued as owing from the vendor for future adjustments. The property acquisition was accounted for as a business combination using the acquisition method whereby the net assets acquired and the liabilities assumed are recorded at fair value. Had the acquisition closed January 1, 2011, an additional $1.7 million of revenue, net of royalties and taxes, and $0.6 million of operating and transportation expenses would have been recognized in the condensed consolidated statements of operations and comprehensive income. Net income effects from the acquisition are not readily determinable.

Consideration	(CDN$ thousands)
Cash paid		6,337
Accrued adjustment receivable		(249	)
Net consideration		6,088

Net assets acquired
Property, plant and equipment		11,917
Decommissioning provisions		(5,829	)
Net assets		6,088

8.	Financial instruments

	Cash and cash equivalents and restricted cash are financial assets designated at fair value through profit or loss. Gains or losses related to periodic revaluation at each reporting period are recorded to net income or loss. Cash equivalents are transacted in active markets and have been classified using Level 1 inputs.

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

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

	Derivatives are designated at fair value through profit or loss. Gains or losses related to periodic revaluation at each reporting period are recorded to net income or loss.

	The following tables provide fair value measurement information for financial assets and liabilities as of September 30, 2011, and December 31, 2010. The carrying value of cash and cash equivalents, restricted cash, trade and other receivables, provisions, accounts payable and accrued liabilities, convertible preferred shares, demand loan and the revolving credit facility included in the consolidated statement of financial position approximate fair value due to the short term nature of those instruments. These assets and liabilities are not included in the tables.

					Fair value measurements using:
As at September 30, 2011	Carrying value		Fair value		Level 1		Level 2		Level 3
Financial assets:
Commodity contracts		306		306		--		306		--
Total financial assets		306		306		--		306		--
Financial liabilities
Commodity contracts		431		431		--		431		--
Derivative liability – warrants		36		36		--		36		--
Conversion feature on convertible preferred shares		548		548		--		--		548
Total financial liabilities		1,015		1,015		--		467		548

Sonde Resources Corp.

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Page 11

8.	Financial instruments (continued)

					Fair value measurements using:
As at December 31, 2010	Carrying value		Fair value		Level 1		Level 2		Level 3
Financial liabilities
Derivative liability – warrants		404		404		--		404		--
Conversion feature on convertible preferred shares		4,695		4,695		--		--		4,695
Total financial liabilities		5,099		5,099		--		404		4,695

	The Company uses a fair value hierarchy to categorize the inputs used to measure the fair value of its financial instruments.

	Level 1 Fair Value Measurements

	Level 1 fair value measurements are based on unadjusted quoted market prices. Cash equivalents and restricted cash have been classified as level 1.

	Level 2 Fair Value Measurements

	Level 2 fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted indices.

	Commodity contracts – Risk management contracts are marked to market by reference to the forward prices per the applicable commodity exchange.

	Derivative liability on warrants – The fair value of the conversion feature is determined using a Black Scholes model. The assumptions included in the model include the risk-free discount rate, volatility and expected dividend rates.

	Level 3 Fair Value Measurements

	Level 3 fair value measurements are based on unobservable information.

	Conversion features on preferred shares – The fair value of the conversion feature is determined using a binomial lattice model. The assumptions included in the model include the risk-free discount rate, volatility, expected dividend rates, conversion price and forced conversion price. At September 30, 2011, the conversion feature was valued using a risk-free discount rate of 0.205%, volatility of 67% and expected dividend rate of 0%.

	All components of the Series B shares have been classified as current at September 30, 2011, and December 31, 2010. The following table summarizes the carrying value of the liability and equity components of the convertible preferred shares:

	Liability component						Conversion feature					Total
	Series A shares			Series B shares			Series A shares		Series B shares
Balance, January 1, 2010		15,301			--			--		--			15,301
Accreted non-cash interest, pre conversion		44			--			--		--			44
Loan restructuring		(15,345	)		15,517			--		3,415			3,587
Accreted non-cash interest, post conversion		--			119			--		--			119
Fair value change conversion feature		--			--			--		1,371			1,371
Foreign exchange		--			(839	)				(91	)		(930	)
Balance, December 31, 2010		--			14,797			--		4,695			19,492
Accreted non-cash interest		--			54			--		--			54
Fair value change conversion feature		--			--			--		(4,194	)		(4,194	)
Foreign exchange		--			799			--		47			846
Balance, September 30, 2011		--			15,650			--		548			16,198

Sonde Resources Corp.

Q3 2011 FS

Page 12

9.	Risk Management

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

	Credit risk

	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 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 industry credit risks. The Company’s credit risk exposure is as follows:

	September 30		December 31
	2011		2010
(CDN$ thousands) Western Canada joint interest billings		1,521		2,036
Goods and Services Tax receivable		2,085		1,314
North Africa recoverable expenses		130		--
Revenue accruals and other receivables		4,323		3,797
Accounts receivables		8,059		7,147
Restricted cash		--		19,892
Financial assets designated at fair value through profit or loss		306		--
Credit exposure		8,365		27,039

	The Company’s allowance for doubtful accounts is currently $2.1 million (December 31, 2010 – $3.0 million). These amounts offset $1.8 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2010 – $1.8 million), $0.3 million of Western Canada joint interest and miscellaneous receivables (December 31, 2010 – $0.3 million) and nil withholding tax receivable on preferred share dividends (December 31, 2010 – $0.9 million) that the Company considers past due.

	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 following commodity price risk contract was in place as of the date of this report.

Term	Contract	Volume (GJ/d)		Fixed Price ($/GJ)		Realized gain

March 1, 2011 – December 31, 2011	Swap		5,000	$	4.11	$	585

In exchange for receiving the fixed price on the February 14, 2011, Swap Agreement, the Company issued the following call option:

Term	Contract	Volume (Bbls/d)		Fixed Price (US$/Bbl)		Realized loss

March 1, 2011 – December 31, 2012	Call option		250	$	100.00	$	(105	)

Sonde Resources Corp.

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Page 13

9.	Risk Management (continued)

	Foreign exchange risk

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

	September 30		December 31
	2011		2010
(US$ thousands) Cash and cash equivalents		17,917		1,744
Restricted cash		--		20,000
Foreign denominated financial assets		17,917		21,744

	September 30		December 31
	2011		2010
(US$ thousands) Block 5(c) payables included in liabilities held for sale		--		285
MG Block payables included in liabilities held for sale		--		12,040
North Africa payables		142		7,947
Mariner swap provision		12,500		12,500
Convertible preferred shares		15,000		14,878
Conversion feature on convertible preferred shares		522		4,720
Derivative liability - warrants		35		355
Foreign denominated financial liabilities		28,199		52,725

	These balances are exposed to fluctuations in the U.S. dollar. At this time, the Company has chosen not to enter into any risk management agreements to mitigate foreign exchange risk. The Company’s exposure to foreign currency exchange risk on its comprehensive income assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent is $0.6 million. This analysis assumes all other variables remain constant.

	Interest rate risk

	The Company is exposed to interest rate risk as the credit facilities bear interest at floating market interest rates. The Company has no interest rate swaps or hedges to mitigate interest rate risk at September 30, 2011. The Company’s exposure to fluctuations in interest expense on its net loss and comprehensive income, assuming reasonably possible changes in the variable interest rate of +/- 1% is $0.1 million. This analysis assumes all other variables remain constant.

10.	Provisions

	September 30 2011		December 31 2010		January 1 2010
Mariner swap (note 17c)		13,103		12,433		--
Onerous contracts		23		259		1,146
Provisions		13,126		12,692		1,146

Sonde Resources Corp.

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Page 14

11.	Short term debt

	September 30 2011		December 31 2010		January 1 2010
Credit facility A		131		20,251		24,067
Convertible preferred shares		15,650		14,797		15,301
Short term debt		15,781		35,048		39,368

	As at September 30, 2011, the Company had issued two letters of credit for $0.1 million (December 31, 2010 – letters of credit of $0.1 million, short term debt of $20.2 million) against the $40.0 million (December 31, 2010 - $40.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75% as at September 30, 2011, and prime plus 0.75% as at December 31, 2010. Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company. Credit Facility A has covenants, as defined in the Company’s credit agreement, that require the Company to maintain its working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative expenditures in excess of $7.0 million per year and all foreign capital expenditures are not funded from Credit Facility A nor domestic cash flow while Credit Facility A is outstanding.

	On February 22, 2011, the Company obtained an additional $20.0 million development demand loan (“Credit Facility B”) at a variable interest rate of 50 basis points above the variable interest rate on Credit Facility A. Credit Facility B was to be used to assist in the acquisition of producing petroleum and natural gas reserves and/or development of proved producing/undeveloped petroleum and natural gas reserves. On August 16, 2011, the Company repaid the $6.3 million balance on the loan. On October 12, 2011, the Company cancelled this facility in order to reduce standby fees. Subject to availability and review, Credit Facility B can be reopened should the Company require access to additional debt financing.

	As at December 31, 2010, the Company was in violation of one of its debt covenants. This covenant placed a ceiling on foreign expenditures that was exceeded pending the approval of the Trinidad and Tobago asset sale. The Company sought and received a waiver from its lender on this violation and it does not impact the Company’s borrowing ability. As at September 30, 2011, the Company was in compliance with all of its debt covenants.

	The Company is subject to the next semi-annual review of its credit facilities on or before April 30, 2012.

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

	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 year ended December 31, 2010. The conversion feature and the issuance of common share purchase warrants have been recorded as financial derivative liabilities (Note 8).

	During the nine months ended September 30, 2011, and the year ended December 31, 2010, the Company elected to pay cash as opposed to common shares to satisfy its quarterly preferred shares dividend requirements.

Sonde Resources Corp.

Q3 2011 FS

Page 15

12.	Revenue

	The following summarizes the Company’s revenue:

	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
Petroleum and natural gas sales		10,279			8,248			29,255			27,142
Royalties		(1,291	)		(1,021	)		(3,441	)		(4,155	)
		8,988			7,227			25,814			22,987

13.	Operating expense

	Operating costs for the Company are as follows:

	Three months ended September 30				Nine months ended September 30
	2011		2010		2011		2010
Operating		3,521		2,853		9,627		8,310
Well workovers		609		238		1,412		348
		4,130		3,091		11,039		8,658

14.	Financing costs

	Three months ended September 30				Nine months ended September 30
	2011		2010		2011		2010
Accretion on decommissioning provision		165		158		488		516
Interest on credit facilities		73		29		705		187
Interest on preferred shares		264		226		762		717
		502		413		1,955		1,420

15.	Stock based compensation

	(a)	Stock option plan

	The Company has a stock option plan for its directors, officers and employees. The exercise price for stock options granted is the quoted market price on the grant date vesting over a three year period. Options issued prior to May 2011 vest over three years with a maximum term of ten years. Options issued May 2011 onwards vest over four years with a maximum term of five years.

	Nine months ended September 30, 2011					Twelve months ended December 31,2010
	Number of options			Weighted average exercise price		Number of options			Weighted average exercise price
(CDN$ thousands, except per share price)
Balance, beginning of period		1,910		$	5.78		1,978		$	9.10
Cancelled		--			--		(258	)		11.90
Forfeited		(524	)		8.82		(792	)		8.67
Granted		1,867			3.54		982			3.08
Balance, end of period		3,253			4.01		1,910			5.78

Sonde Resources Corp.

Q3 2011 FS

Page 16

15.	Stock based compensation (continued)

	The following table summarizes stock options outstanding under the plan at September 30, 2011:

	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 ($)
2.50 – 3.00	920	4.70	2.80	50	2.86
3.01 – 4.00	1,158	8.79	3.11	522	3.09
4.01 – 5.00	916	9.29	4.29	298	4.30
5.01 – 10.00	103	2.52	8.47	103	8.47
10.01 – 18.90	156	5.40	13.21	156	13.21
2.81 – 18.90	3,253	7.41	4.01	1,129	5.29

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 2011		Twelve months ended December 31 2010
Share price ($)		3.54		3.08
Exercise price ($)		3.54		3.08
Risk free rate (%)		2.1		2.1
Expected life (years)		4.2		3.8
Expected dividend yield (%)		--		--
Expected volatility (%)		140.6		122.8
Weighted average fair value of options granted		3.02		2.54

	A forfeiture rate of 27.7% (December 31, 2010 – 16.9%) is used when recording stock based compensation. This estimate is based on the historical forfeiture rate and adjusted to the actual forfeiture rate. Stock based compensation cost of $4.6 million incurred for the nine month period ending September 30, 2011 (September 30, 2010 - $1.6 million) was expensed. No stock based compensation expense was capitalized during the first nine months of 2011 or 2010.

	(b)	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 104,113 shares on the open market under the ESSP during the nine months ended September 30, 2011 (September 30, 2010 – 67,891 shares).

	(c)	Stock unit awards

	As at September 30, 2011, the Company has issued 1.5 million (December 31, 2010 – 0.7 million) stock unit awards to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the aplicable vesting date. The stock units have time and/or share based performance vesting terms which vary depending on whether the holder is an executive officer or director. If subsequent to the grant date, the shareholders of the Company approve an equity compensation plan under which the stock units may be paid with common shares of the Company, then the Board may determine that the stock units may be paid in cash or common shares. As of September 30, 2011, the Company recorded a liability of $1.4 million to recognize the fair value of the vested stock units (December 31, 2010 - $1.0 million).

	(d)	Restricted share units

	The Restricted Share Unit Plan became effective on March 24, 2011, to attract and retain experienced personnel with incentive compensation tied to shareholder return. Under the plan, each grantee will be entitled to, in respect of each Restricted Share Unit (“RSU”), a cash amount equal to the fair market value of one common share in the capital of the Company on such vesting date, with the vesting subject to a minimum floor share price.

Sonde Resources Corp.

Q3 2011 FS

Page 17

15.	Stock based compensation (continued)

	The following table summarizes RSUs outstanding under the plan at September 30, 2011:

	Units outstanding			Units exercisable
Floor price ($)	Number of units (thousands)	Average remaining contractual life (years)	Weighted average floor price ($)	Number of units (thousands)	Weighted average floor price ($)
0.00 – 3.00	295	2.05	1.98	104	2.52
3.01 – 3.50	42	2.29	3.13	--	--
3.51 – 3.64	12	2.29	3.64	--	--
0.00 – 3.64	349	2.09	2.18	104	2.52

RSUs issued during the period were initially valued at the grant date and revalued at September 30, 2011 using a binomial lattice approach with weighted average assumptions as follows:

	Valuation at September 30 2011		Valuation at grant date
Share price ($)		2.41		2.55
Risk free rate (%)		0.9		1.5
Expected life (years)		2.1		2.4
Expected volatility (%)		60		55
Weighted average fair value		1.96		2.10

The following table summarizes stock based compensation expense:

	Three months ended September 30					Nine months ended September 30
	2011			2010		2011		2010
Stock option expense		743			382		3,401		1,380
Stock unit award expense		72			134		852		189
Restricted share unit expense		(11	)		--		350		--
Stock based compensation expense		804			516		4,603		1,569

The following table summarizes the stock based compensation liability:

	September 30 2011		December 31 2010		January 1 2010
Stock unit award liability		1,382		530		55
Restricted share unit liability		350		--		--
Stock based compensation liability		1,732		530		55

Sonde Resources Corp.

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Page 18

16.	Supplemental cash flow information

	Changes in non-cash working capital

	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
Accounts receivable		(2,111	)		6,648			(912	)		5,891
Prepaid expenses and deposits		(58	)		(3,510	)		399			(5,741	)
Accounts payable and accrued liabilities		(3,815	)		(3,739	)		(19,501	)		(16,031	)
Provisions		1,040			(221	)		435			(666	)
Change in non-cash working capital		(4,944	)		(822	)		(19,579	)		(16,547	)

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

	Three months ended September 30						Nine months ended June 30
	2011			2010			2011			2010
Operating		(4,641	)		(1,214	)		(3,552	)		(6,199	)
Financing		--			190			--			190
Investing		(303	)		202			(16,027	)		(10,538	)
		(4,944	)		(822	)		(19,579	)		(16,547	)

Cash and cash equivalents were comprised of the following:

	September 30 2011		December 31 2010		January 1 2010
Cash held in banking institutions		16,535		2,649		3,305
Marketable securities		14,137		--		--
Cash and cash equivalents		30,672		2,649		3,305

	The Company’s policy is to invest excess cash in highly liquid short-term investment instruments with minimal principal risk.

17.	Contingencies and commitments

	(a)	MG Block Trinidad and Tobago

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

Sonde Resources Corp.

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Page 19

17.	Contingencies and commitments (continued)

	The Company’s agreement to sell its remaining interest in Block 5(c) and the MG Block includes the assumption of the performance guarantee. Upon closing the sale on June 22, 2011, the purchaser assumed the performance guarantee for the MG Block. While the rights to the MG Block were not transferred to the purchaser pending Trinidad and Tobago's approval of the assignment of such rights, this guarantee provides a receivable with the right to offset the US$12.0 million performance guarantee in discontinued operations (Note 5). Should the Company be required to pay the performance security amount in order to relinquish the MG Block, the purchaser will reimburse the Company for any amounts owing up to US$12.0 million. The Company expects that the purchaser’s guarantee will offset any further liability with respect to the MG Block. As of September 30, 2011, the Company had ceased all operations in Trinidad and exited the country but the assignment of the MG Block has yet to be approved.

	(b)	North Africa

	Joint Oil block

	On August 27, 2008, the Company entered into the EPSA with a Tunisian company, Joint Oil. Joint Oil is owned equally by the governments of Tunisia and Libya.The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, the Company is the operator. Under the EPSA, the minimum work program for the first phase (four years) of the seven year exploration period includes the Zarat North-1 appraisal well, three exploration wells and 500 square 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. On January 11, 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North–1 well. The well has been temporarily abandoned in a manner allowing it to be utilized for future development purposes while the Company evaluates reservoir characteristics and development options on a field development.

	Political issues and Libyan sanctions

	The governments of Tunisia and Libya are in political turmoil. During January 2011, protests in Tunisia led to the overthrow of the government. The Company safely evacuated its personnel and the rig and equipment without incident. While relative calm has been restored, uncertainty remains over the future direction of the country. Similarly, widespread protests over the government in Libya have occurred with the opposition forces assuming power. On February 26, 2011, the United Nations imposed sanctions on the Libyan government followed by consequent actions of the Canadian Government pursuant to the Special Economics Measures Act (Canada) (the “Libyan Sanctions”). While this turmoil has not had a direct impact on the Company’s Joint Oil Block evaluation of the Zarat North-1 results and planning of future activities, it affected the Company in various ways, including the functioning of Joint Oil, the pace of future development plans and activities, the ability to secure supplies and personnel, the ability to make payments to Joint Oil and the ability to attract joint venture partners or financing.

	The imposition of sanctions and the state of war are unforeseen circumstances beyond the control of the Company, which rendered the performance of Sonde’s obligations impossible and thus constituted a condition of force majeure. As a result, the Company made a formal force majeure declaration to Joint Oil for the Joint Oil Block on June 7, 2011. This declaration effectively put the term of the EPSA on hold, without penalty, pending the resolution of political sanctions and instability in Libya. On August 31, 2011, the Canadian Government repealed its unilateral sanctions against Libya, and further amended the Regulations Implementing the United Nations Resolutions on Libya on September 22, 2011, following the adoption of Resolution 2009 (2011) by the United Nations Security Council (“UNSC”). After careful review of these rulings, and in consultation with the Canadian Foreign Affairs Ministry, Sonde lifted the Force Majeure declaration and is working with Joint Oil personnel to resume normal operations on the Joint Oil Block.

Sonde Resources Corp.

Q3 2011 FS

Page 20

17.	Contingencies and commitments (continued)

	(c)	Swap agreement

	At the time it entered into the North Africa EPSA, the Company also signed a "Swap Agreement" awarding an overriding royalty interest and optional participating interest to Joint Oil, in the Company's "Mariner" Block, offshore Nova Scotia, Canada. No well has been drilled on the Mariner Block and Joint Oil has the right to put back the overriding royalty to the Company for US$12.5 million. On December 31, 2010, the Mariner Block license lapsed resulting in the Company no longer holding any interest in offshore Nova Scotia, Canada. As a result, Joint Oil has notified the Company that it is exercising its put rights. The Company is in discussions with Joint Oil to obtain information to confirm that the Mariner Swap payment does not violate remaining sanctions and that the EPSA remains in full force and effect. Pending this discussion, the Company may post a letter of credit or escrow funds to secure the payment.

	(d)	Commitments

	At September 30, 2011, the Company has committed to future payments over the next five years, as follows:

	2011		2012		Thereafter		Total
Accounts payable and accrued liabilities		12,333		--		--		12,333
Stock based compensation liability		1,732		--		--		1,732
Mariner swap		13,103		--		--		13,103
Derivative financial liabilities		1,015		--		--		1,015
Short term debt		15,781		--		--		15,781
Office rent		392		1,142		--		1,534
Equipment		3		8		--		11
		44,359		1,150		--		45,509

	(e)	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 alleged 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 purported 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 Defendants’ 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. Subsequently, the Stipulation was finalized and approved by the U.S. and Canadian courts. Notice has been given to the classes of possible claimants, and the parties anticipate seeking final court approval in late 2011 subject to the conditions in the Stipulation having been met.

	The Defendants 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.

Sonde Resources Corp.

Q3 2011 FS

Page 21

17.	Contingencies and commitments (continued)

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

18.	Reconciliation of statement of financial position from Canadian GAAP to IFRS

	(a)	IFRS transition exemptions

	IFRS 1 requires the presentation of comparative information as at the January 1, 2010, transition date and subsequent comparative periods as well as the consistent and retrospective application of IFRS accounting policies. To assist with the transition, the provisions of IFRS 1 allow for certain mandatory exceptions and optional exemptions for first-time adopters to alleviate the retrospective application of all IFRSs. The Company has applied the following exemptions to full retrospective application of IFRS in accordance with IFRS 1:

		(i)	Deemed cost of property plant and equipment

		The Company has elected to apply the exemption under IFRS 1 allowing the measurement of oil and gas assets at the date of transition to IFRS to be determined based on the amounts disclosed under the full cost method of accounting in accordance with Canadian GAAP.

		(ii)	Decommissioning liabilities

		The exemption provided in IFRS 1 from the full retrospective application of IFRS 1 has been applied and the difference between the carrying values of the Company’s decommissioning liabilities as measured under IFRS and their carrying values under Canadian GAAP as of January 1, 2010, has been recognized directly in opening deficit.

		(iii)	Share-based payments

		The Company has elected not to apply IFRS 2, Share-based Payments to equity instruments granted after November 7, 2002, that have not vested by the transition date.

		(iv)	Borrowing costs

		The Company has applied the borrowing cost exemption in IFRS 1. It has applied the requirement of IAS 23 to borrowing costs relating to qualifying assets on a prospective basis from the date of transition to IFRS.

		(v)	Foreign currency translation

		The cumulative translation differences for all foreign operations are deemed to be zero at the date of transition to IFRS. Cumulative translation differences are recorded prospectively from this date.

		(vi)	Business combinations

		IFRS 1 allows an entity to use the IFRS rules for business combinations on a prospective basis rather than restating all business combinations.

	(b)	Mandatory exceptions to retrospective application

	Hindsight was not used to create or revise estimates and accordingly the estimates previously made by the Company under Canadian GAAP are consistent with their application under IFRS.

	The remaining IFRS 1 exemptions were not applicable or material to the preparation of the Company’s Consolidated Statement of Financial Position at the date of transition on January 1, 2010.

Sonde Resources Corp.

Q3 2011 FS

Page 22

18.	Reconciliation of statement of financial position from Canadian GAAP to IFRS (continued)

	(c)	Reconciliation of assets, liabilities and shareholders’ equity

	The following reconciliations present the adjustments made to the Company's Canadian GAAP financial results of operations and financial position to comply with IFRS. A summary of the significant accounting policy changes and applicable exemptions are discussed following the reconciliations.

		December 31, 2010									September 30, 2010									January 1, 2010
	Note 18(e)	Canadian GAAP			Adj			IFRS			Canadian GAAP			Adj			IFRS			Canadian GAAP			Adj		IFRS

Assets
Current
Cash and cash equivalents			2,649			--			2,649			1,435			--			1,435			3,305		--			3,305
Restricted cash			--			--			--			630			--			630			1,364		--			1,364
Accounts receivable			7,147			--			7,147			5,522			--			5,522			11,340		--			11,340
Derivative financial assets			--			--			--			1,024			--			1,024			--		--			--
Prepaid expenses and deposits			1,686			--			1,686			9,220			--			9,220			3,185		--			3,185
Assets of discontinued operations	(i)		104,299			(3,607	)		100,692			23,392			--			23,392			23,819		--			23,819
			115,781			(3,607	)		112,174			41,223			--			41,223			43,013		--			43,013
Long term portion of prepaid expenses and deposits			555			--			555			608			--			608			878		--			878
Exploration and evaluation assets	(vi),(v), (viii),(xi)		--			49,361			49,361			--			20,962			20,962			--		12,526			12,526
Property, plant and equipment, net	(ii),(v)-(viii)		152,085			(49,482	)		102,603			146,765			(18,027	)		128,738			158,204		(12,526	)		145,678
Assets of discontinued operations	(i)		--			--			--			100,451			(2,004	)		98,447			89,737		(765	)		88,972
			268,421			(3,728	)		264,693			289,047			931			289,978			291,832		(765	)		291,067

Liabilities
Current
Accounts payable and accrued liabilities			18,126			--			18,126			9,039			--			9,039			26,443		--			26,443
Stock based compensation liability			530			--			530			244			--			244			55		--			55
Provisions	(ix)		12,433			259			12,692			--			480			480			--		1,146			1,146
Derivative financial liabilities	(iii),(iv)		--			5,099			5,099			--			--			--			--		--
Short term debt	(iii)		35,048			--			35,048			3,097			--			3,097			24,067		15,301			39,368
Liabilities of discontinued operations	(i)		15,212			1,438			16,650			3,166			--			3,166			1,793		--			1,793
			81,349			6,796			88,145			15,546			480			16,026			52,358		16,447			68,805
Derivative financial liabilities	(iii),(iv)		--			--			--			--			1,727			1,727			--		--			--
Convertible preferred shares	(iii)		--			--			--			15,276			--			15,276			15,301		(15,301	)		--
Decommissioning provision	(ii)		13,802			4,395			18,197			13,717			4,425			18,142			12,591		3,314			15,905
Liabilities of discontinued operations	(i)		--			--			--			1,476			1,940			3,416			1,387		1,376			2,763
			95,151			11,191			106,342			46,015			8,572			54,587			81,637		5,836			87,473

Shareholders' equity
Share capital	(xii)		339,183			30,709			369,892			339,183			30,709			369,892			280,561		30,709			311,270
Equity portion of preferred shares	(iii)		12,682			(12,682	)		--			12,682			(12,682	)		--			1,969		(1,969	)		--
Warrants	(iv)		303			(303	)		--			303			(303	)		--			76		--			76
Contributed surplus	(x)		29,452			1,616			31,068			27,951			1,967			29,918			26,923		1,571			28,494
Foreign currency translation reserve	(xi)		--			(5,789	)		(5,789	)		--			(2,126	)		(2,126	)		--		--			--
Deficit	all		(208,350	)		(28,470	)		(236,820	)		(137,087	)		(25,206	)		(162,293	)		(99,334	)	(36,912	)		(136,246	)
			173,270			(14,919	)		158,351			243,032			(7,641	)		235,391			210,195		(6,601	)		203,594
			268,421			(3,728	)		264,693			289,047			931			289,978			291,832		(765	)		291,067

Sonde Resources Corp.

Q3 2011 FS

Page 23

18.	Reconciliation of statement of financial position from Canadian GAAP to IFRS (continued)

	(d)	Reconciliation of total comprehensive loss

		Year ended December 31, 2010									Nine months ended September 30, 2010									Three months ended September 30, 2010
	Note 5(e)	Canadian GAAP			Adj			IFRS			Canadian GAAP			Adj			IFRS			Canadian GAAP			Adj			IFRS

Revenue
Petroleum and natural gas sales, net of royalties			32,239			--			32,239			22,987			--			22,987			7,227			--			7,227
Gain on commodity derivatives			3,197			--			3,197			3,156			--			3,156			247			--			247
			35,436			--			35,436			26,143			--			26,143			7,474			--			7,474
Expenses
Operating			13,036			--			13,036			8,658			--			8,658			3,091			--			3,091
Transportation			1,304			--			1,304			989			--			989			379			--			379
Exploration	(viii)		--			9,114			9,114			--			535			535			--			336			336
General and administrative	(ix)		12,014			(888	)		11,126			9,269			(666	)		8,603			3,114			(221	)		2,893
Depletion and depreciation	(vii)		27,743			(11,069	)		16,674			21,051			(8,440	)		12,611			6,681			(2,809	)		3,872
Impairments	(vi)		38,756			2,017			40,773			9,712			5,526			15,238			--			--			--
Stock based compensation	(x)		2,960			45			3,005			1,173			396			1,569			399			117			516
Bad debt			852			--			852			867			--			867			(48	)		--			(48	)
Loss on abandonment			123			--			123			7			--			7			--			--			--
			96,788			(781	)		96,007			51,726			(2,649	)		49,077			13,616			(2,577	)		11,039
Operating income (loss)			(61,352	)		781			(60,571	)		(25,583	)		2,649			(22,934	)		(6,142	)		2,577			(3,565	)

Other
Financing costs	(ii)		(1,239	)		(664	)		(1,903	)		(811	)		(609	)		(1,420	)		(226	)		(187	)		(413	)
Gain (loss) on foreign exchange	(xi)		744			144			888			(300	)		664			364			(1,482	)		2,034			552
Gain (loss) on financial derivatives	(iii) (iv)		--			(5,210	)		(5,210	)		--			(1,779	)		(1,779	)		--			--			--
Other income	(viii)		165			136			301			275			136			411			131			--			131
Loss on exchange of preferred shares			(172	)		--			(172	)		(172	)		--			(172	)		--			--			--
			(502	)		(5,594	)		(6,096	)		(1,008	)		(1,588	)		(2.596	)		(1,577	)		1,847			270
Loss before income taxes from continuing operations			(61,854	)		(4,813	)		(66,667	)		(26,591	)		1,061			(25,530	)		(7,719	)		4,424			(3,295	)
Part VI.1 tax on preferred share dividends			470			--			470			424			--			424			38			--			38
Loss from continuing operations			(62,324	)		(4,813	)		(67,137	)		(27,015	)		1,061			(25,916	)		(7,757	)		4,424			(3,333	)
Net income (loss) from discontinued operations	(i)		(35,676	)		2,238			(33,438	)		278			(371	)		(93	)		847			(876	)		(29	)
Net loss			(98,000	)		(2,575	)		(100,575	)		(26,737	)		690			(26,047	)		(6,910	)		3,548			(3,362	)

Other comprehensive loss
Foreign currency translation adjustment	(xi)		--			(552	)		(552	)		--			283			283			--			327			327
Foreign currency translation adjustment relating to assets and liabilities held for sale	(xi)		--			(5,237	)		(5,237	)		--			(2,409	)		(2,409	)		--			(4,555	)		(4,555	)
Other comprehensive loss			--			(5,789	)		(5,789	)		--			(2,126	)		(2,126	)		--			(4,228	)		(4,228	)
Total comprehensive loss			(98,000	)		(8,364	)		(106,364	)		(26,737	)		(1,436	)		(28,173	)		(6,910	)		(680	)		(7,590	)

Sonde Resources Corp.

Q3 2011 FS

Page 24

18.	Reconciliation of statement of financial position from Canadian GAAP to IFRS (continued)

	(e)	Explanation of significant adjustments

		(i)	Assets/liabilities held for sale and discontinued operations

		Foreign currency translation differences associated with the LNG Project and Trinidad and Tobago assets and liabilities were recorded as part of net loss from discontinued operations under Canadian GAAP. Under IFRS, these differences were reclassified to other comprehensive loss. See section (xi) for details on foreign currency translation differences.

		Decommissioning provision differences between IFRS and Canadian GAAP associated with Trinidad and Tobago assets were recorded as changes to liabilities held for sale. The impact of changes to the accretion of these provisions was recorded to net loss from discontinued operations. See section (ii) for details on decommissioning provision differences.

		(ii)	Decommissioning provision

		Under Canadian GAAP, increases in the estimated cash flows were discounted using the current credit-adjusted risk-free rate while downward revisions in the estimated cash flows were discounted using the credit-adjusted risk-free rate that existed when the original liability was recognized. Under IFRS, estimated cash flows are discounted using the risk-free rate that exists at the date of the statement of financial position.

		In accordance with IFRS 1, the Company elected to re-measure its decommissioning provision at the IFRS transition date and has estimated the related asset by discounting the liability to the date in which the liability arose and recalculated the accumulated depreciation and depletion under IFRS. Adjustments at the IFRS transition date have been recorded to opening deficit. Adjustments arising as a result of changes in the interest rate during the 2010 period have been recorded to property plant, and equipment. The impact of these changes on accretion has been reflected as a change in financing costs.

		(iii)	Convertible preferred shares

		Under Canadian GAAP, the convertible instrument is split into a liability and an equity component. The value of the liability component was determined at the time of placement of the instrument based on the fair value of the debt component of the instrument. The remaining amount was recorded in equity under Canadian GAAP.

		The treatment of the liability component determined at the time of placement under IFRS is similar to Canadian GAAP. The initial recognition is at fair value. Under Canadian GAAP the carrying value of the liability component is subsequently accreted to its face value using the effective interest method which is similar to IFRS. No adjustment was required upon adoption of IFRS.

		There is no equity instrument recorded for the conversion feature under IFRS. IFRS requires a fixed number of the Company’s own equity instruments to be delivered in exchange for a fixed amount of cash to make recognition as equity possible. As the liability is denominated in United States dollars (“U.S. dollars” or “US$”), and therefore is variable in Canadian dollars, this requirement is not met for the conversion feature of the preferred shares. As a result, under IFRS no equity component can be recorded and the conversion feature is considered an embedded derivative. The embedded derivative is separated and recorded at fair value as a financial derivative liability, with changes in fair value charged to net income or loss.

		On December 17, 2009, the Company renegotiated the terms of the convertible preferred shares. Pursuant to the terms of the restructuring, the Series A convertible preferred shares were exchanged for Series B convertible preferred shares and common share purchase warrants. Series A and B shares have different conversion prices and different redemption/retraction dates. The Certificate of Amendment which created the Series B shares was amended February 3, 2010. Under Canadian GAAP, the modification resulted in the Series A shares being presented as non-current at December 31, 2009, despite the redemption/retraction date of the Series A shares being December 31, 2010. Under Canadian GAAP, short term debt that is refinanced with long term debt prior to completion of the statement of financial position can be classified as non-current if certain criteria have been met. Under IFRS the appropriate treatment is to reflect the Series A shares as current liabilities in the IFRS opening statement of financial position.

		The equity treatment of the modification under Canadian GAAP resulted in adjustments to contributed surplus and incremental equity on preferred shares. Under IFRS, these adjustments are reversed as the conversion features of the modified convertible preferred shares are recorded at their fair value.

Sonde Resources Corp.

Q3 2011 FS

Page 25

18.	Reconciliation of statement of financial position from Canadian GAAP to IFRS (continued)

		(iv)	Preferred share warrants

		As part of the February 3, 2010, modification of the convertible preferred shares, the Company issued warrants, the exercise price of which is denominated in U.S. dollars. Under Canadian GAAP these warrants have been recorded in equity. Under IFRS, the warrants are recorded as a derivative liability at fair value at issuance and at the end of each reporting period, with changes in fair value being recorded in income in the same manner as the convertible preferred shares above.

		(v)	Exploration and evaluation assets and property plant and equipment

		Under Canadian GAAP, the Company applied the full cost method of accounting for oil and gas exploration, development and production activities. Under the full cost method, all costs associated with these activities were capitalized. Under IFRS, the Company elected an IFRS 1 exemption whereby the Canadian GAAP full cost pool was measured upon transition to IFRS as follows:

		-	exploration and evaluation assets were reclassified from the full cost pool to exploration and evaluation assets at the amount that was recorded under Canadian GAAP;

		-	non-oil and gas assets (corporate assets ) were reclassified from the full cost pool to property plant and equipment;

		-	LNG Project related costs were identified as intangible start-up costs and reclassified from the full cost pool to property plant and equipment; and

		-	the remaining full cost pool was allocated to the producing/development assets and components pro rata using reserve values.

		The Company’s exploration and evaluation assets consist of its undeveloped Western Canada land and North Africa offshore assets. Undeveloped land costs identified as exploration and evaluation assets pertain to only those undeveloped sections that the Company intended to actively pursue through its upcoming development programs. Exploration and evaluation assets were assessed for impairment on the IFRS transition date as described in section (vi). Corporate assets and LNG Project costs were also adjusted out of the full cost pool as these were considered non-oil and gas related costs and therefore not subject to the application of the deemed cost exemption. Corporate assets and the LNG Project were evaluated for impairment and subsequently recorded at their carrying values in property plant and equipment.

		(vi)	Impairments

		Under Canadian GAAP, an item of property plant and equipment is deemed recoverable if the undiscounted future cash flows exceed the carrying value of the asset group. Under IFRS, recoverability or property plant and equipment is based on the higher of fair value less costs to sell and value in use of the CGU.

		During the 2010 comparative period, ceiling test impairments were recognized under Canadian GAAP at June 30, 2010 and December 31, 2010. Under IFRS, The Company evaluated these assets for indicators of impairment at each reporting period resulting in further impairment adjustments recorded at June 30, 2010 and December 31, 2010 in relation to the Company’s Western Canada producing and developed assets. Impairments were the result of declining long-term natural gas prices resulting in the carrying value of these CGU’s exceeding their recoverable amounts. Recoverable amounts have been determined using fair value less costs to sell and value in use (the net present value of the cash flow or benefit that an asset generates for a specific use) of each CGU.

		(vii)	Depletion and depreciation

		Under IFRS, the Company adopted a policy of depleting its producing and developed oil and gas assets on a unit of production basis over estimated proved plus probable reserves. The depletion policy under Canadian GAAP was based on units of production over proved reserves. Under Canadian GAAP, depletion was calculated using all of Canada as a single cost centre. IFRS requires depletion and depreciation to be calculated based on individual components (ie. fields or combinations thereof) or CGU’s.

Sonde Resources Corp.

Q3 2011 FS

Page 26

18.	Reconciliation of statement of financial position from Canadian GAAP to IFRS (continued)

		(viii)	Exploration costs and other income

		Under Canadian GAAP, all exploration costs were capitalized in accordance with the full-cost method of accounting for oil and gas assets. Exploration costs identified under IFRS include those costs associated with leases and licences related to undeveloped land that are no longer being actively pursued by the Company as part of its development program. These costs have been recorded as an adjustment from property, plant and equipment to exploration costs during 2010.

		IFRS adjustments related to other income relate to a refund of Nova Scotia offshore work deposits that were recorded against property, plant and equipment under Canadian GAAP during 2010. Under IFRS, carrying value associated with Nova Scotia offshore leases were impaired as part of the application of deemed cost under IFRS 1 on the IFRS transition date. These refunds have been adjusted from property plant and equipment to other income during 2010.

		(ix)	Provisions

		Under IFRS, onerous contracts arise when the costs of meeting the obligations of a contract exceed the benefits to be derived from the agreement. When an onerous contract arises, IFRS requires that a provision be set up for the present obligation of the contract. The Company has lease agreements for office space which it no longer uses, resulting in costs of the agreements outweighing its benefits. Under IFRS, the leases are considered onerous in which case a provision has been recorded on the IFRS transition date as an adjustment to retained earnings. During 2010, the change in provision is recorded as a reduction against general and administrative expense.

		(x)	Share-based payments

		Under Canadian GAAP, the Company recognized an expense related to share based payments on a straight-line basis through the date of full vesting and did not incorporate a forfeiture multiplier. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting awards and estimate a forfeiture rate.

		(xi)	Foreign currency translation

		IFRS 1 allows companies to deem the cumulative translation difference to be zero at transition date. The gain or loss on a subsequent disposal of any foreign operation then excludes the translation differences that arose before the date of transition to IFRS. The Company has elected to apply this exemption.

		When an entity elects to use a deemed cost exemption for certain assets on initial adoption of IFRS, it calculates the cumulative translation amount for those assets not from the date of acquisition but from the date at which the deemed cost amount is determined. The Company has elected to apply the deemed cost exemption for its oil and gas assets as at the date of transition. Therefore oil and gas assets relating to foreign operations identified with a functional currency of U.S. dollars will not be adjusted for foreign exchange differences as the deemed cost has established its reporting currency value. The functional currency carrying value for these assets have been determined by applying the Canadian dollar to U.S. dollar spot rate at the IFRS transition date to the deemed cost amounts.

		The financial information for those operations for which the functional currency is concluded to be different from the Company’s reporting currency of Canadian dollars is the LNG Project, Trinidad and Tobago and North Africa. The only adjustment required at the IFRS transition date is to the decommissioning provision balance for the Company’s Block 5(c) Trinidad and Tobago wells. Foreign exchange adjustments during the 2010 comparative period are required for all non-monetary assets and liabilities. The restatement from functional currency to reporting currency on all assets and liabilities have been recorded in other comprehensive income and accumulated under foreign currency translation reserve.

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18.	Reconciliation of statement of financial position from Canadian GAAP to IFRS (continued)

		(xii)	Flow-through shares

		Under Canadian GAAP, proceeds from flow-through shares are recorded to share capital. When the tax benefits have been renounced to the flow-through shareholder, the Company records a reduction in share capital with a corresponding increase in the future income tax liability. Under IFRS, share capital for flow-through shares issued is recorded to share capital at the quoted value of the shares at the date of issuance. The difference between the quoted value and the gross proceeds received on the issuance of the shares is recorded as a liability. The tax cost resulting from deduction renouncement, less any proceeds received in excess of the quoted value of the shares, must be included in the determination of the tax expense. The Company’s last issuance of flow-through shares was in 2008 resulting in the difference being applied as an increase to share capital with an offset to opening deficit on the IFRS transition date.

		(xiii)	Correction from previous reporting

		In the course of preparing the Financial Statements management identified an error in the application of IFRS on initial adoption. The Company had previously recognized an impairment of $8.4 million related to exploration and evaluation assets upon initial adoption of IFRS at January 1, 2010. Management has determined that the timing of this impairment was incorrect and that the assets should have been impaired to exploration expense in the quarter ended December 31, 2010. The impact is that exploration and evaluation assets and shareholders' equity were understated by $8.4 million at both January 1, 2010 and March 31, 2010, while exploration expense was understated by $8.4 million for the year ended December 31, 2010. This has been corrected in the reconciliations from Canadian GAAP to IFRS and on the statement of financial position as at January 1, 2010.

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Document 2

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") has been prepared by management as of November 9, 2011, and reviewed and approved by the Board of Directors (the “Board”) of Sonde Resources Corp. ("Sonde" or the “Company”). This MD&A is a review of the operational results of the Company with disclosure of oil and gas activities in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Effective January 1, 2011 the Company adopted International Financial Reporting Standards (“IFRS”). This MD&A should be read in conjunction with the unaudited condensed consolidated financial statements and accompanying notes for the three and nine months ended September 30, 2011, and 2010. In 2010, the Canadian Institute of Chartered Accountants Handbook was revised to incorporate IFRS and require publicly accountable companies to apply such standards effective January 1, 2011. The Company has commenced reporting on this basis. The term “Canadian GAAP” refers to Canadian GAAP before the adoption of IFRS. The reporting currency is the Canadian dollar unless otherwise stated.

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

Boe Presentation – Production information is commonly reported in units of barrel of oil equivalent ("boe"). For purposes of computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet to one barrel of oil (6:1). This conversion ratio of 6:1 is based on an energy 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 common shares on a five for one basis effective on the close of business June 4, 2010. The effect of the consolidation was to reduce to one-fifth the number of common shares, warrants, stock options and stock unit awards outstanding. The number of shares into which the preferred shares are convertible were also reduced to one-fifth. In addition, the conversion price of the preferred shares, the weighted average exercise price and fair value per options, warrants and stock unit awards have been adjusted to five times the pre-consolidation prices. All share and per share amounts included in this MD&A have been adjusted retroactively for the consolidation.

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

·	business strategy, plans and priorities;

·	expected sources of funding for the capital program;

·	future costs, expenses and royalty rates and development, exploration and other expenses;

·	expected volume and product mix of the Company's oil and gas production;

·	future oil and gas prices and interest rates in respect of the Company's commodity risk management programs;

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

·	the Company's tax pools.

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

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

·	risks and uncertainties involving geology of oil and gas deposits;

·	uncertainty related to production, marketing and transportation;

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·	availability of experienced service industry personnel and equipment;

·	availability of qualified personnel;

·	the uncertainty of reserves and resources estimates, reserves life and underlying reservoir risk;

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

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

·	delays due to adverse weather conditions;

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

·	the outcome and effects of any future acquisitions and dispositions;

·	health, safety and environmental risks;

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

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

·	risks associated with competition from other producers;

·	changes in general economic and business conditions; and

·	the possibility that government policies or laws may change or government approvals may be delayed or withheld.

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

Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is presented. The Company assumes no obligation to update forward-looking information should circumstances or management’s estimates or opinions change, except as required by law.

Statements contained in this document relating to estimates, results, events and expectations are forward-looking statements within the meaning of Section 27A of the United States Securities Act of 1933, as amended and Section 21E of the United States Securities Exchange Act of 1934, as amended. These forward-looking statements involve known and unknown risks, uncertainties, scheduling, re-scheduling and other factors which may cause the actual results, performance, estimates, projections, resource potential and/or reserves, interpretations, prognoses, schedules or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such statements. Such factors include, among others, those described in the Company’s’ annual reports on Form 40-F or Form 20-F on file with the U.S. Securities and Exchange Commission.

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Business Overview and Strategy

The Company is a Calgary, Alberta; Canada based energy company engaged in the exploration for and production of oil and natural gas. The Company’s operations are located in Western Canada and offshore North Africa. On June 22, 2011, the Company completed the sale of its offshore operations in the Republic of Trinidad and Tobago (“Trinidad and Tobago”). The Trinidad and Tobago operations have been classified as discontinued operations in accordance with IFRS. In February 2011, the Company sold its interest in Liberty Natural Gas LLC (“Liberty”), a wholly owned subsidiary of the Company which had been involved in the development of a proposed liquefied natural gas project (the “LNG Project”) in U.S. federal waters offshore the state of New Jersey. The dispositions of its Trinidad and Tobago operations and the LNG Project have allowed the Company to effectively recapitalize its balance sheet in order to focus its resources towards development of existing assets in Western Canada.

The Company derives all of its production and cash flow from operations in Western Canada. The Company’s Western Canadian oil and gas assets are primarily high working interest properties that are geographically concentrated in southern and west-central Alberta, the most significant being the Company’s southern Alberta cash generating unit (“CGU”) (or Greater Drumheller, Alberta area), which accounts for approximately 78% of the Company’s production. The balance of production largely comes from the Kaybob/Windfall and Boundary Lake/Eaglesham areas in west-central Alberta, with minor production in north-eastern British Columbia. The Company holds a Western Canadian land position of 429,507 gross (310,184 net) acres.

With success in recent lease sales adding 10 net sections (6,400 acres) in the core Waskahigan and Ante Creek North areas, Sonde owns 71,136 gross (66,689 net) high potential acres in the rapidly expanding Duvernay play. Recent high bids in the immediate vicinity of Sonde leases ranged from $1,500 - $6,500 per acre, demonstrating the enormous potential industry competitors see in the area. Sonde is actively working to permit its inaugural drilling program consisting of four to six horizontal wells, anticipating commencement of drilling in the second or third quarter of 2012.

In addition to the Duvernay, Sonde has 38,453 gross (38,453 net) acres of Montney rights at Waskahigan and Ante Creek North, in the vicinity of recently-announced high-rate horizontals drilled by RMP Energy Ltd. and Cequence Energy Ltd. Sonde has been engaged in joint venture discussions with several industry and financial partners to provide financial leverage and risk-mitigation in the early phases of these plays.

In June, July and August, Sonde drilled and cased three horizontal development wells in its Mannville “I” oil pool at Drumheller in Section 29-19W4. The early production results of these wells were previously announced. Based on the belief that this inaugural program indicates economic results can be achieved for the larger Mannville “I” pool infill program, Sonde is in the process of permitting multiple drilling pads for 2012, expecting to drill four infill wells per pad. In addition, Sonde is permitting expansion of gas and oil pipelines in the pool and planning to begin a waterflood program in early 2012.

In September and October, Sonde drilled and cased the 16-20-29-14W4 horizontal (Wildunn Banff Oil Pool) and 16-28-59-15W5 horizontal (Windfall Gething Gas Pool) infill wells, and spudded the 13-17-31-17W4 horizontal (Michichi Detrital Oil Pool) infill. The Company is waiting on completion of these proof of concept wells and anticipate that all three will be in production sometime late in the fourth quarter.

Concentrating on liquids-rich opportunities has allowed the Company to decrease its gas / liquid ratio to approximately 72% gas in the three months ending September 30, 2011, as compared to approximately 76% gas in the same quarter last year.

On October 5, 2011, Sonde lifted the force majeure declaration on the Joint Oil Block, Exploration and Production Sharing Agreement (“EPSA”) designated area, or “Joint Oil Block”, Offshore Tunisia/Libya and has resumed discussion with Joint Exploration, Production, and Petroleum Services Company, or “Joint Oil”, on the development of the Block. The Company is currently taking bids to conduct the obligatory 3D seismic to appraise the Zarat discovery and assess additional exploration leads. It is also working with Ryder Scott (independent reservoir engineers) to finalize a Recoverable Contingent Resource report for the previously announced Zarat discovery. Sonde has initiated planning for this very large development and continue to evaluate exploration in the vicinity of the Zarat well.

Sonde continues to seek a one year exploration extension to fulfill its three exploration well drilling obligations, and the establishment and granting of a production license around Zarat. Joint Oil Block commitments will require Sonde to raise equity or other external financing. Sonde’s current cash flow from Western Canada is insufficient to meet these commitments.

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

·	Developing the Western Canada asset base to increase average daily production, along with replacement of producing reserves on an economic and cost effective basis through exploitation, full-cycle exploration and strategic acquisition;

·	Currently evaluating its entire acreage position in anticipation of an aggressive oil and liquids oriented, multi-year drilling program;

·	Establishing organic growth through repeatable drilling programs;

·	Providing shareholders access to high-leverage oil-oriented growth in Western Canada by annually purchasing a significant number of lease acreage in emerging “oil-resource” plays such as the Kaybob-area Duvernay; and

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·	Preserving and monetizing the Company's assets in North Africa while exploring options now that force majeure has concluded.

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, availability of experienced service industry personnel and equipment, capital spending allocations, the ability to attract equity investment, hiring and retaining qualified personnel and managing political and government risk, particularly with respect to its interests in North Africa.

Operating netback and cash flow from (used for) operations

	($ thousands)									($ per boe)
Three months ended September 30, 2011	2011			2010			% change			2011			2010			% change
Revenue
Petroleum and natural gas sales		10,279			8,248			25			37.93			33.02			15
Realized gain on financial instruments		294			999			(71	)		1.08			4.00			(73	)
Transportation		(271	)		(379	)		(28	)		(1.00	)		(1.52	)		(34	)
Royalties		(1,291	)		(1,021	)		26			(4.76	)		(4.09	)		16
		9,011			7,847			15			33.25			31.41			6
Operating expense		(3,521	)		(2,843	)		24			(12.99	)		(11.38	)		14
Well workover expense		(609	)		(248	)		146			(2.25	)		(0.99	)		127
Operating netback(2)		4,881			4,756			3			18.01			19.04			(5	)
Exploration		(784	)		(336	)		133			(2.89	)		(1.35	)		114
General and administrative		(2,365	)		(2,893	)		(18	)		(8.73	)		(11.58	)		(25	)
Foreign exchange loss		(1,695	)		(360	)		-			(6.25	)		(1.44	)		-
Interest and other income		27			131			(79	)		0.10			0.52			(81	)
Interest		(266	)		(222	)		20			(0.98	)		(0.89	)		10
Bad debt recovery		121			48			-			0.45			0.19			-
Asset retirement expenditures		(24	)		-			-			(0.09	)		-			-
Part VI.1 tax on preferred share dividends		(17	)		(38	)		(55	)		(0.06	)		(0.15	)		(60	)
Cash flow from (used for) operations(1,2)		(122	)		1,086			(111	)		(0.44	)		4.34			(110	)
Changes in non-cash working capital		(4,641	)		(1,214	)		(282	)		(17.12	)		(4.86	)		(252	)
Cash from operating activities (1)		(4,763	)		(128	)		-			(17.56	)		(0.52	)		-

(1) Table includes both continuing and discontinued operations.

(2) Non-IFRS measure.

For the three months ended September 30, 2011, cash flow used for operations was $0.1 million compared to cash flow from operations of $1.1 million for the same period in 2010. This was a result of a significant realized foreign exchange loss associated with foreign payables and increased exploration costs associated with Western Canada drilling. Exchange rates increased from $1 USD = $0.96 CAD at June 30, 2011 to $1 USD = $1.05 CAD at September 30, 2011. Exploration costs included impairment of $0.6 million on an exploration well drilling in the third quarter. These items more than offset an increase in operating netback and a decrease in general and administrative expenses. The higher operating netback in 2011 was primarily due to increased production volumes and realized prices on oil and natural gas liquids, partially offset by increased fixed operating costs to add support staff for future production growth. The decrease in non-cash working capital was primarily due to a reduction in accounts payable and accrued liabilities from the quarter ended June 30, 2011.

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	($ thousands)									($ per boe)
Nine months ended September 30, 2011	2011			2010			% change			2011			2010			% change
Revenue
Petroleum and natural gas sales		29,255			27,142			8			38.86			35.57			9
Realized gain on financial instruments		480			2,132			(77	)		0.64			2.79			(77	)
Transportation		(787	)		(989	)		(20	)		(1.05	)		(1.30	)		(19	)
Royalties		(3,441	)		(4,155	)		(17	)		(4.57	)		(5.45	)		(16	)
		25,507			24,130			6			33.88			31.61			7
Operating expense		(9,627	)		(8,310	)		16			(12.79	)		(10.89	)		17
Well workover expense		(1,412	)		(348	)		306			(1.88	)		(0.46	)		309
Operating netback(2)		14,468			15,472			(6	)		19.21			20.26			(5	)
Exploration		(1,154	)		(535	)		116			(1.53	)		(0.70	)		119
General and administrative		(8,197	)		(8,603	)		(5	)		(10.89	)		(11.27	)		(3	)
Foreign exchange gains		(343	)		221			(255	)		(0.46	)		0.29			(259	)
Interest and other income		86			411			(79	)		0.11			0.54			(80	)
Interest		(1,850	)		(773	)		139			(2.46	)		(1.01	)		144
Bad debt recovery		123			(867	)		-			0.16			(1.14	)		-
Asset retirement expenditures		(870	)		(35	)		-			(1.16	)		(0.05	)		-
Part VI.1 tax on preferred share dividends		(137	)		(424	)		(68	)		(0.18	)		(0.56	)		-
Cash flow from operations(1,2)		2,126			4,867			(56	)		2.80			6.36			(56	)
Changes in non-cash working capital		(3,552	)		(6,199	)		43			(4.72	)		(8.12	)		42
Cash from operating activities (1)		(1,426	)		(1,332	)		(7	)		(1.92	)		(1.76	)		(9	)

(1) Table includes both continuing and discontinued operations.

(2) Non-IFRS measure.

For the nine months ended September 30, 2011, cash flow from operations was $2.1 million compared to $4.9 million for the same period in 2010. This was a result of higher interest payments associated with short term debt, increased asset retirement expenditures, increased exploration costs and a lower operating netback. The lower operating netback in 2011 was primarily due to lower realized gain on financial instruments relative to a hedging contract in 2010. The lower operating netback was a result of increased fixed operating costs and higher workover activity, partially offset by a decrease in royalties.

Production

	Three months ended September 30				Nine months ended September 30
	2011		2010		2011		2010
Natural gas (mcf/d)		12,673		12,417		12,188		13,048
Crude oil (bbls/d)		631		496		522		472
Natural gas liquids (bbls/d)		203		150		205		149
Total production (boe/d) (6:1)		2,946		2,716		2,757		2,796

For the three months ended September 30, 2011, production averaged 2,946 boe/d and for the nine months ended September 30, 2011, production averaged 2,757 boe/d. The nine month decrease from 2010 is mainly due maintenance issues at SemCAM’s Kaybob South #3 gas plant causing reduced gas revenue for March 2011, and severe weather conditions in the month of May 2011 that prevented access to shut-in wells. The three month increase from 2010 and the overall increase in oil production is due to successful drilling activity associated with the new wells at Drumheller. Natural gas liquid production increased primarily as a result of successful workover activity.

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Petroleum and natural gas sales

	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
($ thousands, except where otherwise noted) Petroleum and natural gas sales
Natural gas		4,280			4,325			12,974			15,514
Crude oil		4,753			3,184			12,475			9,286
Natural gas liquids		1,246			739			3,806			2,342
Transportation		(271	)		(379	)		(787	)		(989	)
Royalties		(1,291	)		(1,021	)		(3,441	)		(4,155	)
Realized gain on commodity derivatives		294			999			480			2,132
Total		9,011			7,847			25,507			24,130
Average sales price
Natural gas ($/mcf)		3.92			4.66			4.08			4.95
Crude oil ($/bbl)		81.90			69.77			86.88			72.13
Natural gas liquids ($/bbl)		66.83			53.72			68.02			57.66
Average sales price ($/boe)		39.01			37.02			39.50			38.36

For the three months ended September 30, 2011, petroleum and natural gas sales, net of transportation and royalties was $9.0 million, consisting of $4.3 million in natural gas, $0.3 million in realized gains on commodity derivatives, $4.8 million in crude oil and $1.2 million in natural gas liquids sales, less $1.3 million of royalties and $0.3 million of transportation costs. The Company realized an average sales price of $39.01 per boe during the three months ended September 30, 2011 compared to $37.02 per boe for the same period in 2010, exclusive of royalties and transportation.

For the nine months ended September 30, 2011, petroleum and natural gas sales, net of transportation and royalties was $25.5 million, consisting of $13.0 million in natural gas, $0.5 million in realized gains on commodity derivatives, $12.5 million in crude oil and $3.8 million in natural gas liquids sales, less $3.4 million of royalties and $0.8 million of transportation costs. The Company realized an average sales price of $39.50 per boe during the nine months ended September 30, 2011 compared to $38.36 per boe for the same period in 2010, exclusive of royalties and transportation.

Royalties

	Three months ended September 30				Nine months ended September 30
	2011		2010		2011		2010
($ thousands, except where otherwise noted) Royalties
Crown		988		412		2,859		2,974
Freehold and overriding		303		609		582		1,181
Total		1,291		1,021		3,441		4,155
Royalties per boe ($)		4.76		4.09		4.57		5.45
Average royalty rate (%)		12.5		11.5		11.9		14.7

The Company pays royalties to provincial governments, freehold landowners and overriding royalty owners. Royalties are calculated and paid based on petroleum and natural gas sales net of transportation. Crown royalties on Alberta natural gas production are calculated based on the Alberta Reference Price, which may vary from the Company’s realized corporate price, impacting the average royalty rate. In addition, various items impact the average royalty rate paid, such as cost of service credits and other royalty credit programs. Royalties on horizontal gas wells drilled in Alberta in 2011 and beyond generally bear royalties at a maximum of 5% for 18 months or until cumulative production reaches 50,000 boe. Horizontal oil wells generally bear royalties at a maximum of 5% for 18 to 48 months

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until cumulative production reaches 50,000 boe to 100,000 boe, depending on well depth. The Company anticipates that production from wells drilled in 2011 would qualify for these low royalty rates.

Natural gas and liquids royalties for the three months ended September 30, 2011 were $1.3 million or 12.5% of total petroleum and natural gas sales compared to 11.5% in 2010. Royalties for nine months ended September 30, 2011 were $3.4 million or 11.9% of total petroleum and natural gas sales compared to 14.7% in 2010. Freehold and gross overriding royalties decreased in 2011 due to reduced production in the Eaglesham /Boundary Lake areas of Alberta. Crown royalties increased in the three months ended September 30, 2011, due to production from the newly drilled Drumheller oil wells but were offset over the nine months by a prior period recovery of crown royalties received in the first quarter of 2011.

Operating and well workover expense

Combined operating and well workover expenses for the three months ended September 30, 2011 were $4.1 million or $15.24 per boe, compared to $3.1 million or $12.37 per boe for the same period in 2010. Combined expenses for the nine months ended September 30, 2011 were $11.0 million or $14.67 per boe, compared to $8.7 million or $11.35 per boe for the same period in 2010. The increase from 2010 to 2011 is attributable to additional workovers performed, higher fixed labor costs from increased field operating staff and higher processing charges due to rate increases.

Capital expenditures

	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
($ thousands) Acquisitions		6,088			--			6,088			660
Exploration and evaluation		(1,372	)		3,873			8,974			6,764
Drilling and completions		13,453			1,244			20,657			5,439
Plants, facilities and pipelines		1,470			1,077			3,657			2,258
Land and lease		385			1,543			2,013			2,052
Capital well workovers		175			--			308			--
Capitalized general and administrative expenses		655			3,698			2,413			11,758
Capital expenditures		20,854			11,435			44,110			28,931
Trinidad Disposition		(283	)		--			(87,908	)		--
Exploration and evaluation impairment, charged to exploration expense		(800	)		(301	)		(1,158	)		(535	)
Net capital expenditures		19,771			11,134			(44,956	)		28,396

	2011			2010		2011			2010
($ thousands) Continuing operations
Canada		21,192			3,916		31,907			10,835
North Africa		(1,209	)		4,368		9,747			6,761
Corporate Assets		96			43		733			86
		20,079			8,327		42,387			17,682
Discontinued operations
Trinidad and Tobago		(308	)		307		(87,343	)		1,522
United States (LNG Project)		--			2,500		--			9,191
		(308	)		2,807		(87,343	)		10,714
Net capital expenditures		19,771			11,134		(44,956	)		28,396

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Continuing operations

Western Canada

In the nine months ended September 30, 2011, three wells were drilled in Western Canada in the Drumheller Mannville “I” pool. Sonde 3-4 was completed and began producing in June at a total completed cost of $5.2 million, approximately $1.8 million over Authority For Expenditure (“AFE”) due entirely to cost-overruns associated with the hydraulic fracture program. Sonde 3-5 was completed in late July with a total completed cost of $3.7 million, within 10% of AFE. Sonde 14-14 was completed in September with a total completed cost of $3.9 million, within 15% of AFE.

The Company also drilled the16-20 Coyote horizontal development well targeting the Banff formation in the Drumheller region and the 16-28 Windfall well targeting the Gething pool in Central Alberta, both of which are awaiting completion in the fourth quarter. One exploratory horizontal well was drilled in July in the Michichi region targeting the Ellerslie formation. The horizontal portion of this well did not reach the projected zone and was abandoned and impaired through exploration expense; however, the vertical portion of the well did access a payzone and will be completed at a later date.

The Company also continued its well re-activation program concentrated on an extensive portfolio of suspended wells. The Company performed 14 gross (12.7 net) new-zone re-entries and 36 gross (33.5 net) work-overs.

On September 23, 2011, the Company completed a property acquisition consisting of oil and gas assets located in the Drumheller region of Alberta. The net purchase price paid by Sonde was $6.1 million consisting of $6.3 million of cash and $0.2 million accrued as owing from the vendor for future adjustments. The acquired properties are producing approximately 200 boe/d and the Company has identified numerous opportunities to bring suspended wells back into production.

Consideration	(CDN$ thousands)
Cash paid		6,337
Accrued adjustment receivable		(249	)
Net consideration		6,088

Net assets acquired
Property, plant and equipment		11,917
Decommissioning provisions		(5,829	)
Net assets		6,088

North Africa

During the nine months ended September 30, 2011, the Company incurred $9.7 million in North Africa on costs related to the drilling and testing of the successful Zarat-1 North appraisal well. In three months ended September 30, 2011 the $1.2 net recovery of expenses primarily relates to a contractor settlement on well-testing costs; the settled costs had been accrued for in previous quarters at the invoiced amounts. The Company commenced drilling in November 2010 and completed drilling and production testing of the appraisal well on the Zarat discovery extension in January 2011. The Company has abandoned the appraisal well in a manner allowing it to be utilized for future development purposes. The Company is currently evaluating the reservoir characteristics and development options.

Discontinued operations

Trinidad and Tobago

During the nine months ended September 30, 2011, the Company incurred $0.6 million related to continued joint venture transactions with the operator of Block 5(c). On December 22, 2010 the Company entered into an agreement to sell its remaining 25% interest in Block 5(c) and the Mayaro-Guayaguayare block (“MG Block”) exploration and production license for an aggregate purchase price of US$87.5 million plus interest on the outstanding balance prior to closing. The transaction closed on June 22, 2011 for gross proceeds of US$78.1 million and the assumption of the Company’s performance guarantee provided for the MG Block of US$12.0 million. The purchaser guaranteed the performance guarantee, resulting in a receivable with the right to offset the Company’s obligation regarding the MG Block. The Company has recorded this as a receivable offsetting the MG block performance guarantee liability. The

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Trinidad and Tobago assets and the LNG Project were designated as held for sale at December 31, 2010, meaning general and administrative costs incurred in 2011 no longer met the criteria for capitalization.

Proceeds from disposition	(CDN$ thousands)
Cash received		56,877
Debenture retired		19,898
MG Block Performance Guarantee Assumed By Purchaser		11,716
Transaction costs		(583	)
Net proceeds		87,908

Net assets disposed at carrying value
Exploration and evaluation assets		79,665
Asset retirement obligation		(3,040	)
Net assets		76,625
Gross gain on disposition		11,283
Realized foreign currency translation reserve		(5,976	)
Net gain on disposition		5,307

Depletion and depreciation

For the three months ended September 30, 2011 depletion and depreciation was $4.4 million or $16.27 per boe compared to $3.9 million or $15.50 per boe for the same period in 2010. The calculation of depletion and depreciation included an estimated $21.5 million (September 30, 2010 - $5.9 million) for future development capital associated with proved plus probable undeveloped reserves and excluded $64.5 million (September 30, 2010 – $21.0 million) related to exploration and evaluation assets. For the nine months ended September 30, 2011 depletion and depreciation was $10.7 million or $14.15 per boe compared to $12.6 million or $16.53 per boe for the same period in 2010. The variance for the nine months is caused by a higher reserve base in 2011 as a result of reserve additions from 2010 and the 2011 acquisition, higher estimated future development costs as a result of a revised development plan, and a lower depletion base due to asset impairments in the second and fourth quarters of 2010.

General and administrative expenses

	Three months ended September 30						Nine months ended September 30
	2011			2010			2011			2010
($ thousands, except where otherwise noted) Continuing operations
Gross general and administrative expense		2,958			4,571			9,105			10,697
Capitalized general and administrative expense		(655	)		(1,678	)		(2,413	)		(2,094	)
		2,303			2,893			6,692			8,603
Discontinued operations
Gross general and administrative expense		62			2,019			1,505			9,664
Capitalized general and administrative expense		--			(2,019	)		--			(9,664	)
		62			--			1,505			--
Total net general and administrative expense		2,365			2,893			8,197			8,603
General and administrative expense ($/boe)		8.73			11.58			10.89			11.27

Continuing operations

For the three months ended September 30, 2011, gross general and administrative (“G&A”) expenses for continuing operations decreased to $3.0 million from $4.6 million for the same period in 2010. Gross G&A for continuing operations consists of $0.2 million (2010 – $0.8 million) relating to North Africa and $2.8 million (2010 – $3.8 million) related to Western Canada administration and corporate head office. The decrease is due to cost management in 2011 and one-time charges incurred in 2010 related to restructuring, severance and litigation.

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For the nine months ended September 30, 2011, gross G&A expenses for continuing operations decreased to $9.1 million from $10.7 million in 2010. Gross G&A for continuing operations consists of $1.4 million (2010 – $1.1 million) relating to North Africa and $7.7 million (2010 – $9.6 million) related to Western Canada administration and corporate head office. The decrease is due to cost management in 2011 and one-time charges incurred in 2010 related to restructuring, severance and litigation.

Discontinued operations

For the three and nine month periods ended September 30, 2011, gross G&A expenses from discontinued operations decreased to $0.1 million and $1.5 million from $2.0 million and $9.7 million respectively in 2010. Costs declined due to the sale of the Trinidad and Tobago assets on June 22, 2011 and the sale of the LNG Project. On February 22, 2011, the Company completed the sale of the LNG Project to West Face Capital Inc. (“West Face”). The sale of the LNG Project was initiated with West Face in keeping with the Company’s strategy of focusing on the development of its interests in Western Canada and North Africa. Pursuant to the sale, the Company received US$1.0 million for reimbursable costs between January 1, 2011 and February 22, 2011, which was recorded as an offset to G&A expenses from discontinued operations. The Company is entitled to receive deferred cash consideration of US$12.5 million payable upon West Face’s first successful gas delivery. No amounts have been recorded in the consolidated financial statements related to this contingent consideration. In 2010, net G&A expenses from discontinued operations were lower due the Trinidad and Tobago assets and the LNG Project meeting the criteria for capitalization under IFRS.

Stock based compensation

	Three months ended September 30					Nine months ended September 30
	2011			2010		2011		2010
Stock option expense		743			382		3,401		1,380
Stock unit award expense		72			134		852		189
Restricted share unit expense		(11	)		--		350		--
Stock based compensation		804			516		4,603		1,569

During the three months ended September 30, 2011, the Company incurred stock based compensation expenses of $0.8 million compared to $0.5 million in 2010. The increase is primarily due to higher stock option expense as a result of issuances in 2011, partially offset by a decrease in the carrying value of the liability associated with the Company’s Restricted Share Unit (“RSU”) program. The RSU Plan (the "Plan”) became effective on March 24, 2011 to attract and retain experienced personnel with incentive compensation tied to shareholder return. Under the Plan, each holder of RSUs will be entitled to, in respect of each RSU, a cash amount equal to the fair market value of one common share in the capital of the Company on such vesting date, with the vesting subject to a minimum floor share price.

Prior to the conversion to IFRS, stock based compensation related to stock options was expensed on a straight-line basis through the date of full vesting and did not incorporate a forfeiture multiple. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting awards and estimate a forfeiture rate.

As at September 30, 2011 the Company had issued 1.5 million (December 31, 2010 – 0.7 million) stock unit awards to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the applicable vesting date. The stock units have time and share based performance vesting terms which vary depending on whether the holder is an executive officer or director. If subsequent to the grant date, the shareholders of the Company approve an equity compensation plan under which the stock units may be paid with common shares of the Company, then the Board may determine that the stock units may be paid in cash or common shares. As of September 30, 2011, the Company recorded a liability of $1.4 million to recognize the fair value of the vested stock units (December 31, 2010 - $0.5 million).

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Liquidity and capital resources

	September 30			December 31
	2011			2010
($ thousands) Cash and cash equivalents		30,672			2,649
Accounts receivable		8,059			7,147
Derivative financial assets		306			--
Prepaid expenses and deposits		1,430			1,686
Assets of discontinued operations		--			100,692
Accounts payable and accrued liabilities		(12,333	)		(18,126	)
Stock based compensation liability		(1,732	)		(530	)
Provisions		(13,126	)		(12,692	)
Derivative financial liabilities		(1,015	)		(5,099	)
Short term debt		(15,781	)		(35,048	)
Liabilities of discontinued operations		--			(16,650	)
Working capital surplus (deficit)		(3,520	)		24,029

As at September 30, 2011, the Company had a working capital deficit of $3.5 million (December 31, 2010 – $24.0 million surplus) and had issued two letters of credit for $0.1 million (December 31, 2010 – letters of credit of $0.1 million, short term debt of $20.2 million) against the $40.0 million (December 31, 2010 - $40.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75% as at September 30, 2011 and at December 31, 2010. Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company. Credit Facility A has covenants, as defined in the Company’s credit agreement, that require the Company to maintain its working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative expenditures in excess of $7.0 million per year and all foreign capital expenditures are not funded from Credit Facility A nor domestic cash flow while Credit Facility A is outstanding.

On February 22, 2011, the Company obtained an additional $20.0 million development demand loan (“Credit Facility B”) at a variable interest rate of 50 basis points above the variable interest rate on Credit Facility A. Credit Facility B was to be used to assist in the acquisition of producing petroleum and natural gas reserves and/or development of proved producing/undeveloped petroleum and natural gas reserves. On August 16, 2011, the Company repaid the $6.3 million balance on the loan. On October 12, 2011, the Company cancelled this facility in order to reduce standby fees. Subject to availability and review, Credit Facility B can be reopened should the Company require access to additional debt financing.

As at December 31, 2010, the Company was in violation of one of its debt covenants. This covenant placed a ceiling on foreign expenditures that was exceeded pending the approval of the Trinidad and Tobago asset sale. The Company sought and received a waiver from its lender on this violation and it does not impact the Company’s borrowing ability. As at September 30, 2011 the Company was in compliance with all of its debt covenants.

The Company is subject to the next semi-annual review of its credit facilities on or before April 30, 2012.

On February 3, 2010, the Company restructured the terms of the Series A, 5.0% US Cumulative Redeemable Convertible Preferred Shares (the “Series A Shares”). Pursuant to the terms of the restructuring, the Series A Shares were exchanged on a share for share basis for 150,000 First Preferred Shares, Series B shares (the “Series B Shares”) pursuant to which the redemption date was extended from December 31, 2010 to December 31, 2011, the conversion price was reduced from US$12.50 to US$3.00 and the conversion of 150,000 preferred shares into common shares was increased from 1,200,000 to 5,000,000. The terms of the dividend payment under the Series B Shares remain unchanged from the Series A Shares whereby the Company can elect to pay the quarterly dividend by way of issuance of common shares at market, based on a 5.75% annualized dividend rate in lieu of the 5.0% annualized cash dividend rate. The dividend rate was increased by 1/30 of 1% per day restricted to the 150 day period after December 31, 2010 and thereafter reverted to 5.0%. In addition, the Company granted 500,000 common share purchase warrants exercisable at a price of US$3.25 for each common share expiring December 31, 2011. The Series B Shares are redeemable by the Company on or after December 31, 2011 and retractable by the holders of the Series B Shares on December 31, 2011. The Company can force conversion of the Series B Shares at any time 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

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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 anticipates redeeming the Series B Shares in accordance with its terms.

At September 30, 2011, the Company had $30.7 million in cash and cash equivalents (December 31, 2010 - $2.6 million) and none was classified as restricted cash (December 31, 2010 – $19.9 million). The Company generally relies on a combination of cash flow from operations and credit facility to fund its capital requirements and to provide liquidity for domestic and international operations, augmented in 2011 by the proceeds from the sale of Trinidad and Tobago assets.

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

Contingencies and commitments

MG Block Trinidad and Tobago

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

The Company’s agreement to sell its remaining interest in Block 5(c) and the MG Block includes the assumption of the performance guarantee. Upon closing the sale on June 22, 2011 the purchaser assumed the performance guarantee for the MG Block. While the rights to the MG Block were not transferred to the purchaser, pending Trinidad and Tobago’s approval of the assignment of such rights, this guarantee provides a receivable with the right to offset the US$12.0 million performance guarantee in discontinued operations. Should the Company be required to pay the performance security amount in order to relinquish the MG Block, the purchaser will reimburse the Company for any amounts owing up to US$12.0 million. The Company expects that the purchaser’s guarantee will offset any further liability with respect to the MG Block. As of September 30, 2011, the Company had ceased all operations in Trinidad and exited the country but the assignment of the MG Block has yet to be approved.

North Africa

Joint Oil block

On August 27, 2008, the Company entered into the EPSA with a Tunisian company, Joint Oil. Joint Oil is owned equally by the governments of Tunisia and Libya. The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, the Company is the operator. Under the EPSA, the minimum work program for the first phase (four years) of the seven year exploration period includes the Zarat North-1 appraisal well, three exploration wells and 500 square 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. On January 11, 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North–1 well. The well has been temporarily abandoned in a manner allowing it to be utilized for future development purposes while the Company evaluates reservoir characteristics and development options on a field development.

Political issues and Libyan sanctions

The governments of Tunisia and Libya are in political turmoil. During January 2011, protests in Tunisia led to the overthrow of the government. The Company safely evacuated its personnel and the rig and equipment without incident. While relative calm has been restored, uncertainty remains over the future direction of the country. Similarly, widespread protests over the government in Libya have occurred with the opposition forces assuming power. On February 26, 2011, the United Nations imposed sanctions on the Libyan government followed by consequent actions of the Canadian Government pursuant to the Special Economics Measures Act (Canada) (the “Libyan Sanctions”). While this turmoil has not had a direct impact on the Company’s

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Joint Oil Block evaluation of the Zarat North-1 results and planning of future activities, it affected the Company in various ways, including the functioning of Joint Oil, the pace of future development plans and activities, the ability to secure supplies and personnel, the ability to make payments to Joint Oil and the ability to attract joint venture partners or financing.

The imposition of sanctions and the state of war are unforeseen circumstances beyond the control of the Company, which rendered the performance of Sonde’s obligations impossible and thus constituted a condition of force majeure. As a result, the Company made a formal Force Majeure declaration to Joint Oil for the Joint Oil Block on June 7, 2011. This declaration effectively put the term of the EPSA on hold, without penalty, pending the resolution of political sanctions and instability in Libya. On August 31, 2011 the Canadian Government repealed its unilateral sanctions against Libya, and further amended the Regulations Implementing the United Nations Resolutions on Libya on September 22, 2011, following the adoption of Resolution 2009 (2011) by the United Nations Security Council (“UNSC”). After careful review of these rulings, and in consultation with the Canadian Foreign Affairs Ministry, Sonde lifted the Force Majeure declaration and is working with Joint Oil personnel to resume normal operations on the Joint Oil Block.

Swap agreement

At the time it entered into the North Africa EPSA, the Company also signed a "Swap Agreement" awarding an overriding royalty interest and optional participating interest to Joint Oil, in the Company's "Mariner" Block, offshore Nova Scotia, Canada. No well has been drilled on the Mariner Block and Joint Oil has the right to put back the overriding royalty to the Company for US$12.5 million. On December 31, 2010, the Mariner Block license lapsed resulting in the Company no longer holding any interest in offshore Nova Scotia, Canada. As a result, Joint Oil has notified the Company that it is exercising its put rights. The Company is in discussions with Joint Oil to obtain information to confirm that the Mariner Swap payment does not violate remaining sanctions and that the EPSA remains in full force and effect. Pending this discussion, the Company may post a letter of credit or escrow funds to secure the payment to obtain information to confirm that the Mariner Swap payment.

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 alleged 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 purported 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 Defendants’ 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. Subsequently, the Stipulation was finalized and approved by the U.S. and Canadian courts. Notice has been given to the classes of possible claimants, and the parties anticipate seeking final court approval in late 2011 subject to the conditions in the Stipulation having been met.

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

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

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Off-balance sheet arrangements

The Company has no off-balance sheet arrangements.

Share capital

As at November 9, 2011, the Company had approximately 62.3 million common shares, 3.0 million stock options, 0.2 million Series B Preferred Shares and 0.5 million common share purchase warrants issued and outstanding.

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 following commodity price risk contracts were in place at the date hereof.

Term	Contract	Volume (GJ/d)		Fixed Price ($/GJ)		Realized gain

March 1, 2011 – December 31, 2011	Swap		5,000	$	4.11	$	585

In exchange for receiving the fixed price on the February 14, 2011 Swap Agreement, the Company issued the following call option:

Term	Contract	Volume (Bbls/d)		Fixed Price (US$/Bbl)		Realized loss

March 1, 2011 – December 31, 2012	Call option		250	$	100.00	$	(105	)

Sensitivities

The following sensitivity analysis is provided to demonstrate the impact of changes in commodity prices on third quarter 2011 petroleum and natural gas sales and is based on the balances disclosed in this MD&A and the consolidated financial statements for the three months ended September 30, 2011:

($ thousands)	Petroleum and Natural Gas Sales(1)
Change in average sales price for natural gas by $1.00/mcf		1,166
Change in the average sales price for crude oil and natural gas liquids by $1.00/bbl		59
Change in natural gas production by 1 mmcf/d (2)		361
Change in crude oil and natural gas liquids production by 100 bbls/d (2)		754

(1)	Reflects the change in petroleum and natural gas sales for the three months ended September 30, 2011.

(2)	Reflects the change in production multiplied by the Company’s average sales prices for the three months ended September 30, 2011.

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, 2011, and ending on September 30, 2011, 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, 2011, 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.

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Quarterly financial summary

($ thousands except per share and production amounts)

	2011 IFRS			2011 IFRS		2011 IFRS			2010 IFRS			2010 IFRS			2010 IFRS			2010 IFRS			2009 CGAAP
		Q3			Q2		Q1			Q4			Q3			Q2			Q1			Q4
Production
Natural gas (mcf/d)		12,673			11,509		12,377			14,140			12,417			13,631			13,104			14,428
Crude oil and natural gas liquids (bbl/d)		834			672		677			730			646			620			595			653
Total (boe/d)		2,946			2,584		2,740			3,087			2,716			2,892			2,779			3,058

Petroleum & natural gas sales (2)		9,011			7,747		8,749			10,002			7,847			7,682			8,601			9,370
Net income (loss) (1)		(591	)		2,781		(6,261	)		(74,528	)		(3,362	)		(19,988	)		(2,697	)		(63,903	)
Net income (loss) per share – basic(1)		(0.01	)		0.04		(0.10	)		(1.20	)		(0.05	)		(0.32	)		(0.05	)		(1.62	)
Cash flow from (used for) operations (3) (4)		(122	)		1,008		1,240			604			1,086			727			3,054			3,671
Cash flow from (used for) operations per share – basic (3) (4)		--			0.02		0.02			0.01			0.02			0.01			0.05			0.09

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

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

(3) Non-IFRS measures.

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

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

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

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

·	Fluctuations in debt levels from quarter to quarter can substantially impact the company’s net income and cash flow from operations.

Please refer to the other sections of this MD&A for the detailed discussions on changes for the three and nine months ending September 30, 2011.

Significant accounting estimates and judgments

The timely preparation of the condensed consolidated financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant estimates used in the preparation of the financial statements include, but are not limited to, those areas discussed below.

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Oil and gas reserves and resources

Certain depletion, depreciation, impairment and decommissioning and restoration charges are measured based on the Company’s estimate of oil and gas reserves and resources. The estimation of reserves and resources is an inherently complex process and involves the exercise of professional judgment. Reserves and resources have been evaluated at December 31, 2010 by independent petroleum consultants in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The reserves and resources estimates are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook.

Oil and gas reserves and resources estimates are based on a range of geological, technical and economic factors, including projected future rates of production, estimated commodity prices, engineering dates, and the timing and amount of future expenditures, all of which are subject to uncertainty. Assumptions reflect market and regulatory conditions existing at each annual reporting date, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Exploration and evaluation costs

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

Decommissioning liabilities and other provisions

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

Deferred income taxes

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

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

Impairment of assets

The allocation of assets into cash generating units (“CGU’s”) requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, shared infrastructures, and the way in which management monitors the operations.

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

Sonde Resources Corp.

Q3 2011 MD&A

Page 16

Share-based payment

Expenses recorded for share-based payments are based on the historical volatility of the Company’s share price which may not be indicative of the future volatility. Accordingly, those amounts are subject to measurement uncertainty.

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.

Sonde Resources Corp.

Q3 2011 MD&A

Page 17

Document 3

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Jack W. Schanck, the Chief Executive Officer of Sonde Resources Corp., certify the following:

1.	Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended September 30, 2011.

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 report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance 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

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

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, 2011 and ended on September 30, 2011 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.

Date: November 9, 2011

(Signed) Jack W. Schanck

Jack W. Schanck

Chief Executive Officer

Sonde Resources Corp.

Document 4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Jack W. Schanck, the Chief Executive Officer of Sonde Resources Corp., certify the following:

1.	Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended September 30, 2011.

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 report together with the other financial information included in the interim filings fairly present in all material respects the financial condition, financial performance 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

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

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, 2011 and ended on September 30, 2011 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.

Date: November 9, 2011

(Signed) Kurt A, Nelson

Kurt A. Nelson

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 9, 2011	By:	/s/ Kurt Nelson
			Name:	Kurt Nelson
			Title:	Chief Financial Officer