Edgar Filing: SONDE RESOURCES CORP.

form6k.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer

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

the Securities Exchange Act of 1934

For the month of,		November		2012
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):

Note: Regulation S-T Rule 101(b)(1) only permits the submission in paper of a Form 6-K if submitted solely to provide an attached annual report to security holders.

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):

Note: Regulation S-T Rule 101(b)(7) only permits the submission in paper of a Form 6-K if submitted to furnish a report or other document that the registrant foreign private issuer must furnish and make public under the laws of the jurisdiction in which the registrant is incorporated, domiciled or legally organized (the registrant's "home country"), or under the rules of the home country exchange on which the registrant's securities are traded, as long as the report or other document is not a press release, is not required to be and has not been distributed to the registrant's security holders, and, if discussing a material event, has already been the subject of a Form 6-K submission or other Commission filing on EDGAR.

DOCUMENTS INCLUDED AS PART OF THIS REPORT

Document		Description


1.		Interim Financial Statements for the three months ended September 30, 2012.
2.		Management's Discussion and Analysis for the three months ended September 30, 2012.
3.		Canadian Form 52-109F2 Certification of Interim Filings – CEO.
4.		Canadian Form 52-109F2 Certification of Interim Filings – CFO.

This Report on Form 6-K is incorporated by reference into the Registration Statement on Form S-8 of the Registrant, which was filed with the Securities and Exchange Commission on August 12, 2011 (File No. 333-176261).

Document 1

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(unaudited)

	September 30 2012			December 31 2011
(CDN$ thousands)
Assets
Current
Cash and cash equivalents (note 9)		24,588			3,743
Accounts receivable (note 8)		4,344			7,436
Prepaid expenses and deposits		1,287			1,528
		30,219			12,707
Long term portion of prepaid expenses and deposits		316			420
Exploration and evaluation assets (note 3)		55,389			69,015
Property, plant and equipment (note 3)		102,102			104,745
		188,026			186,887

Liabilities
Current
Accounts payable and accrued liabilities		8,374			17,655
Share based compensation liability (note 14)		604			2,448
Provisions (note 10)		--			12,730
Derivative financial liabilities (note 9)		30			781
		9,008			33,614
Decommissioning provision		27,339			26,344
		36,347			59,958
Going concern (notes 2b and 7) Contingencies and commitments (note 7) Related party transactions (note 6) Segments (note 15)

Shareholders’ Equity
Share capital		369,892			369,892
Contributed surplus		34,035			33,528
Foreign currency translation reserve		(560	)		550
Deficit		(251,688	)		(277,041	)
		151,679			126,929
		188,026			186,887

See accompanying notes to the condensed consolidated financial statements

On behalf of the Board,

(Signed) “Jack W. Schanck”		(Signed) “W. Gordon Lancaster”
Jack W. Schanck		W. Gordon Lancaster
Director and Chief Executive Officer		Director and Chair of the Audit Committee

Q3 2012 FS

Page 1

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE (LOSS) INCOME

(unaudited)

	Three months ended September 30						Nine months ended September 30
(CDN$ thousands, except per share amounts)	2012			2011			2012			2011
Revenue
Revenue, net of royalties (note 11)		5,776			8,988			18,656			25,814
Gain on commodity derivatives (notes 8, 9)		21			898			659			355
		5,797			9,886			19,315			26,169
Expenses
Operating (note 12)		3,829			4,130			12,376			11,039
Transportation		145			271			460			787
Exploration and evaluation (note 3)		196			784			22,508			1,154
General and administrative		1,300			2,303			6,610			6,692
Depletion and depreciation		2,604			4,409			8,316			10,652
Share based compensation (note 14)		(553	)		881			(392	)		3,556
Property, plant and equipment impairment (note 3)		--			--			16,241			--
Bad debt		1			(121	)		26			(123	)
Loss on settlement of decommissioning liabilities		--			24			84			799
		7,522			12,681			66,229			34,556
Operating loss		(1,725	)		(2,795	)		(46,914	)		(8,387	)

Other
Financing costs (note 4)		(260	)		(502	)		(759	)		(1,955	)
Gain (loss) on foreign exchange		(162	)		433			(446	)		(115	)
Gain on financial derivatives		--			1,930			--			4,563
Other income		74			27			146			86
Gain on disposition of exploration and evaluation assets (note 3)		--			--			73,361			--
		(348	)		1,888			72,302			2,579
(Loss) income from continuing operations before income taxes		(2,073	)		(907	)		25,388			(5,808	)
Current income taxes		--			17			35			137
(Loss) income from continuing operations		(2,073	)		(924	)		25,353			(5,945	)
Income from discontinued operations, net of tax (note 16)		--			256			--			2,921
Net (loss) income		(2,073	)		(668	)		25,353			(3,024	)
Other comprehensive income (loss)
Foreign currency translation adjustment		(1,528	)		3,598			(1,110	)		2,480
Foreign currency translation adjustment relating to assets and liabilities of discontinued operations (note 16)		--			--			--			(1,128	)
Foreign currency translation reclassified to net earnings (note 16)		--			--			--			6,365
Other comprehensive (loss) income		(1,528	)		3,598			(1,110	)		7,717
Total comprehensive (loss) income		(3,601	)		2,930			24,243			4,693

Basic and diluted income (loss) per common share from continuing operations (note 5)		($0.03	)		($0.01	)		$0.41			($0.10	)
Basic and diluted income per common share from discontinued operations (note 5)		--			--			--			$0.05
Net (loss) income per common share		($0.03	)		($0.01	)		$0.41			($0.05	)

See accompanying notes to the condensed consolidated financial statements

Q3 2012 FS

Page 2

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three months ended September 30						Nine months ended September 30
	2012			2011			2012			2011
(CDN$ thousands)
Cash provided by (used in):
Operating activities
Net (loss) income		(2,073	)		(668	)		25,353			(3,024	)
Items not involving cash:
Depletion and depreciation		2,604			4,409			8,316			10,652
Share based compensation		(553	)		881			(392	)		3,556
Exploration and evaluation		196			784			22,308			1,154
Property, plant and equipment impairment		--			--			16,241			--
Unrealized (gain) loss on commodity derivatives		(21	)		(604	)		(751	)		125
Unrealized (gain) loss on financial derivatives		--			(1,930	)		--			(4,563	)
Unrealized (gain) loss on foreign exchange		185			(898	)		74			63
Financing costs		260			502			759			2,448
Loss on settlement of decommissioning liabilities		--			24			84			799
Gain on disposition of exploration and evaluation assets		--			--			(73,361	)		--
Gain on disposition of discontinued operations		--			(318	)		--			(4,918	)
Interest paid		(104	)		(266	)		(271	)		(1,850	)
Decommissioning expenditures		--			(24	)		(151	)		(870	)
Changes in non-cash working capital (note 13)		2,461			(4,641	)		4,011			(3,552	)
		2,955			(2,749	)		2,220			20
Financing activities
Exercise of restricted share units		--			--			(150	)		--
Exercise of stock unit awards		(653	)		--			(795	)		--
Revolving credit facility repayments		--			(6,901	)		(23,400	)		(41,463	)
Revolving credit facility advances		--			--			23,400			21,343
		(653	)		(6,901	)		(945	)		(20,120	)
Investing activities
Property, plant and equipment additions		(11,013	)		(16,374	)		(21,338	)		(24,356	)
Exploration and evaluation additions		(3,705	)		1,667			(11,661	)		(13,054	)
Asset additions in discontinued operations		--			--			--			(565	)
Property acquisition		--			(6,088	)		--			(6,088	)
Proceeds on exploration and evaluation disposition (notes 3, 16)		--			283			74,979			87,908
Decrease in restricted cash		--			19,892			--			19,892
Change in non-cash working capital (note 13)		(4,125	)		(1,576	)		(22,336	)		(16,362	)
		(18,843	)		(2,196	)		19,644			47,375
(Decrease) increase in cash and cash equivalents		(16,541	)		(11,846	)		20,919			27,275
Effect of foreign exchange on cash and cash equivalents		(185	)		1,681			(74	)		748
Cash and cash equivalents, beginning of period		41,314			40,837			3,743			2,649
Cash and cash equivalents, end of period		24,588			30,672			24,588			30,672

See accompanying notes to the condensed consolidated financial statements

Q3 2012 FS

Page 3

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(unaudited)

(CDN$ thousands)	Share capital		Contributed surplus		Foreign currency translation			Deficit			Total
At December 31, 2010		369,892		30,718		(5,789	)		(236,470	)		158,351
Total comprehensive income		--		--		1,352			3,341			4,693
Foreign currency translation reserve reclassified to net earnings		--		--		6,365			(6,365	)		--
Stock option expense		--		2,354		--			--			2,354
At September 30, 2011		369,892		33,072		1,928			(239,494	)		165,398

(CDN$ thousands)	Share capital		Contributed surplus		Foreign currency translation			Deficit			Total
At December 31, 2011		369,892		33,528		550			(277,041	)		126,929
Total comprehensive income		--		--		(1,110	)		25,353			24,243
Stock option expense		--		507		--			--			507
At September 30, 2012		369,892		34,035		(560	)		(251,688	)		151,679

See accompanying notes to the condensed consolidated financial statements

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Page 4

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(unaudited)

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

1.	Reporting entity

	Sonde Resources Corp. (“Sonde” 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 February 22, 2011, the Company completed the sale of its wholly owned subsidiary Liberty Natural Gas LLC (the “LNG Project”). On June 22, 2011, the Company completed the sale of its offshore operations in the Republic of Trinidad and Tobago (“Trinidad and Tobago”). These dispositions are discussed in more detail in Note 16. The condensed consolidated financial statements (the “Financial Statements”) comprise the Company and its wholly owned subsidiaries. The Company’s shares are widely held and publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange MKT.

2.	Basis of preparation

	(a)	Statement of compliance

	The Financial Statements are prepared in accordance with International Accounting Standards 34 (“IAS 34”) Interim Financial Reporting and present the Company’s results of operations and financial position under International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”) as at September 30, 2012 and December 31, 2011 and for the three and nine month periods ended September 30, 2012 and 2011.

	The Financial Statements were approved and authorized for issue by the Board on November 9, 2012.

	(b)	Going concern

	The Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and settlement of liabilities and commitments in the normal course of business and does not reflect adjustments that would otherwise be necessary if the going concern assumption was not valid. For the nine months ended September 30, 2012, the Company had an operating loss of $46.9 million and an accumulated deficit of $251.7 million. Management believes that the going concern assumption is appropriate for the Financial Statements; however, items discussed in Note 7 – “Commitments and Contingencies”, describe significant uncertainties that cast significant doubt over the Company’s ability to continue as a going concern. If this assumption were not appropriate, adjustments to the carrying amounts of assets and liabilities, revenues and expenses and the statement of financial position classifications used may be necessary and these adjustments could be material.

	(c)	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 audited consolidated financial statements for the year ended December 31, 2011. The accounting policies have been applied consistently to all periods presented in the Financial Statements. The Financial Statements should be read in conjunction with the audited consolidated financial statements and notes thereto as at and for the year ended December 31, 2011.

	(d)	Functional and presentation currencies

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

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2.	Basis of preparation (continued)

	(e)	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.

3.	Exploration and evaluation assets and property, plant and equipment

	Nine months ended September 30, 2012									Year ended December 31, 2011
	Cost			Accum. DD&A			Carrying value			Cost			Accum. DD&A			Carrying value
Exploration and Evaluation Assets
Beginning of period		79,399			(10,384	)		69,015			58,475			(9,114	)		49,361
Additions		11,661			--			11,661			19,405			--			19,405
Dispositions		(1,618	)		--			(1,618	)		--			--			--
Transfers to PP&E		--			--			--			(43	)		--			(43	)
Impairments, to exploration expense		--			(22,308	)		(22,308	)		--			(1,270	)		(1,270	)
Change in decommissioning obligations		--			--			--			41			--			41
Foreign exchange		(1,361	)		--			(1,361	)		1,521			--			1,521
End of period		88,081			(32,692	)		55,389			79,399			(10,384	)		69,015

Property, plant and equipment
Beginning of period		212,453			(107,708	)		104,745			161,165			(58,562	)		102,603
Additions		21,338			--			21,338			37,509			--			37,509
Acquisitions		--			--			--			11,827			--			11,827
Dispositions		--			--			--			(151	)		30			(121	)
Transfers from E&E assets		--			--			--			43			--			43
Change in decommissioning obligations		576			--			576			2,060			--			2,060
Depreciation and depletion		--			(8,316	)		(8,316	)		--			(14,906	)		(14,906	)
Impairments		--			(16,241	)		(16,241	)		--			(34,270	)		(34,270	)
End of period		234,367			(132,265	)		102,102			212,453			(107,708	)		104,745

	During the three and nine months ended September 30, 2012, the Company capitalized $1.2 million and $3.4 million respectively (September 30, 2011 – $0.7 million and $2.4 million) of general and administrative expenses related to exploration and development activities.

	Exploration and evaluation assets consist of the Company’s exploration projects which are pending the determination of proved or probable reserves.

	Land expiries and impairment on Western Canada exploratory wells charged to exploration and evaluation expense during the three and nine months ended September 30, 2012, totaled $0.2 million and $1.3 million respectively (September 30, 2011 – $0.8 million and $1.2 million), respectively. As at September 30, 2012, no indicators of impairment were identified in Western Canada that would imply a further decline in exploration and evaluation asset carrying values.

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3.	Exploration and evaluation assets and property, plant and equipment (continued)

	Impairment on the Joint Oil Block offshore North Africa charged to exploration and evaluation expense during the three and six months ended June 30, 2012, totaled $21.0 million and $21.0 million respectively (June 30, 2011 – $Nil for both the three and six month periods). The factors leading to this impairment are further described in Note 7.

	Impairment on the Joint Oil Block offshore North Africa charged to exploration and evaluation expense during the three and nine months ended September 30, 2012, totaled $Nil and $21.0 million respectively (September 30, 2011 – $Nil for both the three and nine month periods). As at September 30, 2012, no indicators of impairment were identified in North Africa that would imply a further decline in exploration and evaluation asset carrying values.

	The Company evaluated the fair value of the Joint Oil Block as described below. This analysis assumed a wide range of potential future outcomes. There is a great deal of uncertainty in the estimate of production, capital and future operating cost for the future development of these assets. The key items that contribute to this uncertainty are oil and natural gas price and production volumes. A series of outcomes were modeled for each variable. The other key model variable is if the Joint Oil Block does not get developed. Factors contributing to this non-commercial variable are described in Note 7. All of these could severally influence the fair value.

	The recoverable value was determined using a third party valuation firm to estimate the fair value of $43.6 million less costs to sell of $0.4 million. The valuation was performed under the Swanson’s mean methodology utilizing probability-weighted discounted cash flows over the estimated life of the project (estimated to be 2012 – 2032). The most significant assumptions used in the determination of the fair value include:

	·	The estimated low to medium probability of finding a commercial solution to the Inert and Acid Gas Initiative can have an adverse or positive impact on this valuation; this is subject to change.

	·	The estimated start date of production under the high case scenarios was 2017. Both the base and low case scenarios were determined using delays of three to five years, respectively, in establishing production.

	·	Estimates of production rates and reserves of the unitized area including the Joint Oil Block were based on a recent contingent resource study of the Joint Oil Block. Due to the uncertainties with estimating contingent resources, these may be materially different as exploration and reservoir modeling continue and from the actual reserves ultimately discovered, if any, and the production, if any, from such discoveries.

	·	Oil prices were estimated using base case scenarios of US$80 per barrel (“bbl”) derived from future expected Brent prices less an estimated differential. The low case scenarios used US $60/bbl and the high case scenarios at US $100/bbl. Future Brent prices were compared to Brent forward contract prices available in the market, as well as historical trends for Brent pricing.

	·	Natural gas prices were estimated using base case scenarios of US$6 per million British thermal units (“mmbtu”) derived from Tunisian gas prices expected less an estimated differential. The low case scenarios used US$3/mmbtu and high case scenarios used US$9/ mmbtu. Estimates were derived by looking at historical trends of Tunisian and European gas pricing and expectations for the future.

	Given the number of quantitative and qualitative factors discussed above and in Note 7, each with substantial uncertainties, and the interdependency of factors, the Company is unable to identify the sensitivities associated with individual factors. A number of the potential scenarios result in no value for the North African assets; however, as of the report date management does not believe that this is the most likely outcome and the fair value of $43.6 million was determined to be the most probable value in the range of possible values.

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3.	Exploration and evaluation assets and property, plant and equipment (continued)

	The Company believes that the issues identified above are ongoing and is actively working towards finding appropriate solutions for these complex issues. The Company expects more clarity in the near future relating to these issues, including whether the current extension for the exploration wells to December 2013 will be maintained. Negotiations regarding additional extensions to the exploration period will occur in the fourth quarter of 2012. Additional impairments, including potentially abandoning the project, may result in the future as conditions unfold and clarity is obtained with respect to the Company’s North African operations.

	An impairment test is performed on capitalized property and equipment costs at a cash-generating unit (“CGU”) level on an annual basis and quarterly when indicators of impairment exist. There were no indicators of impairment as at September 30, 2012. During the six months ended June 30, 2012, the Company recorded an impairment of $16.2 million. For additional information relating to this impairment, please see the Company’s condensed interim financial statements for the three and six months ended June 30, 2012.

	On February 8, 2012, the Company completed the sale of 24,383 net acres of undeveloped land in the Kaybob Duvernay play in Central Alberta for cash proceeds of $75.0 million. This land was classified as evaluation and exploration assets at December 31, 2011, and had a carrying value of $1.6 million, resulting in a gain of $73.4 million. The Company’s tax pools offset the taxes associated with the gain.

4.	Short term debt and financing costs

	As at September 30, 2012, the Company had issued three letters of credit for $0.2 million (December 31, 2011 – two letters of credit for $0.1 million) against the $30.0 million (December 31, 2011 - $40.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75%. Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company.

	Credit Facility A has covenants, as defined in the Company’s credit agreement, that require the Company to maintain an adjusted working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative 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. The Company can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility. As at September 30, 2012, 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 December 31, 2012. Financing costs for the Company are as follows:

	Three months ended September 30				Nine months ended September 30
	2012		2011		2012		2011
Accretion of decommissioning provision(1)		156		165		488		488
Interest on credit facilities(1)		104		73		271		705
Interest on preferred shares		--		264		--		762
		260		502		759		1,955

(1) Amounts disclosed do not include Trinidad and Tobago operations, which are classified as discontinued operations.

5.	Weighted average common shares outstanding

	For the three and nine months ended September 30, 2012, the diluted weighted average common shares outstanding were 62,301,446 and 62,301,707 respectively (September 30, 2011 – 62,301,446 for both periods). For the calculation of diluted earnings per share the Company excluded 3,336,947 and 3,263,430 stock options that are anti-dilutive for the three and nine months ended September 30, 2012 (September 30, 2011 – 3,194,276 and 2,879,119). The basic weighted average common shares outstanding was 62,301,446 for all periods.

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6.	Related party transactions

	In the course of normal business activities the Company purchased $0.1 million of processing services in the nine months ended September 30, 2012, (September 30, 2011 – $0.1 million) from a company with a common director. These services were purchased under normal industry terms and have been measured and disclosed at their settlement value. As of September 30, 2012 and December 31, 2011, there were no amounts outstanding in accounts payable to this service provider.

7.	Contingencies and commitments

	(a)	North Africa

	On August 27, 2008, the Company entered into an Exploration and Production Sharing Agreement (“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 kilometres of 3D seismic.

	The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15.0 million per exploration well, and the Company has provided a corporate guarantee to a maximum of US$45.0 million to secure its minimum work program obligations. The potential cost of drilling the three wells could exceed US$100.0 million.

	In January 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North – 1 well. In December 2011, the Company commenced the acquisition of 513 square kilometres of 3D seismic in accordance with the requirements of the EPSA and completed the acquisition in January 2012. The first phase of the exploration period has been extended until December 23, 2013, conditioned by Joint Oil on the Company securing a rig for the three well commitment by the end of September 2012. Without this extension, the commitment must be met by December 23, 2012.

	On January 30, 2012, the Company engaged an advisor to identify and evaluate alternatives to finance the Company’s remaining North Africa obligations. New information obtained during the process has adversely impacted currently available financing alternatives and may delay the outcome and drilling of the three exploratory wells. The Company recorded an impairment of $21.0 million to the Joint Oil Block as at June 30, 2012, charged to exploration and evaluation expense. This was a result of the following information obtained during the second quarter of 2012:

	·	Inert and Acid Gas Initiative - On June 12, 2012, DGE (Tunisian Direction Generale de L’Energie) announced an initiative for the Gulf of Gabes operators offshore Tunisia to study options for sequestration of carbon dioxide and other inert and acid gases (which comprise a high percentage of all known oil and gas accumulations in the Gulf of Gabes, including the Joint Oil Block) to allow the currently stranded high inert content gas to be developed commercially and brought to the Tunisian market. This initiative is focused on early development of the Sonde Zarat Discovery, which contains approximately 60% inert and acid gases. This initiative will ensure that the Zarat Plan of Development and other developments in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments vis-à-vis international organizations like the Kyoto Accord on greenhouse gas emissions. This study is anticipated to take twelve to eighteen months to understand the alternatives for carbon dioxide sequestration.

	·	Drilling Rig Availability - The initial results indicate that the global demand for offshore drilling units is higher in other parts of the world than North Africa. During the period ended September 30, 2012, one contractor submitted a bid for a technically acceptable jack up drilling rig that may be available in the second quarter of 2013. The commercial terms of their offer were unacceptable to Sonde. As a result, Sonde was unable to meet the terms of the one year extension of the initial exploration phase to December 2013. Without the extension the exploration phase will expire in December 2012. This expiration can trigger the US $45 million penalty in the event that Joint Oil does not agree to extend the three well exploratory well obligation to the second exploration phase. Combined, the first and second exploration phases would expire in December 2015.

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Page 9

7.	Contingencies and commitments (continued)

	·	Unitization and Plan of Development - The Company has filed a Plan of Development with Joint Oil for the development of the Zarat field. The Company expected Joint Oil to approve the plan of development expediently so that we could demonstrate to the market an asset with an approved Exploitation Plan. However, Joint Oil has deferred approval of the Company’s Plan of Development pending negotiations with the other license holder and Entreprise Tunisienne d’Activities Petrolicres (ETAP) on Unitization and a Unit Plan of Development for Zarat, which will in the Company’s opinion be heavily dependent on the outcome of the inert and acid gases initiative described above. As a result, the Company expects approval of its Zarat Plan of Development will be delayed for some time.

	·	Exploratory Well Obligations – The Company plans to discuss with Joint Oil the timing of the three well exploratory commitment due to lack of availability of a suitable drilling rig and pending resolution of the inert and acid gases sequestration issue. Neither the Company nor interested parties can find merit in an additional discovery of high inert and acid gases at this time without a clear commercialization path that includes a solution to this issue.

	Whether the Company can secure additional financing for the North Africa three exploratory well commitment or whether the US$45.0 million penalty will be triggered is uncertain. This uncertainty casts significant doubt about the Company’s ability to continue as a going concern. The Company continues its efforts to secure alternate financing or other arrangements on acceptable terms for the Joint Oil Block. The Company has met with Joint Oil and its shareholders and has formally requested that the three well obligation be moved into the second phase of the exploration period, which expires in December 2015.

	Public and private debt and equity markets remain inaccessible for exploratory or development projects on the Joint Oil Block and the Company’s Western Canada operations will not provide sufficient cash flows to meet the exploratory commitment. Without access to third party financing or a party to assume the Joint Oil Block exploratory obligations, the Company may not be able to continue as a going concern. The Financial Statements do not include any adjustments to the amounts and classification of assets (with the exception of a partial impairment of the Joint Oil Block component of the exploration and evaluation assets) and liabilities that may be necessary should the Company be unable to continue as a going concern, and these adjustments may be material.

	(b)	Commitments and financial liabilities

	At September 30, 2012, the Company has committed to future payments over the next five years and thereafter, as follows:

	2012		2013		2014		2015		2016		Thereafter		Total
Accounts payable and accrued liabilities		8,374		--		--		--		--		--		8,374
Stock based compensation liability		604		--		--		--		--		--		604
Derivative financial liabilities		30		--		--		--		--		--		30
North Africa exploration commitments (note 7a)		--		44,244		--		--		--		--		44,244
Office rent		304		1,212		1,212		1,217		1,233		7,159		12,337
		9,312		45,456		1,212		1,217		1,233		7,159		65,589

The Company generally relies on a combination of cash flow from operating activities, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for domestic and international operations. The Company is continuing to work to secure financing for the North Africa exploration commitment and is also attempting to restructure these obligations.

Q3 2012 FS

Page 10

7.	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 was drilled on the Mariner Block and Joint Oil had the right to put back the overriding royalty to the Company for US$12.5 million. Joint Oil exercised its put rights and the Company made a payment of US$12.5 million on January 15, 2012. Prior to the payment, the Company confirmed that the EPSA remains in full force and effect.

	(d)	Litigation and claims

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

8.	Risk Management

	Commodity price risk

	The Company enters into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility. These financial instruments are entered into solely for risk mitigation purposes and are not used for trading or other speculative purposes. In 2011, the Company entered into a commodity swap contract from March to December on a portion of the Company’s natural gas production. In return for this fixed price the Company sold a call option on a portion of the Company’s oil production from March 2011 through December 2012.

Three months ended

September 30, 2012

September 30, 2011

Term

Contract

Volume

Fixed Price

Realized gain (loss)

Unrealized gain (loss)

Realized gain

Unrealized gain (loss)

March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

$294

($104)

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

$21

$708

Nine months ended

September 30, 2012

September 30, 2011

Term

Contract

Volume

Fixed Price

Realized gain (loss)

Unrealized gain (loss)

Realized gain (loss)

Unrealized gain (loss)

March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

$585

$306

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($92)

$751

($105)

($431)

	Interest rate risk

	The Company is exposed to interest rate risk as the credit facilities bear interest at floating market interest rates. The Company had no interest rate swaps or hedges to mitigate interest rate risk at September 30, 2012 or December 31, 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 insignificant. This analysis assumes all other variables remain constant.

Q3 2012 FS

Page 11

8.	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
	2012		2011
(US$ thousands
Cash and cash equivalents		1,247		1,020
North Africa receivables		56		111
Foreign denominated financial assets		1,303		1,131

North Africa payables		663		1,720
Mariner swap provision		--		12,500
Foreign denominated financial liabilities		663		14,220

	These balances are exposed to fluctuations in the U.S. dollar. At this time, the Company has chosen not to enter into any risk management agreements to mitigate foreign exchange risk. The Company’s exposure to foreign currency exchange risk on its comprehensive income, assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent, is $0.1 million. This analysis assumes all other variables remain constant.

	Credit risk

	The Company’s credit risk exposure is as follows:

	September 30		December 31
	2012		2011
(CDN$ thousands)
Western Canada joint interest billings		2,005		2,830
Goods and Services Tax receivable		102		740
North Africa recoverable expenses		56		113
Revenue accruals and other receivables		2,181		3,753
Accounts receivable		4,344		7,436
Cash and cash equivalents		24,588		3,743
Maximum credit exposure		28,932		11,179

The Company’s allowance for doubtful accounts is currently $1.8 million (December 31, 2011 – $2.0 million). This amount offsets $1.7 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2011 – $1.8 million) and $0.1 million of Western Canada joint interest and miscellaneous receivables (December 31, 2011 – $0.2 million). The Company considers all amounts greater than 90 days to be past due. As at September 30, 2012, $1.0 million of accounts receivable are past due, all of which are considered to be collectible.

Q3 2012 FS

Page 12

9.	Financial instruments

	At September 30, 2012, cash and cash equivalents were comprised of $20.0 million in short term investment instruments and $4.6 million of cash held at financial institutions (December 31, 2011 – $3.7 million cash held at financial institutions).

	The following tables provide fair value measurement information for financial assets and liabilities as of September 30, 2012 and December 31, 2011. The carrying value of cash and cash equivalents, accounts receivables, provisions, accounts payable and accrued liabilities 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 table.

	Fair value measurements using:
	Carrying value		Fair value		Level 1		Level 2		Level 3
Financial liabilities
Commodity contracts – as at September 30, 2012		30		30		--		30		--
Commodity contracts – as at December 31, 2011		781		781		--		781		--

	The Company uses a fair value hierarchy to categorize the inputs used to measure the fair value of its financial instruments. Commodity contracts are measured using level 2.

10.	Provisions

	September 30 2012		December 31 2011
Mariner swap (note 7c)		--		12,713
Onerous contracts		--		17
Provisions		--		12,730

11.	Revenue

	The following summarizes the Company’s revenue:

	Three months ended September 30						Nine months ended September 30
	2012			2011			2012			2011
Petroleum and natural gas sales		6,436			10,279			21,179			29,255
Royalties		(660	)		(1,291	)		(2,523	)		(3,441	)
		5,776			8,988			18,656			25,814

12.	Operating expense

	Operating costs for the Company are as follows:

	Three months ended September 30				Nine months ended September 30
	2012		2011		2012		2011
Operating		3,212		3,521		10,506		9,627
Well workovers		617		609		1,870		1,412
		3,829		4,130		12,376		11,039

Q3 2012 FS

Page 13

13.	Supplemental cash flow information

	The changes in non-cash working capital are as follows:

	Three months ended September 30						Nine months ended September 30
	2012			2011			2012			2011
Accounts receivable		(314	)		(2,111	)		3,092			(912	)
Prepaid expenses and deposits		256			(58	)		345			399
Accounts payable and accrued liabilities		(1,607	)		(3,815	)		(9,281	)		(19,501	)
Provisions		(4	)		1,040			(12,730	)		435
Foreign currency translation adjustment		5			(1,273	)		249			(335	)
Change in non-cash working capital		(1,664	)		(6,217	)		(18,325	)		(19,914	)

The change in non-cash working capital is attributed to the following activities:

	Three months ended September 30						Nine months ended September 30
	2012			2011			2012			2011
Operating		2,461			(4,641	)		4,011			(3,552	)
Investing		(4,125	)		(1,576	)		(22,336	)		(16,362	)
Change in non-cash working capital		(1,664	)		(6,217	)		(18,325	)		(19,914	)

14.	Share 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 closing trading price on the Toronto Stock Exchange on the last trading day prior to the grant date. Options issued prior to May 2011 vest over three years with a maximum term of ten years. Options issued after May 2011 generally vest over four years with a maximum term of five years. The Board of Directors can at its discretion alter the vesting terms.

	Nine months ended September 30, 2012					Twelve months ended December 31, 2011
	Number of options			Weighted average exercise price		Number of options			Weighted average exercise price
($ thousands, except per share price)
Balance, beginning of period		2,974		$	3.43		1,910		$	5.78
Granted		757			2.34		1,984			3.49
Exercised		--			--		--			--
Forfeited		(543	)		3.20		(920	)		8.43
Balance, end of period		3,188			3.21		2,974			3.43

Q3 2012 FS

Page 14

14.	Share based compensation (continued)

	The following table summarizes stock options outstanding under the plan at September 30, 2012:

	Options outstanding						Options exercisable
Exercise price ($)	Number of options (thousands)		Average remaining contractual life (years)		Weighted average exercise price ($)		Number of options (thousands)		Weighted average exercise price ($)
0.88 – 2.50		708		4.45		2.35		16		2.50
2.51 – 3.00		654		3.68		2.85		299		2.86
3.01 – 4.00		1,035		7.86		3.10		958		3.09
4.01 – 11.80		791		8.06		4.43		674		4.46
0.88 – 11.80		3,188		6.29		3.21		1,947		3.52

The fair value of options granted during the year 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, 2012		Twelve months ended December 31,2011
Share price ($)		2.34		3.49
Exercise price ($)		2.34		3.49
Risk free rate (%)		1.5		2.0
Expected life (years)		3.8		3.7
Expected dividend yield (%)		--		--
Expected volatility (%)		78.1		87.6
Weighted average fair value of options granted ($)		1.31		2.13

	A forfeiture rate of 25.5% (December 31, 2011 – 27.6%) was used when recording stock based compensation. This estimate is based on the historical forfeiture rate and adjusted to the actual forfeiture rate. Stock option expense incurred for the three and nine months ended September 30, 2012 was $0.1 million and $0.5 million respectively (September 30, 2011 - $0.8 million and $2.4 million). No stock based compensation expense was capitalized during 2012 or 2011.

	In the course of preparing the Financial Statements management identified an error in the comparative figures for the three and nine months ended September 30, 2011. The Company had previously recognized stock option expense of $0.7 million and $3.4 million for the three and nine months respectively. This error was corrected in the audited consolidated financial statements and notes thereto for the year ended December 31, 2011.

	(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 87,506 and 211,104 shares on the open market under the ESSP during the three and nine months ended September 30, 2012 (September 30, 2011 – 44,551 and 104,113 shares). The costs related to this plan are expensed as incurred.

Q3 2012 FS

Page 15

14.	Share based compensation (continued)

	(c)	Stock unit awards

	At September 30, 2012, the Company had 1.6 million (December 31, 2011 – 1.5 million) stock unit awards outstanding, issued to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the applicable vesting date. The stock units have time and/or share based performance vesting terms which vary depending on whether the holder is an executive officer or director.

	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, 2012, the Company recorded a liability of $0.6 million to recognize the fair value of the vested stock units (December 31, 2011 - $2.0 million). During the nine months ended September 30, 2012, the Company paid $0.8 million to settle awards held by current and former directors.

	(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 and/or the lapse of time. In the nine months ended September 30, 2012, 66,666 RSUs were redeemed for a total of $0.1 million (September 30, 2011 – $Nil).

	The following table summarizes RSUs outstanding under the plan at September 30, 2012:

	Units outstanding						Units vested
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		229		1.42		2.56		94		3.00
3.01 – 3.50		28		0.84		3.10		14		3.09
3.51 – 3.64		10		1.54		3.64		4		3.64
0.00 – 3.64		267		1.36		2.66		112		3.03

RSUs issued were initially valued at the grant date and revalued at September 30, 2012, using a binomial lattice model with weighted average assumptions as follows:

	Valuation at September 30, 2012		Valuation at grant date
Share price ($)		0.75		2.47
Risk free rate (%)		1.1		1.5
Expected life (years)		1.1		2.4
Expected volatility (%)		75		55
Weighted average fair value ($)		0.17		1.99

Q3 2012 FS

Page 16

14.	Share based compensation (continued)

	Share based compensation is a recovery of $0.1 million for the three months ended September 30, 2012, due to a decrease in the liability associated with stock unit awards and restricted share units as a result of a lower share price. The following table summarizes share based compensation expense:

	Three months ended September 30						Nine months ended September 30
	2012			2011			2012			2011
Stock option expense		134			820			507			2,354
Stock unit award expense		(572	)		72			(590	)		852
Restricted share unit expense		(115	)		(11	)		(309	)		350
		(553	)		881			(392	)		3,556

The following table summarizes the share based compensation liability:

	September 30 2012		December 31 2011
Stock unit award liability		571		1,955
Restricted share unit liability		33		493
Share based compensation liability		604		2,448

15.	Segments and cash generating units

	The Company has identified two reporting segments based on geographical location, nature of operations, and regulatory regime applicable to oil and gas activities. The Company’s continuing operating and reportable segments are as follows:

	(a)	Western Canada

	This segment is comprised of the Company’s producing properties and undeveloped land located in Alberta, British Columbia, and Saskatchewan. All property, plant and equipment are included in this segment. Corporate assets, liabilities, revenues, and expenses are also included in this segment.

	(b)	North Africa

	This segment is comprised of the Company’s interest in the Joint Oil Block offshore North Africa. All costs incurred are directly attributable costs associated with the exploration and evaluation of this block and have been capitalized as exploration and evaluation assets. Working capital associated with the Block is included in this segment.

	The Company has five cash-generating units (“CGUs”), including the North Africa CGU, which is classified as exploration and evaluation assets. The four remaining CGUs are included in the Western Canada reportable segment and include Northern Alberta, Central Alberta, Southern Alberta and British Columbia.

	The CGUs have been chosen primarily based on their geographical location, similar reservoir characteristics, similar development plans, shared infrastructure, discrete processing and gathering facilities, regulatory regimes (e.g. Alberta vs. British Columbia) and management’s basis for internal reporting and monitoring.

Q3 2012 FS

Page 17

15.	Segments and cash generating units (continued)

	The condensed statements of operations for the three and nine months ended September 30, 2012 and 2011 by operating segment are as follows:

Three months ended September 30	Western Canada			North Africa		Total 2012			Western Canada			North Africa		Total 2011
(CDN$ thousands)
Revenue
Revenue, net of royalties		5,776			--		5,776			8,988			--		8,988
Gain (loss) on commodity derivatives		21			--		21			898			--		898
		5,797			--		5,797			9,886			--		9,886
Expenses
Operating		3,829			--		3,829			4,130			--		4,130
Transportation		145			--		145			271			--		271
Exploration and evaluation		196			--		196			784			--		784
General and administrative		1,300			--		1,300			2,303			--		2,303
Depletion and depreciation		2,604			--		2,604			4,409			--		4,409
Share based compensation		(553	)		--		(553	)		881			--		881
Property, plant and equipment impairment		--			--		--			--			--		--
Bad debt		1			--		1			(121	)				(121	)
Loss on settlement of decommissioning liabilities		--			--		--			24			--		24
		7,522			--		7,522			12,681			--		12,681
Operating loss		(1,725	)				(1,725	)		(2,795	)		--		(2,795	)
Other
Financing costs		(260	)		--		(260	)		(502	)		--		(502	)
Gain (loss) on foreign exchange		(162	)		--		(162	)		433			--		433
Gain on financial derivatives		--			--		--			1,930			--		1,930
Other income		74			--		74			27			--		27
		(348	)		--		(348	)		1,888			--		1,888
Loss from continuing operations before income taxes		(2,073	)		--		(2,073	)		(907	)		--		(907	)
Current income taxes		--			--		--			17			--		17
Loss from continuing operations		(2,073	)		--		(2,073	)		(924	)		--		(924	)

Q3 2012 FS

Page 18

15.	Reportable segments and cash generating units (continued)

Nine months ended September 30	Western Canada			North Africa			Total 2012			Western Canada			North Africa		Total 2011
Revenue
Revenue, net of royalties		18,656			--			18,656			25,814			--		25,814
Gain (loss) on commodity derivatives		659			--			659			355			--		355
		19,315			--			19,315			26,169			--		26,169
Expenses
Operating		12,376			--			12,376			11,039			--		11,039
Transportation		460			--			460			787			--		787
Exploration and evaluation		1,521			20,987			22,508			1,154			--		1,154
General and administrative		6,610			--			6,610			6,692			--		6,692
Depletion and depreciation		8,316			--			8,316			10,652			--		10,652
Share based compensation		(392	)		--			(392	)		3,556			--		3,556
Property, plant and equipment impairment		16,241			--			16,241			--			--		--
Bad debt		26			--			26			(123	)				(123	)
Loss on settlement of decommissioning liabilities		84			--			84			799			--		799
		45,242			20,987			66,229			34,556			--		34,556
Operating loss		(25,927	)		(20,987	)		(46,914	)		(8,387	)		--		(8,387	)
Other
Financing costs		(759	)		--			(759	)		86			--		86
Gain (loss) on foreign exchange		(446	)		--			(446	)		4,563			--		4,563
Gain on financial derivatives		--			--			--			(115	)		--		(115	)
Other income		146			--			146			(1,955	)		--		(1,955	)
Gain on disposition of exploration and evaluation assets		73,361			--			73,361			--			--		--
		72,302			--			72,302			2,579			--		2,579
Income (loss) from continuing operations before income taxes		46,375			(20,987	)		25,388			(5,808	)		--		(5,808	)
Current income taxes		35			--			35			137			--		137
Income (loss) from continuing operations		46,340			(20,987	)		25,353			(5,945	)		--		(5,945	)

The condensed statements of financial position by operating segment as at September 30, 2012 and December 31, 2011 are as follows.

	Western Canada		North Africa		Total – As at Sept. 30, 2012		Western Canada		North Africa		Total – As at Dec. 31, 2011
(CDN$ thousands)
Assets
Current
Cash and cash equivalents		24,480		108		24,588		3,012		731		3,743
Accounts receivable		4,289		55		4,344		7,323		113		7,436
Prepaid expenses and deposits		1,262		25		1,287		1,488		40		1,528
		30,031		188		30,219		11,823		884		12,707
Long term portion of prepaid expenses and deposits		316		--		316		420		--		420
Exploration and evaluation assets		11,016		44,373		55,389		8,907		60,108		69,015
Property, plant and equipment		102,102		--		102,102		104,745		--		104,745
Total assets		143,465		44,561		188,026		125,895		60,992		186,887
Liabilities
Current
Accounts payable and accrued liabilities		7,722		652		8,374		15,906		1,749		17,655
Share based compensation liability		604		--		604		2,448		--		2,448
Provisions		--		--		--		17		12,713		12,730
Derivative financial liabilities		30		--		30		781		--		781
		8,356		652		9,008		19,152		14,462		33,614
Decommissioning provision		27,339		--		27,339		26,344		--		26,344
Total liabilities		35,695		652		36,347		45,496		14,462		59,958

Q3 2012 FS

Page 19

16.	Discontinued operations

	(a)	Trinidad and Tobago

		On June 22, 2011, the Company completed the sale of its remaining 25% interest in Block 5(c) and the Mayaro-Guayaguayare block (“MG Block”) exploration and production license for cash proceeds of US$78.1 million and the assumption of the Company’s performance guarantee provided for the MG Block of US$12.0 million. On February 8, 2011, as part of the agreement, the Company had 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.

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	)
Proceeds net of transaction costs		87,908

Net assets disposed at carrying value
Exploration and evaluation assets		79,664
Decommissioning provisions		(3,040	)
Net assets		76,624
Gain before understated		11,284
Realized foreign currency translation reserve, reclassified from shareholders’ equity		(5,975	)
Net gain on disposition		5,309

	(b)	LNG Project

	On February 22, 2011, the Company completed the sale of its wholly owned subsidiary Liberty Natural Gas LLC which owned a 100% working interest in the LNG Project and received US$1.0 million for reimbursable costs incurred between January 1, 2011, and February 22, 2011. The Company is entitled to receive deferred cash consideration of US$12.5 million payable upon the project’s first successful gas delivery. No amounts have been recorded in the Financial Statements related to this contingent consideration.

	(c)	Financial information from discontinued operations

	Loss from discontinued operations reported in the 2011 consolidated statement of operations, comprehensive loss and deficit is as follows:

	Three months ended								Nine months ended
For the three and nine months ended September 30, 2011	Trinidad and Tobago			LNG Project		Total			Trinidad and Tobago			LNG Project			Total
(CDN$ thousands)
Expenses
General and administrative		(92	)		30		(62	)		(626	)		(879	)		(1,504	)
Finance costs		--			--		--			(493	)		--			(493	)
Gain (loss) on disposition of foreign operations, net of realized foreign currency translation reserve		318			--		318			5,308			(389	)		4,918
Income (loss) from discontinued operations		226			30		256			4,189			(1,268	)		2,921
Foreign currency translation gain (loss) relating to assets and liabilities held for sale		--			--		--			(1,148	)		20			(1,128	)
Reclassified from foreign currency translation reserve to net earnings		--			--		--			5,976			389			6,365
Total comprehensive income (loss) from discontinued operations		226			30		256			9,017			(859	)		8,158

Q3 2012 FS

Page 20

Document 2

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") has been prepared by management as of November 9, 2012, and reviewed and approved by the Board of Directors (the “Board”) of Sonde Resources Corp. (“Sonde”). This MD&A is a review of the operational results of Sonde. This MD&A should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ended December 31, 2011, and 2010. The reporting currency is the Canadian dollar unless otherwise stated.

Non-IFRS Measures – This MD&A contains references to funds from (used for) operations, funds from (used for) operations per share and operating netback, which are not defined under International Financial Reporting Standards (“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 Sonde believes funds from (used for) operations, funds from (used for) operations per share and operating netback are relevant indicators of Sonde’s financial performance, and its ability to fund future capital expenditures. Funds from (used for) operations and operating netback should not be considered an alternative to or more meaningful than cash provided by (used in) operating activities, as determined in accordance with IFRS, as an indicator of Sonde's performance. In the operating netback and funds from (used for) operations section of this MD&A, reconciliation has been prepared to cash provided by (used in) 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 equivalency conversion method primary applicable at the burner tip and does not represent a value equivalency at the wellhead. Such disclosure of boes may be misleading, particularly if used in isolation. Additionally, given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be misleading as an indication of value. Readers should be aware that historical results are not necessarily indicative of future performance. Natural gas production is expressed in thousand cubic feet (“mcf”). Oil and natural gas liquids are expressed in barrels (“bbls”).

Going concern – Sonde’s consolidated financial statements have been prepared on a going concern basis. The going concern basis assumes that Sonde will continue its operations in the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. Management believes that the going concern assumption is appropriate for the Financial Statements; however, the “Commitments and Contingencies” section describes significant uncertainties that cast significant doubt over the Company’s ability to continue as a going concern. If this assumption were not appropriate, adjustments to the carrying amounts of assets and liabilities, revenues and expenses and the statement of financial position classifications used may be necessary and these adjustments could be material.

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

	·	business strategy, plans and priorities;
	·	planned exploration and development activities;
	·	extension of Sonde’s exploratory well commitment in North Africa to the second phase of the exploratory period;
	·	planned capital expenditures;
	·	expected sources of funding for the capital program;
	·	expected changes in oil and gas production;
	·	continued plans to seek financing through a partnering process for North Africa; and
	·	other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance.

Q3 2012 MD&A

Page 1

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 Sonde and described in the forward-looking information contained in this interim MD&A. Assumptions have been made regarding, among other things, operating conditions, management’s expectations regarding future growth, plans for and results of drilling activity, availability of capital, future commodity prices and differentials, and other expenditures. Material risk factors affecting forward-looking information 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;
	·	availability of experienced service industry personnel and equipment;
	·	availability of qualified personnel and the ability to attract or retain key employees or members of management;
	·	the uncertainty of reserves 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) and risks associated with negotiating with foreign parties;
	·	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 Sonde’s operations or financial results are included in Sonde’s most recent Annual Information Form, which is available on SEDAR at www.sedar.com. In addition, information is available in Sonde’s other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission.

Sonde operates in many different jurisdictions and could be adversely affected by violations of the Corruption of Foreign Public Officials Act (Canada) or the U.S. Foreign Corrupt Practices Act and similar worldwide anti-corruption laws. The Acts (collectively “FCPA”) and similar worldwide anti-corruption laws, including the U.K. Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to government and other officials for the purpose of obtaining or retaining business. Sonde’s internal policies mandate compliance with these anti-corruption laws.

Despite training and compliance programs, Sonde cannot be assured that internal control policies and procedures will always protect it from acts of corruption committed by employees or agents. Continued expansion outside Canada, including in developing countries, could increase the risk of such violations in the future. Violations of these laws, or allegations of such violations, could disrupt the business and result in a material adverse effect on Sonde’s financial condition, results of operations and cash flows.

Forward-looking information is based on the estimates and opinions of Sonde’s management at the time the information is presented. Sonde 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.

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Page 2

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 Sonde, 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 Sonde’s’ annual reports on Form 40-F or Form 20-F on file with the U.S. Securities and Exchange Commission.

Business Overview and Strategy

Sonde Resources Corp. is a Calgary, Alberta, Canada based energy company engaged in the exploration for and production of oil and natural gas. Sonde’s operations are located in Western Canada and offshore North Africa. Sonde derives all of its production and cash flow from operations in Western Canada. Sonde’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 Sonde’s Southern Alberta cash generating unit (“CGU”) (or Greater Drumheller, Alberta area), which accounts for approximately 83% of Sonde’s production. The balance of production largely comes from the Kaybob/Windfall and Boundary Lake/Eaglesham areas in west-central Alberta. Sonde holds a Western Canadian land position of 454,396 gross (343,877 net) acres.

In Western Canada, Sonde continues to accumulate undeveloped acreage in the Montney (44,000 net acres), Duvernay (86,000 net acres) and Wabamun (51,000 net acres) plays. Sonde is monitoring natural gas netback prices and is returning a significant percentage of shut-in natural gas production back online. Western Canada production averaged 2,155 boe/day (68% natural gas). September production rates were diminished by approximately 5% due to required biennial plant maintenance at the Drumheller 9-9 battery. Sonde has completed hook up of three Michichi oil wells, recovered frac fluid on two of the wells and begun recovering the frac fluid on the third.

Sonde has completed an extended test of its previously announced 4-19-67-26W5 Montney well at Ante Creek North. This test confirmed the previously announced short-term production data, with high water cuts (~95%) throughout the production period. The well is capable of approximately 120 boe/d hydrocarbon production, but provides insufficient production to support the required pipeline and processing infrastructure on its own. If Sonde can prove an extension to this pool with follow-up drilling, the 4-19 can be tied-in as part of a future development plan and has subsequently been suspended awaiting future drilling results.

Sonde’s recently announced workover success on a Wabamun well in NW Alberta has continued to produce better than expected results, with current daily rates of approximately 150 boe/day, and high producing pressure indicating the well is capable of better performance when facilities can be optimized. Sonde is very encouraged by these results and is preparing plans for three horizontal well locations, and has submitted a permit application for an initial horizontal step-out well, which we anticipate receiving in the coming month.

In the Mannville “I” pool, Sonde has converted a previously suspended well to a water source well in preparation for expanding the waterflood, and is preparing for a high-rate test of this well in early November in an attempt to demonstrate that sufficient water will be available for this purpose.

Management met with representatives of Joint Oil and its shareholders the week of October 8 in Tunisia. Due to the status of the unitization agreements and the Gulf of Gabes inert and acid gas initiatives undertaken with Joint Oil and potential partners, Sonde formally requested that the three well exploration obligation be deferred into the second phase of the exploration period. The second phase of the exploration period expires in December 2015. With an extension, Sonde anticipates that continued progress on both the unitization agreements and the inert and acid gas initiatives will allow the Company to obtain a drilling rig on a staged basis and continue to seek financing through a partnering process.

In addition, Sonde presented the exploration potential of the Joint Oil Block and discussed the history of activities, beginning with the drilling of the Zarat North – 1 appraisal well, 513 sq. km. of 3-D seismic, review of the plan of development, implications of the Gulf of Gabes inert and acid gas consortium and the status of unitization. Sonde is encouraged by the positive tone of the ongoing dialogue with Joint Oil. While no assurance can be provided and while Sonde has reserved its rights in this regard, Sonde believes a basis may exist for a mutually acceptable extension of the three well exploration obligation. Sonde continues to make progress on defining the Zarat Field and area unit development plan allowing Sonde to advance its ongoing financing efforts.

Q3 2012 MD&A

Page 3

Operating netback and funds from (used for) operations

	($ thousands)									($ per boe)
Three months ended September 30	2012			2011			% change			2012			2011			% change
Petroleum and natural gas sales		6,436			10,279			(37	)		32.46			37.93			(14	)
Realized gain on financial instruments		--			294			(100	)		--			1.08			(100	)
Transportation		(145	)		(271	)		(46	)		(0.73	)		(1.00	)		(27	)
Royalties		(660	)		(1,291	)		(49	)		(3.32	)		(4.76	)		(30	)
		5,631			9,011			(38	)		28.41			33.25			(15	)
Operating expense		(3,212	)		(3,521	)		(9	)		(16.20	)		(12.99	)		25
Well workover expense		(617	)		(609	)		1			(3.11	)		(2.25	)		38
Operating netback(2)		1,802			4,881			(63	)		9.10			18.01			(49	)
General and administrative		(1,300	)		(2,365	)		(45	)		(6.56	)		(8.73	)		(25	)
Foreign exchange gain (loss)		23			319			(93	)		0.12			1.18			(90	)
Interest and other income		74			27			174			0.37			0.10			270
Interest		(104	)		(266	)		(61	)		(0.52	)		(0.98	)		(47	)
Bad debt (expense) recovery		(1	)		121			(101	)		(0.01	)		0.45			(102	)
Income taxes		--			(17	)		(100	)		--			(0.06	)		(100	)
Funds from operations(1,2)		494			2,700			(82	)		2.50			9.97			(75	)
Farm in penalty and exploration expense		--			(784	)		(100	)		--			(2.89	)		(100	)
Decommissioning expenditures		--			(24	)		(100	)		--			(0.09	)		(100	)
Changes in non-cash working capital		2,461			(4,641	)		(153	)		12.41			(17.12	)		(172	)
Cash provided by (used in) operating activities(1)		2,955			(2,749	)		(207	)		14.91			(10.13	)		(247	)

(1) Table includes both continuing and discontinued operations. Discontinued operations relate to the sale of certain exploration and production licenses in Trinidad and Tobago in June 2011 and the sale of a wholly-owned subsidiary, Liberty Natural Gas LLC, in February 2011. There were no revenues associated with discontinued operations, which consisted of nil (2011 – $0.1 million) general and administrative expense.

(2) Non-IFRS measure.

For the three months ended September 30, 2012, funds from operations was $0.5 million compared to funds from operations of $2.7 million for the same period in 2011. This was primarily the result of reduced operating netbacks as a result of lower natural gas prices and lower production volumes.

Q3 2012 MD&A

Page 4

	($ thousands)									($ per boe)
Nine months ended September 30	2012			2011			% change			2012			2011			% change
Petroleum and natural gas sales		21,179			29,255			(28	)		31.97			38.86			(18	)
Realized gain (loss) on financial instruments		(92	)		480			(119	)		(0.14	)		0.64			(122	)
Transportation		(460	)		(787	)		(42	)		(0.69	)		(1.05	)		(34	)
Royalties		(2,523	)		(3,441	)		(27	)		(3.80	)		(4.57	)		(17	)
		18,104			25,507			(29	)		27.34			33.88			(19	)
Operating expense		(10,506	)		(9,627	)		9			(15.86	)		(12.79	)		24
Well workover expense		(1,870	)		(1,412	)		32			(2.82	)		(1.88	)		50
Operating netback(2)		5,728			14,468			(60	)		8.66			19.21			(55	)
General and administrative		(6,610	)		(8,197	)		(19	)		(9.98	)		(10.89	)		(8	)
Foreign exchange loss		(372	)		1,103			(134	)		(0.56	)		1.47			(138	)
Interest and other income		146			86			70			0.22			0.11			100
Interest		(271	)		(1,850	)		(85	)		(0.41	)		(2.46	)		(83	)
Bad debt (expense) recovery		(26	)		123			(121	)		(0.04	)		0.16			(125	)
Income taxes		(35	)		(137	)		(74	)		(0.05	)		(0.18	)		(72	)
Funds from (used for) operations(1,2)		(1,440	)		5,596			(126	)		(2.16	)		7.42			(129	)
Farm-in penalty and exploration expense		(200	)		(1,154	)		(83	)		(0.30	)		(1.53	)		(80	)
Decommissioning expenditures		(151	)		(870	)		(83	)		(0.23	)		(1.16	)		(80	)
Changes in non-cash working capital		4,011			(3,552	)		(213	)		6.05			(4.72	)		(228	)
Cash provided by operating activities (1)		2,220			20			11,000			3.36			0.01			33,500

(2) Non-IFRS measure.

For the nine months ended September 30, 2012, funds used for operations was $1.4 million compared to funds from operations of $5.6 million for the same period in 2011. This was primarily the result of reduced operating netbacks as a result of significantly lower natural gas prices and lower production volumes. This was partially offset by a lower interest expense.

Production

	Q3	Q2	Q3	Nine months ended
Commodity	2012	2012	2011		2012	2011
Natural gas (mcf/d)	8,757	9,665	12,673		9,989	12,188
Crude oil (bbls/d)	523	554	631		547	522
Natural gas liquids (bbls/d)	172	191	203		206	205
Total production (boe/d) (6:1)	2,155	2,356	2,946		2,418	2,757

	Q3	Q2	Q3	Nine months ended
Region	2012	2012	2011		2012	2011
Southern Alberta (boe/d)	1,813	1,956	2,301		1,968	2,103
Central Alberta (boe/d)	194	217	336		277	322
Other Western Canada (boe/d)	148	183	309		173	332
Total production (boe/d) (6:1)	2,155	2,356	2,946		2,418	2,757

Q3 2012 MD&A

Page 5

For the three months ended September 30, 2012, production averaged 2,155 boe/d. The decrease in production from the second quarter of 2012 is primarily due to decreased gas volumes due to shut-in gas wells, required biennial plant maintenance at the Drumheller 9-9 battery and natural decline of gas reserves.

Petroleum and natural gas sales

	Q3		Q2		Q3		Nine months ended
	2012		2012		2011			2012		2011
($ thousands, except where otherwise noted)
Petroleum and natural gas sales
Natural gas	1,901		1,844		4,280			6,059		12,974
Crude oil	3,708		3,406		4,753			11,787		12,475
Natural gas liquids	827		1,064		1,246			3,333		3,806
Transportation	(145	)	(119	)	(271	)		(460	)	(787	)
Royalties	(660	)	(683	)	(1,291	)		(2,523	)	(3,441	)
Realized gain (loss) on commodity derivatives	--		(25	)	294			(92	)	480
Total	5,631		5,487		9,011			18,104		25,507
Average sales price (including commodity derivatives)
Natural gas ($/mcf)	2.36		2.10		3.92			2.21		4.08
Crude oil ($/bbl)	77.09		67.10		81.90			78.00		86.88
Natural gas liquids ($/bbl)	52.24		61.07		66.83			59.01		68.02
Average sales price ($/boe)	32.46		29.33		39.01			31.83		39.50
AECO Gas ($/mcf)(1)	2.34		1.94		3.53			2.07		3.83
Edmonton Light ($/bbl) (1)	86.08		83.00		92.22			87.73		95.27

(1) Source: Independent qualified reserves evaluator.

For the three months ended September 30, 2012, petroleum and natural gas sales, net of transportation and royalties was $5.6 million, consisting of $1.9 million in natural gas, $3.7 million in crude oil and $0.8 million in natural gas liquids sales, less $0.7 million of royalties and $0.1 million of transportation costs. Sonde realized an average sales price of $32.46 per boe during the three months ended September 30, 2012 compared to $29.33 per boe in the three months ended June 30, 2012, exclusive of royalties and transportation, due to higher natural gas prices and a decreased negative differential between realized crude prices and the WTI benchmark.

For the nine months ended September 30, 2012, petroleum and natural gas sales, net of transportation and royalties was $18.1 million, consisting of $6.1 million in natural gas, $0.1 million in realized losses on commodity derivatives, $11.8 million in crude oil and $3.3 million in natural gas liquids sales, less $2.5 million of royalties and $0.5 million of transportation costs. Sonde realized an average sales price of $31.83 per boe during the nine months ended September 30, 2012 compared to $39.50 per boe in the nine months ended September 30, 2011, exclusive of royalties and transportation, due to depressed natural gas prices and lower crude oil prices.

Royalties

	Q3	Q2	Q3	Nine months ended
	2012	2012	2011		2012	2011
($ thousands, except where otherwise noted)
Crown	485	435	988		1,842	2,859
Freehold and overriding	175	248	303		681	582
Total	660	683	1,291		2,523	3,441
Royalties per boe ($)	3.33	3.18	4.76		3.81	4.57
Average royalty rate (%)	10.5	11.1	12.5		12.2	11.9

Q3 2012 MD&A

Page 6

Sonde 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 Sonde’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 until cumulative production reaches 50,000 boe to 100,000 boe, depending on well depth. Sonde anticipates that production from wells drilled in 2012 would qualify for these lower royalty rates.

Natural gas and liquids royalties for the three months ended September 30, 2012 were $0.7 million or 10.5% of total petroleum and natural gas sales compared to 11.1% in in the three months ended June, 2012. The decrease is due primarily to lower realized prices and a positive Gas Cost Allowance adjustment.

Operating and well workover expense

Combined operating and well workover expenses for the three months ended September 30, 2012 were $3.8 million or $19.31 per boe, compared to $4.2 million or $19.75 per boe in the three months ended June 30, 2012. The decrease in aggregate expenses from the three months ended September 30, 2012, is due to decreased processing fees and contract labor for wells that are shut in.

Capital expenditures

	Q3		Q2		Q3		Nine months ended
	2012		2012		2011			2012		2011
($ thousands)
Acquisitions	--		--		6,088			--		6,088
Exploration and evaluation	555		(851	)	(1,372	)		4,489		8,974
Drilling and completions	9,179		4,424		13,453			15,385		20,657
Plants, facilities and pipelines	802		797		1,470			3,649		3,657
Land and lease	2,903		1,392		385			5,049		2,013
Capital well workovers	109		488		175			1,166		308
Capitalized general and administrative expenses	1,168		1,382		655			3,411		2,413
Capital expenditures	14,716		7,632		20,854			33,149		44,110
Dispositions	--		--		(283	)		(74,979	)	(87,908	)
Western Canada exploration and evaluation expense	(196	)	(239	)	(800	)		(1,321	)	(1,158	)
Net capital expenditures	14,520		7,393		19,771			(43,151	)	(44,956	)

	Q3	Q2		Q3		Nine months ended
	2012	2012		2011			2012		2011
($ thousands)
Canada	13,306	7,452		21,192			(50,068	)	31,907
North Africa	1,196	(16	)	(1,209	)		6,612		9,747
Corporate Assets	18	(43	)	96			305		733
Trinidad and Tobago	--	--		(308	)		--		(87,343	)
Net capital expenditures	14,520	7,393		19,771			(43,151	)	(44,956	)

Q3 2012 MD&A

Page 7

Western Canada

Sonde continues to accumulate undeveloped acreage in the Montney (44,000 acres net), Duvernay (86,000 acres net) and Wabamun (51,000 acres net) plays. Sonde continued its well re-activation program concentrated on an extensive portfolio of suspended wells. Sonde performed 43 net workovers and recompletions in the nine months ended September 30, 2012.

Sonde is monitoring natural gas netback prices and is returning a significant percentage of shut-in natural gas production back online. With the current downturn in natural gas prices, Sonde has not allocated capital to stemming the base decline on natural gas production, and instead is focused solely on maintaining existing liquids production while the drilling program is underway.

At Michichi, Sonde has completed tie-in of its third short-radius horizontal well, the 5-16-31-17W4; however, start-up of this well was delayed for a short period due to the need for a coiled tubing clean out to remove excess frac sand from the well. Sonde has recovered frac fluid on two of the wells and begun recovering the frac fluid on the third.

Sonde’s recently-announced workover success on a Wabamun well NW Alberta has continued to produce better-than-expected results, with current daily rates of approximately 150 boe/day, and high producing pressure indicating the well is capable of better performance when facilities can be optimized. Sonde is very encouraged by these results and is preparing plans for three horizontal well locations, and has submitted a permit application for an initial horizontal step-out well, which we anticipate receiving in the coming month.

North Africa

In addition, Sonde presented the exploration potential of the Joint Oil Block and discussed the history of activities, beginning with the drilling of Zarat North – 1 appraisal well, 513 sq. km. of 3-D seismic, review of the plan of development, implications of the Gulf of Gabes inert and acid gas consortium and the status of unitization. Sonde is encouraged by the positive tone of the ongoing dialogue with Joint Oil. While no assurance can be provided and while Sonde has reserved its rights in this regard, Sonde believes a basis may exist for a mutually acceptable extension of the three well exploration obligation. Sonde continues to make progress on defining the Zarat Field and area unit development plan allowing Sonde to advance its ongoing financing efforts.

Q3 2012 MD&A

Page 8

Contingencies and commitments

North Africa

On August 27, 2008, the Company entered into an Exploration and Production Sharing Agreement (“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 kilometres of 3D seismic. The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15.0 million per exploration well, and the Company has provided a corporate guarantee to a maximum of US$45.0 million to secure its minimum work program obligations. The potential cost of drilling the three wells could exceed US$100.0 million.

In January 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North – 1 well. In December 2011, the Company commenced the acquisition of 513 square kilometres of 3D seismic in accordance with the requirements of the EPSA and completed the acquisition in January 2012. The first phase of the exploration period has been extended until December 23, 2013, conditioned by Joint Oil on the Company securing a rig for the three well commitment by the end of September 2012. Without this extension, the commitment must be met by December 23, 2012.

On January 30, 2012, the Company engaged an advisor to identify and evaluate alternatives to finance the Company’s remaining North Africa obligations. New information obtained during the process has adversely impacted currently available financing alternatives and may delay the outcome and drilling of the three exploratory wells. This was a result of the following information obtained during the second quarter of 2012:

	·	Inert and Acid Gas Initiative – On June 12, 2012, DGE (Tunisian Direction Generale de L’Energie) announced an initiative for the Gulf of Gabes operators offshore Tunisia to study options for sequestration of carbon dioxide and other inert and acid gases (which comprise a high percentage of all known oil and gas accumulations in the Gulf of Gabes, including the Joint Oil Block) to allow the currently stranded high inert content gas to be developed commercially and brought to the Tunisian market. This initiative is focused on early development of the Sonde Zarat Discovery, which contains approximately 60% inert and acid gases. This initiative will ensure that the Zarat Plan of Development and other development in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments vis-à-vis international organizations like the Kyoto Accord on greenhouse gas emissions. This study is anticipated to take twelve to eighteen months to understand the alternatives for carbon dioxide sequestration.

	·	Drilling Rig Availability – The initial results indicate that the global demand for offshore drilling units is higher in other parts of the world than North Africa. During the period ended September 30, 2012, one contractor submitted a bid for a technically acceptable jack up drilling rig that may be available in the second quarter of 2013. The commercial terms of their offer were unacceptable to Sonde. As a result, Sonde was unable to meet the terms of the one year extension of the initial exploration phase to December 2013. Without the extension the exploration phase will expire in December 2012. This expiration can trigger the US $45 million penalty in the event that Joint Oil does not agree to extend the three well exploratory well obligation to the second exploration phase. Combined, the first and second exploration phases would expire in December 2015.

	·	Unitization and Plan of Development – Sonde has filed a Plan of Development with Joint Oil for the development of the Zarat field. Sonde expected Joint Oil to approve the plan of development expediently so that Sonde could demonstrate to the market an asset with an approved Exploitation Plan. However, Joint Oil has deferred approval of Sonde’s Plan of Development pending negotiations with the other license holder and Entreprise Tunisienne d’Activities Petrolicres (ETAP) on Unitization and a Unit Plan of Development for Zarat, which will in the Company’s opinion be heavily dependent on the outcome of the inert and acid gases initiative described above. As a result, Sonde expects approval of its Zarat Plan of Development will be delayed for some time.

	·	Exploratory Well Obligations – Sonde is in discussions with Joint Oil regarding the timing of the three well exploratory commitment due to lack of availability of a suitable drilling rig and pending resolution of the inert and acid gases sequestration issue. Neither Sonde nor interested parties can find merit in an additional discovery of high inert and acid gases at this time without a clear commercialization path that includes a solution to this issue.

Q3 2012 MD&A

Page 9

Whether the Company can secure additional financing for the North Africa three exploratory well commitment or whether the US$45.0 million penalty will be triggered is uncertain. This uncertainty casts significant doubt about the Company’s ability to continue as a going concern. The Company continues its efforts to secure alternate financing or other arrangements on acceptable terms for the Joint Oil Block. The Company has met with Joint Oil and its shareholders and has formally requested that the three well obligation be moved into the second phase of the exploration period, which expires in December 2015.

Public and private debt and equity markets remain inaccessible for exploratory or development projects on the Joint Oil Block and the Company’s Western Canada operations will not provide sufficient cash flows to meet the exploratory commitment. Without access to third party financing or a party to assume the Joint Oil Block exploratory obligations, the Company may not be able to continue as a going concern. The Financial Statements do not include any adjustments to the amounts and classification of assets (with the exception of a partial impairment of the Joint Oil Block component of the exploration and evaluation assets) and liabilities that may be necessary should the Company be unable to continue as a going concern, and these adjustments may be material.

Litigation and claims

Sonde is involved in various claims and litigation arising in the ordinary course of business. In the opinion of Sonde such claims and litigation are not expected to have a material effect on Sonde’s financial position or its results of operations. Sonde maintains insurance, which in the opinion of Sonde, is in place to address any future claims as to matters insured.

Liquidity and capital resources

	September 30			December 31
	2012			2011
($ thousands)
Cash and cash equivalents		24,588			3,743
Accounts receivable		4,344			7,436
Prepaid expenses and deposits		1,287			1,528
Accounts payable and accrued liabilities		(8,374	)		(17,655	)
Stock based compensation liability		(604	)		(2,448	)
Provisions		--			(12,730	)
Derivative financial liabilities		(30	)		(781	)
Working capital surplus (deficit)		21,211			(20,907	)

As at September 30, 2012, Sonde had a working capital surplus of $21.2 million (December 31, 2011 – $20.9 million deficit) and had issued three letters of credit for $0.2 million (December 31, 2011 – two letters of credit of $0.1 million) against the $30.0 million (December 31, 2011 - $40.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75% as at September 30, 2012 and at December 31, 2011.

Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of Sonde and a general security agreement covering all the assets of Sonde. Credit Facility A has covenants, as defined in Sonde’s credit agreement, that require Sonde to maintain an adjusted 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. Sonde can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility. As at September 30, 2012, Sonde was in compliance with all debt covenants. Sonde is subject to the next semi-annual review of its credit facilities on or before December 31, 2012.

Q3 2012 MD&A

Page 10

At September 30, 2012, the Company has committed to future payments over the next five years, as follows:

	2012		2013		2014		2015		2016		Thereafter		Total
Accounts payable and accrued liabilities		8,374		--		--		--		--		--		8,374
Stock based compensation liability		604		--		--		--		--		--		604
Derivative financial liabilities		30		--		--		--		--		--		30
North Africa exploration commitments		--		44,244		--		--		--		--		44,244
Office rent		304		1,212		1,212		1,217		1,233		7,159		12,337
		9,312		45,456		1,212		1,217		1,233		7,159		65,589

Sonde generally relies on a combination of cash flow from operations, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for domestic and international operations. From time to time Sonde may supplement its liquidity with the proceeds from the sale of assets. Sonde is continuing to work to secure financing for the North Africa exploration commitment and is also attempting to defer these obligations.

General and administrative expenses

	Q3		Q2		Q3		Nine months ended
	2012		2012		2011			2012		2011
($ thousands, except where otherwise noted)
Continuing operations
Gross general and administrative expense	2,468		3,892		2,958			10,021		9,105
Capitalized general and administrative expense	(1,168	)	(1,381	)	(655	)		(3,411	)	(2,413	)
	1,300		2,511		2,303			6,610		6,692
Discontinued operations
Gross and net general and administrative expense	--		--		62			--		1,505
Total net general and administrative expense	1,300		2,511		2,365			6,610		8,197
General and administrative expense ($/boe)	6.56		11.66		8.73			10.02		10.89

For the three months ended September 30, 2012, gross general and administrative (“G&A”) expenses decreased to $2.5 million from $3.9 million for the three months ended June 30, 2012. Gross G&A for continuing operations consists of $0.7 million (June 30, 2012 – $1.1million) relating to North Africa and $1.8 million (June 30, 2012 – $2.8 million) related to Western Canada administration and corporate head office. As of September 30, 2012, Sonde had eliminated all consulting staff and reduced its Calgary head count by six employees and three full time consultants, expected to result in approximately $1.3 million in savings.

Depletion, depreciation and impairment

For the three months ended September 30, 2012, depletion and depreciation was $2.6 million or $13.14 per boe compared to $4.4 million or $16.27 per boe for the same period in 2011. The calculation of depletion and depreciation included an estimated $9.4 million (September 30, 2011 - $21.5 million) for future development capital associated with proved plus probable undeveloped reserves and excluded $55.4 million (September 30, 2011 – $64.5 million) related to exploration and evaluation assets. The variance is caused by a lower depletion base due to asset impairments for the six months ended June 30, 2012 and lower production volumes.

Related party transactions

In the course of normal business activities the Company purchased $0.1 million of processing services in the nine months ended September 30, 2012, (September 30, 2011 – $0.1 million) from a company with a common director. These services were purchased under normal industry terms and have been measured and disclosed at their settlement value. As of September 30, 2012 and December 31, 2011, there were no amounts outstanding in accounts payable to this service provider.

Q3 2012 MD&A

Page 11

Share based compensation

	Q3		Q2		Q3		Nine months ended
	2012		2012		2011			2012		2011
($ thousands)
Stock option expense	134		130		820			507		2,354
Stock unit award expense	(572	)	(141	)	72			(590	)	852
Restricted share unit expense	(115	)	(150	)	(11	)		(309	)	350
Share based compensation	(553	)	(161	)	881			(392	)	3,556

During the three months ended September 30, 2012, Sonde incurred a share based compensation recovery of $0.6 million compared to an expense of $0.8 million for the three months ended September 30, 2011. The recovery is due to a decrease in the value of stock unit awards and restricted share unit awards as a result of cancelled awards and a decline in the Company’s share price.

The Restricted Share Unit Plan (“RSUs” or the “Plan”) became effective March 2011 to attract and retain experienced personnel with incentive compensation tied to shareholder return.

Under the Plan, upon vesting 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 Sonde on the vesting date. Under the Plan, RSUs vest over a three year period, subject to a minimum floor share price. In the nine months ended September 30, 2012, 66,666 RSUs were redeemed for a total of $0.1 million (September 30, 2011 – Nil).

At September 30, 2012, the Company had 1.6 million (December 31, 2011 – 1.5 million) stock unit awards outstanding, issued to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the applicable vesting date. The stock units have time and/or share based performance vesting terms which vary depending on whether the holder is an executive officer or director.

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, 2012, the Company recorded a liability of $0.6 million to recognize the fair value of the vested stock units (December 31, 2011 - $2.0 million). During the nine months ended September 30, 2012, the Company paid $0.1 million to settle awards held by a director who retired from the Board and $0.7 million to settle awards held by executive officers.

Share capital

As at November 9, 2012, Sonde had 62,301,446 common shares and 3,188,292 stock options issued and outstanding.

Sensitivities

The following sensitivity analysis is provided to demonstrate the impact of changes in commodity prices on petroleum and natural gas sales for the three months ended September 30, 2012, and is based on the balances disclosed in this MD&A and the consolidated financial statements for the three months ended September 30, 2012:

($ thousands)	Petroleum and Natural Gas Sales(1)
Change in average sales price for natural gas by $1.00/mcf		806
Change in the average sales price for crude oil and natural gas liquids by $1.00/bbl		64
Change in natural gas production by 1 mmcf/d (2)		217
Change in crude oil and natural gas liquids production by 100 bbls/d (2)		905

(1)	Reflects the change in petroleum and natural gas sales for the three months ended September 30, 2012.

(2)	Reflects the change in production multiplied by Sonde’s average sales prices for the three months ended September 30, 2012 excluding fixed price commodity contracts.

Q3 2012 MD&A

Page 12

Foreign exchange risk

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

	September 30		December 31
	2012		2011
(US$ thousands)
Cash and cash equivalents		1,247		1,020
North Africa receivables		56		111
Foreign denominated financial assets		1,303		1,131

North Africa payables		663		1,720
Mariner swap provision		--		12,500
Foreign denominated financial liabilities		663		14,220

Commodity price risk

Sonde enters into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility. These financial instruments are entered into solely for risk mitigation purposes and are not used for trading or other speculative purposes.

In 2011, Sonde entered into a commodity swap contract from March to December on a portion of Sonde’s natural gas production. In return for this fixed price Sonde sold a call option on a portion of Sonde’s oil production.

Three months ended

September 30, 2012

September 30, 2011

Term

Contract

Volume

Fixed Price

Realized loss

Unrealized gain

Realized gain

Unrealized gain (loss)

March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

$294

($104

)

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

$21

$708

Nine months ended

September 30, 2012

September 30, 2011

Term

Contract

Volume

Fixed Price

Realized loss

Unrealized gain

Realized gain (loss)

Unrealized gain (loss)

March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

585

$306

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($92

)

$751

($105

)

($431

)

These balances are exposed to fluctuations in the U.S. dollar. At this time, Sonde has chosen not to enter into any risk management agreements to mitigate foreign exchange risk. Sonde’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 $0.1 million. This analysis assumes all other variables remain constant.

Credit risk

Purchasers of Sonde’s oil, gas and natural gas liquids are subject to an internal credit review to minimize the risk of nonpayment. Sonde mitigates risk from joint venture partners by obtaining partner approval of capital expenditures prior to starting a project.

Sonde’s accounts receivable are with natural gas and liquids marketers 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.

Q3 2012 MD&A

Page 13

Sonde’s credit risk exposure is as follows:

	September 30		December 31
	2012		2011
(CDN$ thousands)
Western Canada joint interest billings		2,005		2,830
Goods and Services Tax receivable		102		740
North Africa recoverable expenses		56		113
Revenue accruals and other receivables		2,181		3,753
Accounts receivable		4,344		7,436
Cash and cash equivalents		24,588		3,743
Credit exposure		28,932		11,179

The Company considers all amounts greater than 90 days to be past due. As at September 30, 2012, $1.0 million of accounts receivable are past due, all of which are considered to be collectible.

Interest rate risk

Sonde is exposed to interest rate risk as the credit facilities bear interest at floating market interest rates. Sonde had no interest rate swaps or hedges to mitigate interest rate risk September 30, 2012 or December 31, 2011. Sonde’s exposure to fluctuations in interest expense on its net income and comprehensive income is insignificant.

Income taxes

Sonde’s current and future income taxes are dependent on factors such as production, commodity prices and tax classification of drilling costs related to exploration and development wells. At September 30, 2012, Sonde has estimated $294.0 million in tax pools (December 31, 2011 – $348.6 million) including $120.9 million in non-capital losses (December 31, 2011 – $126.0 million) that are available for future deduction against taxable income.

The sale of undeveloped land in the nine months ended September 30, 2012, reduced Canadian oil and gas property expense by approximately $49.4 million and non-capital losses by $25.6 million. Non-capital losses expire in the years 2026 – 2031.

	September 30		December 31
	2012		2011
(CDN$ thousands)
Canadian exploration expense		46,847		56,537
Canadian oil and gas property expense		--		44,474
Canadian development expense		44,441		31,905
Undepreciated capital costs		21,145		24,660
Foreign exploration expense		49,257		32,563
Non-capital losses		101,597		126,038
Capital losses		30,094		30,094
Share issue costs and other		585		2,285
		293,966		348,556

Q3 2012 MD&A

Page 14

Off-balance sheet arrangements

Sonde has no off-balance sheet arrangements.

Disclosure controls and procedures and internal control over financial reporting

Disclosure controls and procedures are designed to provide reasonable assurance that material information is gathered and reported to senior management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding public disclosure.

Sonde is required to disclose any change in Sonde’s internal controls over financial reporting that occurred during the period beginning on July 1, 2012, and ending on September 30, 2012, that has materially affected, or is reasonably likely to materially affect, Sonde’s internal controls over financial reporting. The certifying officers concluded that no material changes in Sonde’s internal controls and procedures have occurred during Sonde’s most recent interim period ended September 30, 2012, which have materially affected, or are reasonably likely to materially affect, Sonde’s internal controls over financial reporting.

Quarterly financial summary

($ thousands except per share and production amounts)

	2012			2012			2012			2011			2011			2011			2011			2010
		Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Production
Natural gas (mcf/d)		8,757			9,665			11,553			12,186			12,673			11,509			12,377			14,140
Crude oil and natural gas liquids (bbl/d)		695			745			820			880			834			666			677			730
Total (boe/d)		2,155			2,356			2,746			2,911			2,946			2,584			2,740			3,087
Petroleum & natural gas sales (2)		5,631			5,487			6,986			9,445			9,011			7,747			8,749			10,002
Net income (loss) from continuing operations		(2,073	)		(28,030	)		55,456			(37,529	)		(924	)		(872	)		(4,150	)		(40,952	)
Net income (loss) from continuing operations per share – basic and diluted		(0.03	)		(0.45	)		0.89			(0.60	)		(0.01	)		(0.01	)		(0.07	)		(0.66	)
Net income (loss) (1)		(2,073	)		(28,030	)		55,456			(37,546	)		(668	)		3,019			(5,376	)		(74,177	)
Net income (loss) per share – basic and diluted(1)		(0.03	)		(0.45	)		0.89			(0.60	)		(0.01	)		0.05			(0.09	)		(1.19	)
Funds from (used for) operations (3)		494			(1,267	)		(667	)		3,155			2,700			881			1,645			871
Funds from (used for) operations per share – basic and diluted (3)		0.01			(0.02	)		(0.01	)		0.05			0.01			0.01			0.03			0.01

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

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

(3) Non-IFRS measures.

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

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

	·	Fluctuations in Sonde’s petroleum and natural gas sales 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 Sonde’s net income (loss) from quarter to quarter are primarily caused by variations in petroleum and natural gas sales, sales of assets and impairments of property, plant and equipment.

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

Q3 2012 MD&A

Page 15

Please refer to the other sections of this MD&A for the detailed discussions on changes for the three and nine months ended September 30, 2012.

Additional Information

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

Q3 2012 MD&A

Page 16

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, 2012.

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

	A.	designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

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

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

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

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

5.2	N/A

5.3	N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2012 and ended on September 30, 2012 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.

Date: November 9, 2012

(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, Kurt A. Nelson, the Chief Financial 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, 2012.

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

	A.	designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

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

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

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

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

5.2	N/A

5.3	N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on July 1, 2012 and ended on September 30, 2012 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.

Date: November 9, 2012

(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, 2012	By:	/s/ Kurt A. Nelson
			Name:	Kurt A. Nelson
			Title:	Chief Financial Officer