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,	May	2013
Commission File Number	001-31395
Sonde Resources Corp.
(Translation of registrant’s name into English)
Suite 3100, 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.		Financial Statements for the quarter ended March 31, 2013

2.		Management Discussion and Analysis for the quarter ended March 31, 2013

3.		News Release, dated May 6, 2013

4.		Canadian Form 52-109F2 Certification of Interim Filings – CEO

5.		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	Note	March 31 2013	December 31 2012
(CDN$ thousands) (Unaudited)
Assets
Current
Cash and cash equivalents	5	16,769	19,695
Accounts receivable	6	4,633	4,683
Prepaid expenses and deposits		771	733
		22,173	25,111
Long term portion of prepaid expenses and deposits		754	732
Exploration and evaluation assets	3	56,487	56,499
Property, plant and equipment	3	102,309	104,144
		181,723	186,486

Liabilities
Current
Accounts payable and accrued liabilities		6,198	6,850
Share based compensation liability	4	912	1,074
		7,110	7,924
Decommissioning provision		30,153	29,972
		37,263	37,896
Contingencies and commitments	7

Shareholders’ Equity
Share capital	11	369,892	369,892
Contributed surplus		34,597	34,290
Foreign currency translation reserve		941	(34)
Deficit		(260,970)	(255,558)
		144,460	148,590
Going concern	2(b)
Segments	14
Subsequent event	15
		181,723	186,486

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

Q1 2013 Financial Statements |1

SONDE RESOURCES CORP. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) For the three months ended March 31	Note	2013	2012
(CDN$ thousands, except per share amounts) (Unaudited)
Revenue
Revenue, net of royalties	9	6,784	7,249
Gain on commodity derivatives	6	--	84
		6,784	7,333
Expenses
Operating	10	4,218	4,313
Transportation		177	196
Exploration and evaluation	3	1,955	886
General and administrative		2,824	2,836
Depletion and depreciation	3	2,537	3,095
Share based compensation	4	310	322
Property, plant and equipment impairment	3	--	12,880
		12,021	24,528
Operating loss		(5,237)	(17,195)

Other
Financing costs	8	(189)	(258)
Gain (loss) on foreign exchange		22	(447)
Other income		23	30
Gain on disposition of exploration and evaluation assets	3	--	73,361
Loss on disposition of property, plant and equipment	3	(31)	--
		(175)	72,686
(Loss) income before taxes		(5,412)	55,491
Current income taxes		--	35
Net (loss) income		(5,412)	55,456

Other comprehensive income (loss)
Foreign currency translation adjustment		975	(890)
Total comprehensive (loss) income		(4,437)	54,566

Net (loss) income per common share
Basic and diluted (loss) income per common share	11	(0.09)	$0.89

See accompanying notes to the condensed consolidated financial statements

Q1 2013 Financial Statements |2

SONDE RESOURCES CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the three months ended March 31	Note	2013	2012
(CDN$ thousands) (Unaudited)
Cash (used in) provided by:
Operating
Net (loss) income		(5,412)	55,456
Items not involving cash:
Depletion and depreciation	3	2,537	3,095
Share based compensation	4	310	322
Exploration and evaluation	3	1,955	886
Property, plant and equipment impairment	3	--	12,880
Unrealized (gain) on commodity derivatives	6	--	(151)
Unrealized (gain) loss on foreign exchange		(65)	45
Financing costs	8	189	258
Gain on disposition of exploration and evaluation assets	3	--	(73,361)
Loss on disposition of property, plant and equipment	3	31	--
Interest paid		(17)	(97)
Changes in non-cash working capital	13	1	1,094
		(471)	427
Financing
Exercise of restricted share units	4	--	(85)
Exercise of stock unit awards	4	(165)	--
Revolving credit facility repayments		--	(23,400)
Revolving credit facility advances		--	23,400
		(165)	(85)
Investing
Property, plant and equipment additions	3	(1,020)	(4,613)
Exploration and evaluation additions	3	(1,005)	(6,188)
Proceeds on disposition of exploration and evaluation assets	3	--	74,979
Proceeds on disposition of property, plant and equipment	3	296	--
Changes in non-cash working capital	13	(626)	(20,156)
		(2,355)	44,022
(Decrease) increase in cash and cash equivalents		(2,991)	44,364
Effect of foreign exchange on cash and cash equivalents		65	(45)
Cash and cash equivalents, beginning of period		19,695	3,743
Cash and cash equivalents, end of period	5	16,769	48,062

See accompanying notes to the condensed consolidated financial statements

Q1 2013 Financial Statements |3

SONDE RESOURCES CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(CDN$ thousands) (Unaudited)	Share capital	Contributed surplus	Foreign currency translation	Deficit	Total
At December 31, 2011	369,892	33,528	550	(277,041)	126,929
Total comprehensive (loss) gain	--	--	(890)	55,456	54,566
Stock option expense	--	242	--	--	242
At March 31, 2012	369,892	33,770	(340)	(221,585)	181,737

(CDN$ thousands) (Unaudited)	Share capital	Contributed surplus	Foreign currency translation	Deficit	Total
At December 31, 2012	369,892	34,290	(34)	(255,558)	148,590
Total comprehensive gain (loss)	--	--	975	(5,412)	(4,437)
Stock option expense	--	307	--	--	307
At March 31, 2013	369,892	34,597	941	(260,970)	144,460

See accompanying notes to the condensed consolidated financial statements

Q1 2013 Financial Statements |4

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2013

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

(Unaudited)

1.	Reporting entity

	Sonde Resources Corp. (“Sonde” or the “Company”) is a Canadian based energy company with its head office located at Suite 3100, 500 – 4th Avenue S.W., Calgary, Alberta and its registered office located at Suite 3700, 400 – 3rd 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. At present, all of the Company’s revenues are generated from its operations in Western Canada.

	The condensed consolidated financial statements (the “Financial Statements”) comprise the Company and its subsidiaries, all of which are wholly owned. 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 presentation

	(a)	Statement of compliance

	The Financial Statements are prepared in accordance with International Accounting Standards 34 Interim Financial Reporting (“IAS 34”) and present the Company’s results of operations and financial position under International Financial Reporting Standards (“IFRS”) as at March 31, 2013 and December 31, 2012 and for the three month periods ended March 31, 2013 and 2012.

	The Financial Statements were approved and authorized for issue by the Board on May 6, 2013.

	(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 three months ended March 31, 2013, the Company had an operating loss of $5.2 million and an accumulated deficit of $261.0 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 substantial doubt over the Company’s ability to continue as a going concern. If this assumption is 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, 2012. On January 1, 2013, the Company adopted IFRS 10, 11, 12 and 13; the adoption of which did not have a material impact on the Financial Statements. 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, 2012.

	(d)	Functional and presentation currencies

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

	(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 and such differences may be material.

Q1 2013 Financial Statements |5

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

	Three months ended March 31, 2013									Year ended December 31, 2012
	Cost			Accum. DD&A			Carrying value			Cost			Accum. DD&A			Carrying value
Exploration and evaluation assets
Beginning of period		79,234			(22,735	)		56,499			69,015			--			69,015
Additions		1,005			--			1,005			13,696			--			13,696
Dispositions		--			--			--			(1,647	)		--			(1,647	)
Farm-out proceeds		--			--			--			(995	)		--			(995	)
Impairments, to exploration expense		--			(1,955	)		(1,955	)		--			(22,735	)		(22,735	)
Foreign exchange		938			--			938			(835	)		--			(835	)
End of period		81,177			(24,690	)		56,487			79,234			(22,735	)		56,499

Property, plant and equipment
Beginning of period		239,124			(134,980	)		104,144			212,453			(107,708	)		104,745
Additions		1,020			--			1,020			23,506			--			23,506
Dispositions		(327	)		--			(327	)		--			--			--
Change in decommissioning obligations		9			--			9			3,165			--			3,165
Depreciation and depletion		--			(2,537	)		(2,537	)		--			(11,031	)		(11,031	)
Impairments		--			--			--			--			(16,241	)		(16,241	)
End of period		239,826			(137,517	)		102,309			239,124			(134,980	)		104,144

	(a)	Western Canada exploration and evaluation assets

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

	During the three months ended March 31, 2013 the Company capitalized $0.8 million (March 31, 2012 – $0.9 million) of general and administrative expenses related to exploration and evaluation activities in North Africa ($0.7 million) and Western Canada ($0.1 million).

	On February 8, 2012, the Company completed the sale to an unrelated third party 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 exploration and evaluation 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.

	Land expiries and impairment on Western Canada exploratory wells charged to exploration and evaluation expense during the three months ended March 31, 2013 totaled $0.2 million (March 31, 2012 – $0.9 million). As at March 31, 2013, no indicators of impairment were identified in Western Canada that would imply a further decline in exploration and evaluation asset carrying values.

	(b)	North Africa exploration and evaluation assets

	Prior to the events that occurred in December, 2012 described below, there was a great deal of uncertainty regarding the future development of the North Africa assets. The key items that contributed to this uncertainty were development costs, exploratory well obligations, the unit plan of development and the inert and acid gas initiative, as discussed in Note 7 (a).

	Due to this uncertainty, the Company evaluated the fair value of the Joint Oil Block as described below. The Company utilized a Swanson’s mean probability-weighted discounted cash flow analysis over the life of the project, estimated to be 2012 – 2032, prepared by an independent evaluator, to determine fair value of the North Africa assets.

Q1 2013 Financial Statements |6

	This analysis assumed a wide range of potential future outcomes and a series of outcomes were modeled for each variable. All of the factors could individually influence the fair value.

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

	The most significant assumptions used in the determination of the fair value included:

	·	the estimated low to medium probability of finding a commercial solution to the Inert and Acid Gas Initiative, which could have had an adverse or positive impact on the valuation;

	·	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 included in 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, actual reserves ultimately discovered, if any, and the production, if any, from such discoveries may have been materially different than expected;

	·	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; and

	·	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 (a), each with substantial uncertainties, and the interdependency of factors, the Company was unable to identify the sensitivities associated with individual factors. A number of the potential scenarios resulted in no value for the North African assets; however as of the date of the valuation management did not believe that they were the most probable outcomes and using the above described methodology and assumptions, the fair value of the North Africa assets was determined by the third party valuation firm to be $45.1 million less costs to sell of $0.4 million (which management determined was the most probable value in a range of possible values). This valuation resulted in the Company booking an impairment loss of $21.0 million during the year ended December 31, 2012.

	On December 27, 2012, the Company entered into a farm-out agreement with Viking Energy North Africa Limited (“Viking”). The commercial terms of the farm-out agreement are discussed in Note 7 (b). The farm-out and the revised unit plan of development, which is subject to approval from Joint Oil, will, if approved, result in a new development plan that will change the method of development, the costs and the production profile. Based on that fact, the Company evaluated whether the impairment recorded on the Joint Oil Block should be reversed or if further impairment was necessary.

	The commercial terms of the farm-out agreement indicate that the recoverable amount for the North Africa E&E asset may exceed carrying value; however, management does not feel it is appropriate to reverse the previous impairment charges until the farm-out with Viking is approved by Joint Oil and the transaction formally closes. The Company has concluded that since there have been no changes to the facts and circumstances since December 31, 2012, the methodology employed during the year ended December 31, 2012 is the Company’s best estimate of fair value. As such, all costs capitalized from January 1, 2013 to March 31, 2013 have been booked to exploration and evaluation expense.

	(c)	Property, plant and equipment

	During the three months ended March 31, 2013, the Company disposed of facilities with a net book value of $0.4 million for proceeds of $0.3 million, for a loss of $0.1 million (March 31, 2012 – nil).

	An impairment test is performed on capitalized property plant 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 March 31, 2013. During the three months ended March 31, 2012, Sonde recorded an impairment of $12.9 million ($9.7 million in the Southern Alberta CGU, $2.4 million in the Central Alberta CGU, and $0.8 million in the Northern Alberta CGU) to reflect low natural gas prices. Impairments recognized during the three months ended March 31, 2012 were calculated using a 12% discount rate. Using a discount rate of 10% would reduce the 2012 impairment by $8.5 million. Using a discount rate of 15% would increase the 2012 impairment by $10.4 million.

Q1 2013 Financial Statements |7

4.	Share based compensation

	(a)	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 82,429 shares with a value of $0.1 million on the open market under the ESSP during the three months ended March 31, 2013 (March 31, 2012 – 51,890 shares with a value of $0.1 million). The costs related to this plan are recorded as general and administrative expense as incurred.

	(b)	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 at the date of the grant.

For the years ended	March 31, 2013					December 31, 2012
	Number of options			Weighted average exercise price		Number of options			Weighted average exercise price
($ thousands, except per share price)
Balance, beginning of period		4,728		$	2.40		2,974		$	3.43
Granted		--			--		2,504			1.37
Exercised		--			--		--			--
Forfeited		(90	)		2.71		(750	)		3.03
Balance, end of period		4,638			2.40		4,728			2.40

The following table summarizes stock options outstanding under the plan at March 31, 2013:

	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 ($)
0.75 – 2.50		2,318		4.22		1.32		338		1.55
2.51 – 3.00		552		3.16		2.85		263		2.86
3.01 – 4.00		995		7.39		3.10		990		3.09
4.01 – 11.80		773		7.69		4.40		713		4.41
0.88 – 11.80		4,638		5.35		2.40		2,304		3.25

	There were no options granted during the three months ended March 31, 2013. No stock based compensation expense was capitalized during 2013 or 2012.

	(c)	Stock unit awards

	At March 31, 2013 the Company had 1.1 million (December 31, 2012 – 1.2 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. As of March 31, 2013, the Company recorded a liability of $0.8 million to recognize the fair value of the vested stock units (December 31, 2012 - $0.9 million).

	During the three months ended March 31, 2013, the Company paid $0.2 million to settle awards held by current and former directors (March 31, 2012 - nil).

Q1 2013 Financial Statements |8

4.	Share based compensation (continued)

	(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. During the three months ended March 31, 2013, no RSUs were redeemed (March 31, 2012, 33,333 RSUs were redeemed for a total of $0.1 million). The following table summarizes RSUs outstanding under the plan at March 31, 2013:

	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		0.67		2.56		101		3.00
3.01 – 3.50		3		0.79		3.27		2		3.27
3.51 – 3.64		9		0.79		3.64		6		3.64
0.00 – 3.64		241		0.67		2.61		109		3.04

RSUs issued were initially valued at the grant date and revalued at March 31, 2013, using a binomial lattice model with weighted average assumptions as follows:

	Valuation at March 31, 2013		Valuation at grant date
Share price ($)		1.40		2.55
Risk free rate (%)		1.0		1.0
Expected life (years)		0.67		2.53
Expected volatility (%)		55		55
Weighted average fair value ($)		0.66		1.99

The following table summarizes the share based compensation liability:

	March 31 2013		December 31 2012
Stock unit award liability		769		909
Restricted share unit liability		143		165
Share based compensation liability		912		1,074

The following table summarizes share based compensation expense:

For the three months ended March 31	2013			2012
Stock option expense		307			242
Stock unit award expense		26			123
Restricted share unit gain		(23	)		(43	)
		310			322

Q1 2013 Financial Statements |9

5.	Financial instruments

	The Company uses a fair value hierarchy, discussed in Note 3 (g) of the December 31, 2012 financial statements, to categorize the inputs used to measure the fair value of its financial instruments. At March 31, 2013, all fair value measurements related to the Company’s financial instruments were categorized as level 1 in the fair value hierarchy. Cash and cash equivalents, stock unit awards, restricted share units, and derivatives, which include commodity contracts, are designated at fair value through profit or loss. Gains or losses related to periodic revaluation at each reporting period are recorded in net income or loss.

	Accounts receivable are classified as loans and receivables and are initially measured at their fair value. Accounts payable and accrued liabilities, provisions, demand loans and revolving credit facilities are classified as other liabilities and are initially measured at fair value. Subsequently, loans and receivables and other liabilities are recorded at amortized cost using the effective interest method. The carrying value of cash and cash equivalents, accounts receivable, provisions, accounts payable and accrued liabilities approximate fair value due to the short term nature of those instruments.

	At March 31, 2013, cash and cash equivalents were comprised of $8.3 million in short term investment instruments and $8.5 million of cash held at financial institutions (December 31, 2012 – $10.0 million in short term investment instruments and $9.7 million of cash held at financial institutions).

6.	Risk Management

	(a)	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 sold a call option on a portion of the Company’s oil production from March 2011 through December 2012. The Company did not hold any such instruments at March 31, 2013. The gains and losses associated with this instrument are as follows:

For the three months ended

March 31, 2013

March 31, 2012

Term

Contract

Volume

Fixed Price

Realized

gain (loss)

Unrealized

gain (loss)

Realized (loss)

Unrealized gain

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($67)

$151

	(b)	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 March 31, 2013 or December 31, 2012. The Company’s exposure to fluctuations in interest expense assuming reasonably possible changes in the variable interest rate of +/- 1%, is insignificant. This analysis assumes all other variables remain constant.

	(c)	Capital management

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

	·	maintain a flexible capital structure which optimizes the costs of capital at an acceptable level of risk;

	·	maintain sufficient liquidity to support ongoing operations, capital expenditure programs, strategic initiatives; and

	·	maximize shareholder returns.

	The Company manages its capital structure to support current and future business plans and periodically adjusts the structure in response to changes in economic conditions and the risk characteristics of the Company’s underlying assets and operations. The Company monitors metrics such as the Company’s debt-to-equity and debt-to-cash flow ratios, among others to measure the status of its capital structure. The Company has currently not established fixed quantitative thresholds for such metrics.

Q1 2013 Financial Statements |10

6.	Risk Management (continued)
	Depending on market conditions, the Company’s capital structure may be adjusted by issuing or repurchasing shares, issuing or repaying debt, refinancing existing debt, modifying capital spending programs and disposing of assets. The Company considers its capital structure to include shareholder’s equity and debt. The Company’s capital structure consists of the following:

	March 31 2013			December 31 2012
Share capital		369,892			369,892
Contributed surplus		34,597			34,290
Foreign currency translation reserve		941			(34	)
Deficit		(260,970	)		(255,558	)
Total capital		144,460			148,590

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

	March 31		December 31
	2013		2012
(US$ thousands) Cash and cash equivalents		2,291		2,184
North Africa receivables		1		1
Foreign denominated financial assets		2,292		2,185

North Africa payables		471		566
Foreign denominated financial liabilities		471		566

	These balances are exposed to fluctuations in the Canadian and U.S. dollar exchange rate. 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, assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent is insignificant. This analysis assumes all other variables remain constant.
	(e)	Liquidity risk
	The Company generally relies on a combination of cash flow from operating activities and credit facility availability to fund its capital requirements and to provide liquidity for all operations.

	(f)	Credit risk
	The Company’s allowance for doubtful accounts is currently $1.7 million (December 31, 2012 – $1.7 million). This amount offsets $1.8 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2012 – $1.8 million). The Company considers all amounts greater than 90 days to be past due. As at March 31, 2013, $0.9 million of accounts receivable are past due, all of which are considered to be collectible (December 31, 2012 - $0.9 million). The Company’s credit risk exposure is as follows:

	March 31		December 31
(CDN$ thousands)	2013		2012
Western Canada joint interest billings		2,033		2,310
Revenue accruals and other receivables		2,600		2,373
Accounts receivable		4,633		4,683
Cash and cash equivalents		16,769		19,695
Maximum credit exposure		21,402		24,378

Q1 2013 Financial Statements |11

7.	Contingencies and commitments
	(a)	North Africa Exploration and Production Sharing Agreement (“EPSA”)
	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.
	The Company recorded an impairment of $21.0 million to the Joint Oil Block during the year ended December 31, 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 will ensure that the Zarat Development and other developments in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments with international organizations such as the Kyoto Accord on greenhouse gas emissions. This study is anticipated to take eighteen months.
	·	Drilling Rig Availability – The Company’s initial assessment indicated that the global demand for offshore drilling units was 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 would have been available in the second quarter of 2013. The commercial terms of their offer were unacceptable to the Company. See note 7 (c).
	·	Unitization and Plan of Development – The Company 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 the Company could demonstrate to the market an asset with an approved Exploitation Plan. However, Joint Oil 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. In addition, the farm-out to Viking will impact the timing and potential unit development plans. As a result, the Company expected approval of its Zarat Plan of Development to be delayed for the near term.
	·	Exploratory Well Obligations – The Company planned 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 could 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. As discussed in Note 7 (b), on December 24, 2012 the Company received an extension on its exploratory well obligations until December 23, 2015.

Q1 2013 Financial Statements |12

7.	Contingencies and commitments (continued)
	(b)	North Africa exploratory well extension and farm-out
	On December 24, 2012, Joint Oil approved the extension of the first phase of the exploration period under the EPSA to December 23, 2015. The extension provides for the drilling of three exploration wells, one each year, due December 23, 2013, 2014 and 2015. Penalties for non-fulfillment of the minimum work program are US$15.0 million for each well. In addition, the extension provides for the acquisition and processing of 200 square kilometers of 3D seismic in the Libyan sector of the Joint Oil Block, beginning in the second quarter of 2013.
	On December 27, 2012, the Company entered into a farm-out agreement with Viking covering the Joint Oil Block. The farm-out agreement contains the following terms:
	·	Viking will pay Sonde in total a US$3.0 million non-refundable signature bonus. As at December 31, 2012, US$1.0 million of the signature bonus had been received by the Company and credited against exploration and evaluation assets, with the remaining US$2.0 million due upon formal closing;
	·	Viking will assume responsibility for the three well exploration commitment under the terms of the EPSA and fund 100% of the Joint Oil Block share of the Unit Plan of Development for the Zarat Field. The first well, Fisal, is to be drilled in 2013 along with the acquisition of 3D seismic data in Libyan waters;
	·	Viking will provide to Sonde, prior to closing, the appropriate form of corporate guarantee with the agreed upon commercial terms from one of their affiliated companies, in order to secure the remaining work commitment under the terms of the EPSA;
	·	Sonde will receive 20% of the cost recovery and profit share revenue until Sonde recovers US$70 million. After payout of all Sonde and Viking expenditures, the revenue will be split 33.33% to Sonde and 66.67% to Viking;
	·	Sonde retains the option to fund its 33.33% share of the last two of the exploration wells; and
	·	Any future discoveries will be shared 33.33% to Sonde and 66.67% to Viking.
	This pending farm-out is subject to the following conditions:
	·	Viking (or one of its affiliates) provides Sonde with a corporate guarantee sufficient to offset the current US$45.0 million guarantee for the potential penalties in respect of the three well drilling commitment and 3D seismic; and
	·	Joint Oil consents to the transfer of the interest to Viking as a second party to the EPSA and the naming of Viking as Operator of the Joint Oil Block under the EPSA.
	Whether the transaction with Viking closes or not is uncertain. This uncertainty casts substantial doubt about the Company’s ability to continue as a going concern. The Company has submitted the farm-out to Joint Oil for approval which was conditionally received on May 3, 2013, as discussed in Note 15 – Subsequent event. The farm-out agreement can be terminated after June 7, 2013 unless extended by mutual consent.
	The public and private debt and equity markets remain inaccessible for exploratory or development projects on the Joint Oil Block and the Company’s Western Canadian operations will not provide sufficient cash flows to meet the exploratory commitments. Without access to the funding this transaction provides or third party funding, the Company may not be able to continue as a going concern.

Q1 2013 Financial Statements |13

7.	Contingencies and commitments (continued)
	(c)	Commitments and financial liabilities
	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. At March 31, 2013, the Company has committed to future payments over the next five years and thereafter, as follows:

	2013		2014			2015			2016			2017			Thereafter			Total
Accounts payable and accrued liabilities		6,198		--			--			--			--			--			6,198
Share based compensation liability		912		--			--			--			--			--			912
North Africa exploration commitments (note 7 (a), (b))		16,866		15,240			15,240			--			--			--			47,346
Office rent payable		909		1,212			1,217			1,233			1,233			5,925			11,729
Office rent receivable		--		(405	)		(1,014	)		(1,233	)		(1,233	)		(5,925	)		(9,810	)
		24,885		16,047			15,443			--			--			--			56,375

	(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 sufficient to address any future claims as to matters insured.
8.	Short term debt and financing costs
	As at March 31, 2013, the Company had issued three letters of credit for $0.2 million (December 31, 2012 – three letters of credit for $0.2 million) against the $30.0 million (December 31, 2012 - $30.0 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 of 1:1 or greater and to ensure that non-domestic general and administrative and capital expenditures are funded from cash flow, equity and proceeds from foreign asset sales. The Company can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility.
	As at March 31, 2013, the Company was in compliance with all of its debt covenants. The Company is subject to a semi-annual review of its credit facilities on or before July 1, 2013.
	Financing costs for the Company were as follows:

For the three months ended March 31	2013	2012
Accretion of decommissioning provision	172	161
Interest on credit facilities	17	97
	189	258

Q1 2013 Financial Statements |14

9.	Revenue
	The following summarizes the Company’s revenue:

For the three months ended March 31	2013			2012
Petroleum and natural gas sales		7,249			8,429
Royalties		(465	)		(1,180	)
		6,784			7,249

10.	Operating expense
	Operating costs for the Company are as follows:

For the three months ended March 31	2013		2012
Operating		3,626		3,836
Well workovers		592		477
		4,218		4,313

11.	Share capital
	The number of common and preferred shares authorized, each with no par value, is unlimited.
	For the three months ended March 31, 2013 and March 31, 2012, the basic weighted average common shares outstanding was 62,301,446. For the three months ended March 31, 2013, the diluted weighted average common shares outstanding was 62,938,384 (March 31, 2012 – 62,301,446). The Company excluded 4.6 million options that are anti-dilutive for the three months ended March 31, 2013 (March 31 31, 2012 – 1.8 million) in the calculation of diluted earnings per share.
12.	Related party transactions
	During the three months ended March 31, 2013, in the normal course of business, the Company purchased $0.1 million of processing services (March 31, 2012 – $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 March 31, 2013 and December 31, 2012, there were no amounts outstanding in accounts payable to this service provider.
13.	Supplemental cash flow information
	The changes in non-cash working capital are as follows:

For the three months ended March 31	2013			2012
Accounts receivable		50			2,284
Prepaid expenses and deposits		(60	)		(193	)
Accounts payable and accrued liabilities		(652	)		(8,680	)
Provisions		--			(12,718	)
Foreign currency translation adjustment		37			245
Change in non-cash working capital		(625	)		(19,062	)

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

For the three months ended March 31	2013			2012
Operating		1			1,094
Investing		(626	)		(20,156	)
Change in non-cash working capital		(625	)		(19,062	)

Q1 2013 Financial Statements |15

14.	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.
	The statements of operations for the three months ended March 31, 2013 and March 31, 2012 by operating segment are as follows:

For the three months ended March 31	Western Canada			North Africa			Total 2013			Western Canada			North Africa		Total 2012
Revenue
Revenue, net of royalties		6,784			--			6,784			7,249			--		7,249
Gain on commodity derivatives		--			--			--			84			--		84
		6,784			--			6,784			7,333			--		7,333
Expenses
Operating		4,218			--			4,218			4,313			--		4,313
Transportation		177			--			177			196			--		196
Exploration and evaluation		167			1,788			1,955			886			--		886
General and administrative		2,824			--			2,824			2,836			--		2,836
Depletion and depreciation		2,537			--			2,537			3,095			--		3,095
Share based compensation		310			--			310			322			--		322
Property, plant and equipment impairment		--			--			--			12,880			--		12,880
		10,233			1,788			12,021			24,528			--		24,528
Operating loss		(3,449	)		(1,788	)		(5,237	)		(17,195	)		--		(17,195	)
Other
Financing costs		(189	)		--			(189	)		(258	)		--		(258	)
Gain (loss) on foreign exchange		22			--			22			(447	)		--		(447	)
Other income		23			--			23			30			--		30
(Loss) gain on disposition of exploration and evaluation assets		(31	)		--			(31	)		73,361			--		73,361
		(175	)		--			(175	)		72,686			--		72,686
(Loss) income before income taxes		(3,624	)		(1,788	)		(5,412	)		55,491					55,491
Current income taxes		--			--			--			35			--		35
Net (loss) income		(3,624	)		(1,788	)		(5,412	)		55,456			--		55,456

Q1 2013 Financial Statements |16

14.	Segments and cash generating units (continued)
	The statements of financial position by operating segment as at March 31, 2013 and December 31, 2012 are as follows.

	Western Canada		North Africa		Total – As at Mar. 31, 2013		Western Canada		North Africa		Total – As at Dec. 31, 2012
(CDN$ thousands)
Assets
Current
Cash and cash equivalents		15,366		1,403		16,769		18,024		1,671		19,695
Accounts receivable		4,632		1		4,633		4,682		1		4,683
Prepaid expenses and deposits		750		21		771		714		19		733
		20,748		1,425		22,173		23,420		1,691		25,111
Long term portion of prepaid expenses and deposits		754		--		754		732		--		732
Exploration and evaluation assets		11,868		44,619		56,487		11,799		44,700		56,499
Property, plant and equipment		102,309		--		102,309		104,144		--		104,144
Total assets		135,679		46,044		181,723		140,095		46,391		186,486
Liabilities
Current
Accounts payable and accrued liabilities		5,719		479		6,198		6,288		562		6,850
Share based compensation liability		912		--		912		1,074		--		1,074
		6,631		479		7,110		7,362		562		7,924
Decommissioning provision		30,153		--		30,153		29,972		--		29,972
Total liabilities		36,784		479		37,263		37,334		562		37,896

15.	Subsequent event

	On May 3, 2013, Sonde has received approval from Joint Oil’s Board of Directors to farm out 66.67% of its potential Zarat Field Exploration Area and 50% of the remainder of its interest in the Joint Oil Block to Viking. In order to receive Joint Oil approval, certain terms of the farm-out agreement described in our December 31, 2012 audited financial statements are required to be amended. The amendments to the farm-out agreement are summariezed below. Joint Oil’s approval of the assignment to Viking is subject to approval of the definitive form of Assignemnt Agreement and format of the Bank Guarantee (discussed below). Completion of the assignment will require the execution of the definitve amendment to the farm-out agreement with Viking and closing of the farm-out. Viking has agreed to the conditions.

	The amendments to the original farm-out agreement are as follows:

	·	Sonde will remain the operator of the Joint Oil Block;

	·	Sonde and Viking will post a bank guarantee equivalent to US$50.995 million as a guarantee for the 2013 through 2015 work obligations the (“Bank Guarantee”). Viking will contribute US$40 million to the guarantee and Sonde will contribute US$10.995 million (the “Balance”) to the guarantee. Amounts under the Bank Guarantee will be released in accordance with a pre-determined formula as the work obligations are performed;

	·	Viking will acquire a 66.67% participating interest and Sonde will retain a 33.33% participating interest in the Zarat Field Exploitation Area;

	·	In consideration for contributing the Balance, Sonde will retain a 50% participating interest in the Joint Oil Block that is not covered by the exploitation area around the Zarat Field development. In addition, Sonde will recover the Balance from the initial proceeds from Zarat Field production in preference to the other terms of the farm-out; and

	·	Any future discoveries will be shared 50% to Sonde and 50% to Viking.

	Sonde and Viking are in the process of completing the necessary documentation to effect amendments to the farm-out agreement prior to the June 7th expiry date.

Q1 2013 Financial Statements |17

Document 2

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") has been prepared by management as of May 6, 2013, and reviewed and approved by the Board of Directors (the “Board”) of Sonde Resources Corp. (“Sonde” or the “Company”).

Effective January 1, 2011 the Company adopted International Financial Reporting Standards (“IFRS”). This MD&A should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ended December 31, 2012 and 2011.

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 IFRS as issued by the International Accounting Standards Board and are therefore non-IFRS financial measures that do not have any standardized meaning prescribed by IFRS and are, therefore, unlikely to be comparable to similar measures presented by other issuers.

Management of the Company believes funds from (used for) operations, funds from (used for) operations per share and operating netback are relevant indicators of the Company’s financial performance, ability to fund future capital expenditures and repay debt. Funds from (used for) operations and operating netback should not be considered an alternative to or more meaningful than cash flow from operating activities, as determined in accordance with IFRS, as an indicator of the Company's performance.

In the operating netback and funds from (used for) operations section of this MD&A, reconciliation has been prepared of funds from (used for) operations and operating netback to cash (used in) provided by operating activities, the most comparable measure calculated in accordance with IFRS.

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:

the anticipated closing of the farm-out to Viking Energy North Africa Limited (“Viking”);

expected sources of funding for the capital program, including the completion of the farm-out with Viking which, upon closing, is anticipated to reduce the Company’s work commitments;

the ability to locate and secure an offshore drilling rig for the Fisal exploration well in North Africa;

the proposed unitization of the Zarat field and development of an amended Zarat field unit plan of development;

business strategy, plans, priorities and planned exploration and development activities;

exploration potential relating to the Company’s Western Canadian properties, including horizontal drilling opportunties in the Duvernay, Montney and Wabamun plays;

the possible results of Sonde’s strategic alternatives process in Western Canada and the impact it may have on sources of funding for future exploration and development activities;

expected volume and product mix of the Company's oil and gas production and future oil and gas prices and interest rates in respect of the Company's commodity risk management programs;

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

the Company's tax pools.

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

Q1 2013 MD&A|1

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 estimates, reserves life and underlying reservoir risk;

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

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

delays due to adverse weather conditions;

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

the outcome and effects of any future acquisitions and dispositions;

health, safety and environmental risks;

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

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

risks associated with competition from other producers;

changes in general economic and business conditions;

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

the outcome of the Inert and Acid Gas Initiative and the impact on the Company’s financing abilities relating to its North African obligations;

commercial risks relating to the closing of the Viking farm-out agreement and the negotiation of the proposed unitization of the Zarat field; and

general economic, market and business conditions.

The foregoing list of risk factors is not exhaustive. Additional information on these and other factors which could affect the Company’s operations or financial results are included in the Company’s most recent Annual Information Form. In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission. Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is presented. The Company assumes no obligation to update forward-looking information should circumstances or management’s estimates or opinions change, except as required by law. Statements contained in this document relating to estimates, results, events and expectations are forward-looking statements within the meaning of Section 27A of the United States Securities Act of 1933, as amended and Section 21E of the United States Securities Exchange Act of 1934, as amended.

These forward-looking statements involve known and unknown risks, uncertainties, scheduling, re-scheduling and other factors which may cause the actual results, performance, estimates, projections, resource potential and/or reserves, interpretations, prognoses, schedules or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such statements. Such factors include, among others, those described in the Company’s’ annual reports on Form 40-F or Form 20-F on file with the U.S. Securities and Exchange Commission.

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 boe 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”) or million cubic feet (“mmcf”). Oil and natural gas liquids are expressed in barrels (“bbls”) or thousands of barrels (“mbbls”).

Q1 2013 MD&A|2

Business Overview and Strategy

Sonde is a Calgary, Alberta, Canada based energy company engaged in the exploration for and production of oil and natural gas. The Company’s operations are located in Western Canada and offshore North Africa.

Western Canada

The Company derives all of its production and cash flow from operations in Western Canada. The Company’s Southern Alberta cash generating unit (“CGU”), (or Greater Drumheller, Alberta area), accounts for approximately 84% of the Company’s production. The balance of production comes largely from the Kaybob/Windfall and Boundary Lake/Eaglesham areas in west-central Alberta. The Company’s Western Canadian oil and gas assets are primarily high potential, high working interest producing properties which are complemented by a portfolio of highly prospective undeveloped land positions throughout Greater Alberta.

Western Canada Strategic Alternatives Process

On January 9, 2013, Sonde announced that it had retained FirstEnergy Capital Corp. (“FirstEnergy”) to initiate a process to explore and evaluate potential strategic alternatives to enhance shareholder value with regard to Sonde’s Western Canadian production and exploratory acreage. As financial advisor to the Board of Directors of Sonde, FirstEnergy is assisting in the process of analyzing and evaluating prospects and options available to the Company, which may include, among other alternatives, a sale of all or a material portion of the Western Canadian assets of the Company, a strategic investment in Sonde’s undeveloped acreage, a joint venture, or a merger or other business combination involving Sonde.

2013 Western Canada Drilling Program

No wells were drilled during the three months ended March 31, 2013 due to the strategic alternatives process discussed above.

During the three months ended March 31, 2013, Sonde continued its well re-activation program concentrated on an extensive portfolio of suspended wells. Sonde performed 14 net workovers and recompletions during the three months ended March 31, 2013.

North Africa

On December 27, 2012, the Company entered into a farm-out agreement with Viking covering the Joint Oil Block. The farm-out agreement contains the terms outlined under section (b) of Contingencies and Commitments “North Africa exploratory well extension and farm-out”. As of the date hereof, the farm-out agreement has not closed and completion of this transaction is subject to a number of conditions. The farm-out agreement can be terminated after June 7, 2013 unless extended by mutual consent.

The success of the Company’s ongoing operations are dependent upon a number of factors, including but not limited to, the price of energy commodity products, the Company’s ability to manage price volatility, increasing production and related cash flows, controlling costs, availability of experienced service industry personnel and equipment, capital spending allocations, the ability to attract equity investment, the results of Sonde’s Western Canada strategic alternatives process, hiring and retaining qualified personnel and managing political risk, particularly with respect to its interests in North Africa.

Q1 2013 MD&A|3

Operating netback and funds used for operations

	($ thousands)									($ per boe)
Three months ended March 31	2013			2012			% change			2013			2012			% change
Petroleum and natural gas sales		7,249			8,429			(14	)		39.12			33.73			16
Realized loss on financial instruments		--			(67	)		(100	)		--			(0.27	)		(100	)
Transportation		(177	)		(196	)		(10	)		(0.96	)		(0.78	)		23
Royalties		(465	)		(1,180	)		(61	)		(2.51	)		(4.72	)		(47	)
		6,607			6,986			(5	)		35.65			27.96			28
Operating expense		(3,626	)		(3,836	)		(5	)		(19.57	)		(15.35	)		27
Well workover expense		(592	)		(477	)		24			(3.19	)		(1.91	)		67
Operating netback(1)		2,389			2,673			(11	)		12.89			10.70			20
General and administrative		(2,824	)		(2,836	)		--			(15.24	)		(11.35	)		34
Foreign exchange loss		(43	)		(402	)		(89	)		(0.23	)		(1.61	)		(86	)
Interest and other income		23			30			(23	)		0.12			0.12			--
Interest expense		(17	)		(97	)		(82	)		(0.09	)		(0.39	)		(77	)
Income taxes		--			(35	)		(100	)		--			(0.14	)		(100	)
Funds used for operations(1)		(472	)		(667	)		(29	)		(2.55	)		(2.67	)		(4	)
Changes in non-cash working capital		1			1,094			(100	)		0.01			4.38			(100	)
Cash (used in) provided by operating activities		(471	)		427			(210	)		(2.54	)		1.71			(249	)

(1)	Non-IFRS measure.

For the three months ended March 31, 2013, funds used for operations was $0.5 million compared to funds used for operations of $0.7 million for the same period in 2012. This was primarily the result of a 14% reduction in petroleum and natural gas revenue, consistent operating expense and a 24% increase in well workover expense incurred to address normal wear and tear on older wells.

Production

	Q1	Q4	Q1
Commodity	2013	2012	2012
Natural gas (mcf/d)	7,934	8,940	11,553
Crude oil (bbls/d)	549	572	565
Natural gas liquids (bbls/d)	188	189	255
Total production (boe/d) (6:1)	2,059	2,251	2,746

	Q1	Q4	Q1
Region	2013	2012	2012
Southern Alberta (boe/d)	1,738	1,907	2,129
Central Alberta (boe/d)	190	203	408
Other Western Canada (boe/d)	131	141	209
Total production (boe/d) (6:1)	2,059	2,251	2,746

For the three months ended March 31, 2013, production averaged 2,059 boe/d, compared to 2,251 boe/d for the three months ended December 31, 2012 and 2,746 boe/d for the three months ended March 31, 2012. The decrease in production during the three months ended March 31, 2013 compared to the three months ended December 31, 2012 and March 31, 2012 is due to natural decline, significant third-party natural gas processing plant outages in Central Alberta and constrained capex due to the Western Canada strategic alternatives process.

Q1 2013 MD&A|4

Petroleum and natural gas sales

	Q1		Q4		Q1
($ thousands, except where otherwise noted)	2013		2012		2012
Petroleum and natural gas sales
Natural gas	2,354		2,882		2,314
Crude oil	3,929		3,834		4,673
Natural gas liquids	966		978		1,442
Transportation	(177	)	(139	)	(196	)
Royalties	(465	)	(763	)	(1,180	)
Realized gain (loss) on commodity derivatives	--		--		(67	)
Total	6,607		6,792		6,986
Average sales price (including commodity derivatives)
Natural gas ($/mcf)	3.30		3.50		2.20
Crude oil ($/bbl)	79.58		72.69		89.54
Natural gas liquids ($/bbl)	57.03		56.35		62.08
Average sales price ($/boe)	39.12		37.14		33.47
AECO 5a ($/mcf)	3.13		3.59		2.31
Edmonton Light ($/bbl)	87.71		84.25		93.11

For the three months ended March 31, 2013, petroleum and natural gas sales, net of transportation and royalties, was $6.6 million, compared to $6.8 million for the three months ended December 31, 2012 and $7.0 million for the three months ended March 31, 2012. The decrease in production during the three months ended March 31, 2013 compared to the three months ended December 31, 2012 and March 31, 2012 is due to natural decline, significant third-party natural gas processing plant outages in Central Alberta and constrained capex due to the Western Canada strategic alternatives process.

The Company realized an average sales price of $39.12 per boe during the three months ended March 31, 2013 compared to $37.14 per boe during the three months ended December 31, 2012 and $33.47 per boe during the three months ended March 31, 2012, exclusive of royalties and transportation, representing an increase of 5.3% and 16.9% respectively.

Royalties

($ thousands, except where otherwise noted)	Q1 2013	Q4 2012	Q1 2012
Royalties
Crown	251	519	922
Freehold and overriding	214	244	258
Total	465	763	1,180
Royalties per boe ($)	2.51	3.68	4.72
Average royalty rate (%)	6.6	9.9	14.5

The Company pays royalties to provincial governments, freehold landowners and overriding royalty owners. Royalties are calculated and paid based on petroleum and natural gas sales net of transportation. Crown royalties on Alberta natural gas production are calculated based on the Alberta Reference Price, which may vary from the Company’s realized corporate price, impacting the average royalty rate. In addition, various items impact the average royalty rate paid, such as cost of service credits and other royalty credit programs.

Royalties on horizontal gas wells drilled in Alberta in 2012, 2013 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.

Q1 2013 MD&A|5

For the three months ended March 31, 2013, natural gas and liquids royalties were $0.5 million, or 6.6% of total petroleum and natural gas sales, compared to $0.8 million or 9.9% of total petroleum and natural gas sales during the three months ended December 31, 2012 and $1.1 million or 14.5% of total petroleum and natural gas sales during the three months ended March 31, 2012. The decrease in natural gas and liquids royalties during the three months ended March 31, 2013 compared to the three months ended December 31, 2012 and March 31, 2012 is attributable to an increase in the Gas Cost Allowance received by the Company.

Operating and well workover expense

Combined operating and well workover expenses during the three months ended March 31, 2013 were $4.2 million or $22.76 per boe, compared to $4.8 million or $23.13 per boe during the three months ended December 31, 2012 and $4.3 million or $17.26 per boe during the three months ended March 31, 2012.

Capital expenditures

($ thousands)	Q1 2013		Q4 2012		Q1 2012
Exploration and evaluation	79		141		4,785
Drilling and completions	126		(246	)	1,782
Plants, facilities and pipelines	519		1,476		2,050
Land and lease	236		1,039		754
Capital well workovers	259		657		569
Capitalized general and administrative expenses	806		1,165		861
Capital expenditures	2,025		4,232		10,801
Western Canada dispositions	(296	)	(250	)	(74,979	)
North Africa farm-out proceeds	--		(995	)	--
Exploration and evaluation impairment, charged to exploration expense	(167	)	(227	)	(886	)
Net capital expenditures	1,562		2,760		(65,064	)

	Q1 2013		Q4 2012		Q1 2012
($ thousands) Continuing operations
Canada	847		3,079		(70,825	)
North Africa	769		(199	)	5,433
Corporate Assets	(54	)	(120	)	328
Net capital expenditures	1,562		2,760		(65,064	)

Western Canada

In February, 2012 Sonde sold 26,240 gross acres (24,383 net) in its Kaybob Duvernay play in Alberta for aggregate proceeds of $75 million, resulting in a net gain of $73.4 million.

Sonde continues to accumulate undeveloped acreage in the Duvernay (98,742 acres net), Montney (44,488 acres net), Wabamun (50,736 acres net) and Detrital/Banff (46,677 acres net) plays. Of these lands, 85% have been purchased within the past 18 months, and as such, there are no land expiry issues. These land positions are typically large, consolidated and 100% working interest holdings with outstanding characteristics and growth potential. In the Duvernay, Montney and Wabamun plays, Sonde has identified approximately 216, 50 to 70 and 162 to 324 horizontal drilling locations in each play respectively.

2013 Western Canada Drilling Program

Sonde did not drill any wells during the three months ended March 31, 2013 due to the strategic alternatives process discussed previously. During the three months ended March 31, 2012, Sonde initiated a waterflood in the Drumheller Mannville “I” pool and completed the tie-in and equipping of its Michichi detrital 13-17 well. Sonde performed 14 net workovers and recompletions during the three months ended March 31, 2013 and 16 net workovers during the three months ended March 31, 2012.

Q1 2013 MD&A|6

North Africa

During January 2012, the Company completed the shooting of 513 square kilometers of 3D seismic around two potential Zarat Field exploration well locations in accordance with the requirements of the Joint Oil Block Exploration and Production Sharing Agreement (“EPSA”).

On December 24, 2012, Joint Oil approved the extension of the first phase of the exploration period under the EPSA to December 23, 2015. The extension provides for the drilling of three exploration wells, one each year, due December 23 2013, 2014 and 2015. Penalties for non-fulfillment of the minimum work program are US$15.0 million for each well. In addition, the extension provides for the acquisition and processing of 200 square kilometers of 3D seismic in the Libyan sector of the Joint Oil Block, beginning in the second quarter of 2013.

Depletion, depreciation and impairment

For the three months ended March 31, 2013, depletion and depreciation was $2.5 million or $13.69 per boe compared to $2.7 million or $13.11 per boe during the three months ended December 31, 2012 and $3.1 million or $12.39 per boe during the three months ended March 31, 2012. The calculation of depletion and depreciation excluded $56.5 million (December 31, 2012 – $56.5 million, March 31, 2012 - $71.6 million) related to exploration and evaluation assets, primarily comprised of the Company’s North Africa asset. The decrease in depletion and depreciation during the three months ended March 31, 2013 compared to the three months ended December 31, 2012 and March 31, 2012 is due to a smaller depletion base resulting from impairments incurred during the twelve months ended December 31, 2012.

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 March 31, 2013. During the three months ended March 31, 2012, Sonde recorded an impairment of $12.9 million to property, plant and equipment to reflect the low natural gas price environment for future production. Sonde recorded net impairments of $9.7 million in the Southern Alberta CGU, $2.4 million in the Central Alberta CGU, and $0.8 million in the Northern Alberta CGU. Impairments recognized during the three months ended March 31, 2012 were calculated using a 12% discount rate. Using a discount rate of 10% would reduce the March 31, 2012 impairment by $8.5 million. Using a discount rate of 15% would increase the March 31, 2012 impairment by $10.4 million.

General and administrative expenses

($ thousands, except where otherwise noted)	Q1 2013		Q4 2012		Q1 2012
Gross general and administrative expense	3,630		3,034		3,697
Capitalized general and administrative expense	(806	)	(1,165	)	(861	)
	2,824		1,869		2,836
General and administrative expense ($/boe)	15.24		9.02		11.35

For the three months ended March 31, 2013, gross general and administrative (“G&A”) expenses for continuing operations decreased to $3.6 million from $3.7 million during the three months ended March 31, 2012. Gross G&A consists of $0.7 million (three months ended March 31, 2012 – $0.7 million) relating to North Africa and $2.9 million (three months ended March 31, 2012 – $3.0 million) related to Western Canada administration and corporate head office.

Q1 2013 MD&A|7

Share based compensation

	Q1 2013		Q4 2012	Q1 2012
Stock option expense	307		255	242
Stock unit award expense	26		661	123
Restricted share unit expense	(23	)	132	(43	)
Share based compensation	310		1,048	322

Stock based compensation expense for the year three months ended March 31, 2013 was $0.3 million compared to $1.0 million for the three months ended December 31, 2012. The reduction was due to a decline in the Company’s share price during the first quarter of 2013 which reduced the value of stock unit awards and restricted share units.

Liquidity and capital resources

	March 31			December 31
($ thousands)	2013			2012
Cash and cash equivalents		16,769			19,695
Accounts receivable		4,633			4,683
Prepaid expenses and deposits		771			733
Accounts payable and accrued liabilities		(6,198	)		(6,850	)
Stock based compensation liability		(912	)		(1,074	)
Working capital surplus (deficit)		15,063			17,187

At March 31, 2013, the Company had $16.8 million in cash and cash equivalents (December 31, 2012 – $19.7 million). In 2012 cash flow was augmented by the February 8, 2012 sale of 24,383 net acres of undeveloped land in the Kaybob Duvernary play in Central Alberta for cash proceeds of $75 million, resulting in a gain of 73.4 million.

As at March 31, 2013, the Company had working capital of $15.1 million (December 31, 2012 – $17.2 million) and had issued three letters of credit for $0.2 million (December 31, 2012 – three letters of credit of $0.2 million) against the $30.0 million (December 31, 2012 - $30.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75% as at March 31, 2013 and at December 31, 2012.

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 and capital expenditures are funded from cash flow, equity and proceeds from foreign asset sales.

The Company can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility. As at March 31, 2013 and December 31, 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 July 1, 2013.

Q1 2013 MD&A|8

The Company’s cash flow from operations is directly related to underlying commodity prices and production volumes. A significant decrease in commodity prices or production volumes could materially impact the Company's future cash flow from operations and liquidity. In addition, a substantial decrease in commodity prices or production volumes could impact the Company’s borrowing base under its credit facilities, therefore reducing funds available for Western Canada investment, and in some instances, requiring a portion of the credit facilities to be repaid. The Company currently has no risk management contracts to mitigate commodity prices. Management continues to review various risk mitigating options.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future and the Company has significant work commitments in connection with the EPSA in North Africa. If the Company's revenues or reserves decline, it may limit the Company's ability to expend or access the capital necessary to undertake or complete future drilling programs and meet commitments.

There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company.

The inability of the Company to access sufficient capital for its operations, including the closing of the Viking farm-out agreement which will reduce the Company's capital commitments, could have a material adverse effect on the Company's financial condition, results of operations or prospects.

The Company's financial statements contain a "going concern" note based on developments involving the Company's inability to meet its three exploratory well obligation in respect of the Joint Oil Block, unitization with and plan of development on the Zarat Field, drilling rig availability and an initiative on inert and acid gas sequestration.

Contingencies and commitments

(a)	North Africa EPSA

On August 27, 2008, the Company entered into the EPSA. 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.

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 adversely impacted the available financing alternatives and delayed the outcome and drilling of the three exploratory wells. The Company recorded an impairment of $21.0 million to the Joint Oil Block during the year ended December 31, 2012, charged to exploration and evaluation expense. This was a result of the following information obtained during the second quarter of 2012:

Q1 2013 MD&A|9

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 will ensure that the Zarat Development and other developments in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments with international organizations such as the Kyoto Accord on greenhouse gas emissions. This study is anticipated to take eighteen months.

Drilling Rig Availability – The Company’s initial assessment indicated that the global demand for offshore drilling units was 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 would have been available in the second quarter of 2013. The commercial terms of their offer were unacceptable to Sonde.

Unitization and Plan of Development – The Company 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 the Company could demonstrate to the market an asset with an approved Exploitation Plan. However, Joint Oil 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. In addition, the farm-out to Viking will impact the timing and potential unit development plans. As a result, the Company expected approval of its Zarat Plan of Development to be delayed for the near term.

Exploratory Well Obligations – The Company planned 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 could 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. As discussed below, on December 24, 2012 the Company received an extension on its exploratory well obligations until December 23, 2015.

(b)	North Africa exploratory well extension and farm-out

On December 24, 2012, Joint Oil approved the extension of the first phase of the exploration period under the EPSA to December 23, 2015. The extension provides for the drilling of three exploration wells, one each year, due December 23, 2013, 2014 and 2015. Penalties for non-fulfillment of the minimum work program are US$15.0 million for each well. In addition, the extension provides for the acquisition and processing of 200 square kilometers of 3D seismic in the Libyan sector of the Joint Oil Block, beginning in the second quarter of 2013.

On December 27, 2012, the Company entered into a farm-out agreement with Viking covering the Joint Oil Block. The farm-out agreement contains the following terms:

Viking will pay Sonde in total a US$3.0 million non-refundable signature bonus. As at December 31, 2012, US$1.0 million of the signature bonus had been received by the Company and credited against exploration and evaluation assets, with the remaining US$2.0 million due upon closing;

Viking will assume responsibility for the three well exploration commitment under the terms of the EPSA and fund 100% of the Joint Oil Block share of the Unit Plan of Development for the Zarat Field. The first well, Fisal, is to be drilled in 2013 along with the acquisition of 3D seismic data in Libyan waters;

Viking will provide to Sonde, prior to closing, the appropriate form of corporate guarantee with the agreed upon commercial terms, in order to secure the remaining work commitment under the terms of the EPSA;

Sonde will receive 20% of the cost recovery and profit share revenue until Sonde recovers US$70 million. After payout of all Viking expenditures, the revenue will be split 33.33% to Sonde and 66.67% to Viking;

Sonde retains the option to fund its 33.33% share of the last two of the exploration wells; and

Any future discoveries will be shared 33.33% to Sonde and 66.67% to Viking.

Q1 2013 MD&A|10

This pending farm-out is subject to the following conditions:

Viking (or one of its affiliates) provides Sonde with a corporate guarantee sufficient to offset the current US$45 million guarantee for the potential penalties in respect of the three well drilling commitment and 3D seismic; and

Joint Oil consents to the transfer of the interest to Viking as a second party to the EPSA and the naming of Viking as Operator of the Joint Oil Block under the EPSA.

On May 3, 2013, Sonde has received approval from Joint Oil’s Board of Directors to farm out 66.67% of its potential Zarat Field Exploration Area and 50% of the remainder of its interest in the Joint Oil Block to Viking. In order to receive Joint Oil approval, certain terms of the farm-out agreement described in our December 31, 2012 audited financial statements are required to be amended. The amendments to the farm-out agreement are summariezed below. Joint Oil’s approval of the assignment to Viking is subject to approval of the definitive form of Assignemnt Agreement and format of the Bank Guarantee (discussed below). Completion of the assignment will require the execution of the definitve amendment to the farm-out agreement with Viking and closing of the farm-out. Viking has agreed to the conditions.

The amendments to the original farm-out agreement are as follows:

	·	Sonde will remain the operator of the Joint Oil Block;
	·	Sonde and Viking will post a bank guarantee equivalent to US$50.995 million as a guarantee for the 2013 through 2015 work obligations the (“Bank Guarantee”). Viking will contribute US$40 million to the guarantee and Sonde will contribute US$10.995 million (the “Balance”) to the guarantee. Amounts under the Bank Guarantee will be released in accordance with a pre-determined formula as the work obligations are performed;
	·	Viking will acquire a 66.67% participating interest and Sonde will retain a 33.33% participating interest in the Zarat Field Exploitation Area;
	·	In consideration for contributing the Balance, Sonde will retain a 50% participating interest in the Joint Oil Block that is not covered by the exploitation area around the Zarat Field development. In addition, Sonde will recover the Balance from the initial proceeds from Zarat Field production in preference to the other terms of the farm-out; and
	·	Any future discoveries will be shared 50% to Sonde and 50% to Viking.

Sonde and Viking are in the process of completing the necessary documentation to effect amendments to the farm-out agreement prior to the June 7th expiry date.

Sonde, supported by Viking, is preparing an amended Unit Plan of Development which will be submitted to Joint Oil. The unit production will be shared on an initial fifty – fifty allocation with the license holder to the south until such time as the last development well is drilled and a redetermination of unit working interest can be re-established, at which time all costs, expenses and production will be adjusted accordingly between the unit parties. The revised Plan of Development which requires the approval of the parties involved, contemplates the utilization of a Floating Production Storage and Offloading vessel (“FPSO”).

(c)	Commitments and financial liabilities

At March 31, 2013, the Company has committed to future payments over the next five years and thereafter, as follows:

	2013		2014			2015			2016			2017			Thereafter			Total
Accounts payable and accrued liabilities		6,198		--			--			--			--			--			6,198
Stock based compensation liability		912		--			--			--			--			--			912
North Africa exploration commitments		16,866		15,240			15,240			--			--			--			47,346
Office rent payable		909		1,212			1,217			1,233			1,233			5,925			11,729
Office rent receivable		--		(405	)		(1,014	)		(1,233	)		(1,233	)		(5,925	)		(9,810	)
		24,885		16,047			15,443			--			--			--			56,375

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.

(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.

Q1 2013 MD&A|11

Income taxes

The Company’s current and future income taxes are dependent on factors such as production, commodity prices and tax classification of drilling costs related to exploration and development wells. At March 31, 2013, the Company has estimated $286.6 million in tax pools (2012 - $281.3 million) including $142.8 million in non-capital losses (2012 - $137.4 million) that are available for future deduction against taxable income. Non-capital losses expire in the years 2026 – 2033.

	March 31 2013		December 31 2012
Canadian exploration expense		56,838		56,802
Canadian oil and gas property expense		236		--
Canadian development expense		21,917		21,791
Undepreciated capital costs		29,013		29,041
Foreign exploration expense		4,397		4,354
Non-capital losses		142,779		137,414
Capital losses		30,109		30,094
Share issue costs and other		1,301		1,767
		286,590		281,263

Share capital

As at May 6, 2013, the Company had 62,301,446 common shares and 4,638,200 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 March 31, 2013, and is based on the balances disclosed in this MD&A and the condensed consolidated financial statements for the three months ended March 31, 2013:

($ thousands)	Petroleum and Natural Gas Sales
Change in average sales price for natural gas by $1.00/mcf		714
Change in the average sales price for oil and gas liquids by $1.00/bbl		66
Change in natural gas production by 1 mmcf/d		297
Change in crude oil and natural gas liquids production by 100 bbls/d		1,229

Interest rate risk

The Company is exposed to interest rate risk as the credit facilities bear interest at floating market interest rates. The Company has no interest rate swaps or hedges to mitigate interest rate risk at March 31, 2013. 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.

Credit risk

The Company’s allowance for doubtful accounts is currently $1.7 million (December 31, 2012 – $1.7 million). This amount offsets $1.8 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2012 – $1.8 million). The Company considers all amounts greater than 90 days to be past due. As at March 31, 2013, $0.9 million of accounts receivable are past due, all of which are considered to be collectible (December 31, 2012 - $0.9 million). The Company’s credit risk exposure is as follows:

Q1 2013 MD&A|12

	March 31		December 31
	2013		2012
(CDN$ thousands) Western Canada joint interest billings		2,033		2,310
Revenue accruals and other receivables		2,600		2,373
Accounts receivable		4,633		4,683
Cash and cash equivalents		16,769		19,695
Maximum credit exposure		21,402		24,378

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 sold a call option on a portion of the Company’s oil production from March 2011 through December 2012. The Company did not hold any such instruments at March 31, 2013. The gains and losses associated with this instrument are as follows:

For the three months ended

March 31, 2013

March 31, 2012

Term

Contract

Volume

Fixed Price

Realized gain (loss)

Unrealized gain (loss)

Realized (loss)

Unrealized gain

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

(67

)

151

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:

	March 31		December 31
	2013		2012
(US$ thousands) Cash and cash equivalents		2,291		2,184
North Africa receivables		1		1
Foreign denominated financial assets		2,292		2,185

North Africa payables		471		566
Foreign denominated financial liabilities		471		566

These balances are exposed to fluctuations in the Canadian and U.S. dollar exchange rate. 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, assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent is insignificant. This analysis assumes all other variables remain constant.

Q1 2013 MD&A|13

Liquidity Risk

The Company generally relies on a combination of cash flow from operations, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for operations. At March 31, 2013, the Company has committed to future payments over the next five years, as follows:

	2013		2014			2015			2016			2017			Thereafter			Total
Accounts payable and accrued liabilities		6,198		--			--			--			--			--			6,198
Stock based compensation liability		912		--			--			--			--			--			912
North Africa exploration commitments		16,866		15,240			15,240			--			--			--			47,346
Office rent payable		909		1,212			1,217			1,233			1,233			5,925			11,729
Office rent receivable		--		(405	)		(1,014	)		(1,233	)		(1,233	)		(5,925	)		(9,810	)
		24,885		16,047			15,443			--			--			--			56,375

Related party transactions

During the three months ended March 31, 2013, in the normal course of business, the Company purchased $0.1 million of processing services (March 31, 2012 – $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 March 31, 2013 and December 31, 2012, there were no amounts outstanding in accounts payable to this service provider.

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.

In addition, during the period beginning January 1, 2013 and ending March 31, 2013, there were no changes to the Company’s internal controls that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

Off-balance sheet arrangements

The Company has no off-balance sheet arrangements.

Q1 2013 MD&A|14

Quarterly financial summary

($ thousands except per share and production amounts)

	2013			2012			2012			2012			2012			2011			2011			2011
		Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2
Production
Natural gas (mcf/d)		7,934			8,940			8,757			9,665			11,553			12,186			12,673			11,509
Crude oil and natural gas liquids (bbl/d)		737			761			695			745			820			880			834			666
Total (boe/d)		2,059			2,251			2,155			2,356			2,746			2,911			2,946			2,584

Petroleum & natural gas sales (2)		6,607			6,792			5,631			5,487			6,986			9,445			9,011			7,747
Net (loss) income from continuing operations		(5,412	)		(3,870	)		(2,073	)		(28,030	)		55,456			(36,483	)		(847	)		(1,110	)
Net (loss) income from continuing operations per share – basic and diluted		(0.09	)		(0.06	)		(0.03	)		(0.45	)		0.89			(0.58	)		(0.01	)		(0.02	)
Net (loss) income (1)		(5,412	)		(3,870	)		(2,073	)		(28,030	)		55,456			(36,500	)		(591	)		2,781
Net (loss) income per share – basic and diluted(1)		(0.09	)		(0.01	)		(0.03	)		(0.45	)		0.89			(0.58	)		(0.01	)		0.04
Funds used for (from) operations (3)		(471	)		123			494			(1,267	)		(667	)		3,155			1,945			853
Funds used for (from) operations per share – basic and diluted (3)		(0.01	)		0.01			0.01			(0.02	)		(0.01	)		0.05			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 the Company’s results during the above periods include:

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

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

Please refer to the other sections of this MD&A for the detailed discussions on changes for the three months ending March 31, 2013.

Additional Information

Additional information relating to the Company, including the Company’s annual information form, is filed on SEDAR and can be viewed at www.sedar.com. Information can also be obtained by contacting the Company at Sonde Resources Corp., Suite 3100, 500 – 4th Avenue S.W., Calgary, Alberta, Canada T2P 2V6 and on the Company’s website at www.sonderesources.com.

Q1 2013 MD&A|15

Document 3

For Immediate Release

May 6, 2013

SONDE RESOURCES CORP. ANNOUNCES JOINT OIL APPROVAL OF THE FARM-OUT TO VIKING AND

FIRST QUARTER 2013 FINANCIAL AND OPERATING RESULTS

CALGARY, ALBERTA - (Marketwire – May 6, 2013) - Sonde Resources Corp. ("Sonde" or the "Company") (TSX: SOQ) (NYSE MKT: SOQ) announced today that the Company has received Joint Oil’s approval to farm-out the Joint Oil Block to Viking Exploration and Production Tunisia Limited (“Viking”), a private company. The conditions to this approval and amended commercial terms of the farm-out agreement are described below. In addition, the Company released its financial and operating results for the first quarter ended March 31, 2013. The Management's Discussion and Analysis and Financial Statements for the first quarter ended March 31, 2013 can be viewed on the System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com, and on the Securities and Exchange Commission's Electronic Document Gathering and Retrieval System (EDGAR) at www.sec.gov. Shareholders have the ability to receive a hard copy of the Company's complete first quarter financial statements free of charge upon request.

Sonde will be hosting a conference call on Tuesday, May 7, 2013 at 2:00 p.m. MDT to provide a report on the first quarter 2013 results and an update on current activities. Mr. Jack Schanck, President and CEO will host the call. All interested parties may join the call by dialing 416-340-2216 or 866-226-1792. Please dial-in 15 minutes prior to the call to secure a line. The conference call will be archived for replay on the Sonde website within 48 hours of this conference call.

Joint Oil Approval of the Farm-Out to Viking

Sonde has received approval from Joint Oil’s Board of Directors to farm-out 66.67% of its potential Zarat Field Exploitation Area and 50% of the remainder of its interest in the Joint Oil Block to Viking. In order to receive Joint Oil approval, certain terms of the farm-out agreement described in our December 27, 2012 press release, financial statements and annual information form are required to be amended. The amendments to the farm-out agreement are summarized below. Joint Oil’s approval of the assignment to Viking is subject to approval of the definitive form of Assignment Agreement and format of the Bank Guarantee (discussed below). Completion of the assignment will require the execution of the definitive amendment to the farm-out agreement with Viking and closing of the farm-out. Viking has agreed to the conditions.

The amendments to the original farm-out agreement are as follows:

Sonde will remain the operator of the Joint Oil Block;

Sonde and Viking will post a bank guarantee equivalent to US$50.995 million as a guarantee for the 2013 through 2015 work obligations the (“Bank Guarantee”). Viking will contribute US$40

million to the guarantee and Sonde will contribute US$10.995 million (the “Balance”) to the guarantee. Amounts under the Bank Guarantee will be released in accordance with a pre-determined formula as the work obligations are performed;

Viking will acquire a 66.67% participating interest and Sonde will retain a 33.33% participating interest in the Zarat Field Exploitation Area;

In consideration for contributing the Balance, Sonde will retain a 50% participating interest in the Joint Oil Block that is not covered by the exploitation area around the Zarat Field development. In addition, Sonde will recover the Balance from the initial proceeds from Zarat Field production in preference to the other terms of the farm-out; and

Any future discoveries will be shared as to 50% for Sonde and 50% for Viking.

Sonde and Viking are in the process of completing the necessary documentation to effect amendments to the farm-out agreement, and this documentation is anticipated to be executed prior to the deadline of June 7, 2013 under the terms of the original farm-out agreement.

Jack Schanck, President and CEO said, “Sonde is very pleased to have received the approval of Joint Oil’s Board of Directors to the Viking farm-out. We are delighted to have the Viking Energy Group as our partner in the Joint Oil Block and are very excited to move to the next stage of the development of the Joint Oil Block. We look to this joint venture as a long-term relationship and commitment to our partner Joint Oil and its shareholders.”

Western Canada Strategic Alternatives Process

The Board has established a Special Committee comprised of independent directors to oversee the strategic review process. Various prospects and options are currently being evaluated by the Special Committee. There can be no assurance that the process will result in any transaction or, if a transaction results, the timing of such transaction.

2013 Western Canada Drilling Program

No wells were drilled during the three months ended March 31, 2013 due to the strategic alternatives process discussed above. Sonde performed 14 net workovers and recompletions during the three months ended March 31, 2013.

First Quarter Financial and Operational Review

	2013	2012	%	2012	%
	Q1	Q4	Change	Q1	Change
Financial
Petroleum & natural gas sales(1)	6,607	6,792	(3)	6,986	(5)
Net (loss) income	(5,412)	(3,870)	(40)	55,456	(110)
Net (loss) income per share – basic and diluted	(0.09)	(0.06)	(50)	0.89	(110)
Funds (used for) from operations (2)	(472)	123	(484)	(667)	29
Funds (used for) from operations per share(2)	(0.01)	0.01	--	(0.01)	--
Capital expenditures	2,025	4,232	(52)	10,801	(81)
Working capital surplus	15,063	17,187	(12)	42,914	(65)
Average shares outstanding	62,301	62,301	--	62,301	--
Production
Natural gas (mcf/d)	7,934	8,940	(11)	11,553	(31)
Crude oil (bbl/d)	549	572	(4)	565	(3)
Natural gas liquids (bbl/d)	188	189	(1)	255	(26)
Total (boe/d)	2,059	2,251	(9)	2,746	(25)
Pricing
Natural gas ($/mcf)	3.30	3.50	(6)	2.20	50
Crude oil ($/bbl)	79.58	72.69	9	89.54	(11)
Natural gas liquids ($/bbl)	57.03	56.35	1	62.08	(8)
Average sales price ($/boe)	39.12	37.14	5	33.47	17

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

2)	Non-IFRS measure reconciled in our MD&A filed on www.sedar.com

For the three months ended March 31, 2013, production averaged 2,059 boe/d, compared to 2,251 boe/d for the three months ended December 31, 2012. The three month decrease in production during the period ended March 31, 2013 is due to natural decline and significant third-party natural gas processing plant outages in Central Alberta.

The success of the Company’s ongoing operations are dependent upon a number of factors, including but not limited to, the price of energy commodity products, the Company’s ability to manage price volatility, increasing production and related cash flows, controlling costs, availability of experienced service industry personnel and equipment, capital spending allocations, the ability to attract equity investment, the results of Sonde’s Western Canada strategic alternatives process, hiring and retaining qualified personnel and managing political and government risk, particularly with respect to its interests in North Africa.

Sonde Resources Corp. is a Calgary, Alberta, Canada based energy company engaged in the exploration and production of oil and natural gas. Its operations are located in Western Canada, and offshore North Africa. See Sonde’s website at www.sonderesources.com to review further detail on Sonde’s operations.

Non-IFRS Measures – This document contains references to funds from (used for) operations and funds from (used for) operations per share, which are not defined under IFRS as issued by the International Accounting Standards Board and are therefore non-IFRS financial measures that do not have any standardized meaning prescribed by IFRS and are, therefore, unlikely to be and its comparable to similar measures presented by other issuers. Management of the Company believes funds from (used for) operations and funds from (used for) operations per share are relevant indicators of the Company’s financial performance, ability to fund future capital expenditures. Funds from (used for) operations should not be considered an alternative to or more meaningful than cash flow from operating activities, as determined in accordance with IFRS, as an indicator of the Company's performance. In our MD&A, a reconciliation has been prepared of funds from (used for) operations to cash (used in) provided by 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. This conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Such disclosure of boe’s 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 mcf:1 bbl, utilizing a conversion ratio of 6 mcf:1 bbl 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 (“bbl”).

Forward Looking Information – This news release contains "forward-looking information" within the meaning of applicable Canadian securities laws and "forward looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. These statements include, among others, the amended terms of the farm-out agreement with Viking, the anticipated timing for executing documentation to effect the amended terms of the farm-out, the potential outcomes of the Company’s planned Western Canada strategic review process, proposed exploration and development activities and sources of liquidity. There can be no assurances that the Western Canada strategic review process will result in a transaction on terms and conditions acceptable to Sonde or at all.

Such forward-looking information or statements are based on a number of risks, uncertainties and assumptions which may cause actual results or other expectations to differ materially from those anticipated and which may prove to be incorrect. Assumptions have been made regarding, among other things, market and operating conditions, management's expectations regarding future growth, plans for and results of exploration and development activities, availability of capital, future commodity prices and differentials, and capital and other expenditures.

Actual results could differ materially due to a number of factors, including, without limitation, changes in market conditions, operational risks in development, exploration and production; commodity price volatility; the uncertainty of reserve estimates; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of estimates and projections in relation to production; volatility in the capital markets and changes in the availability of capital generally; risks in conducting foreign operations, including political and fiscal instability and the possibility of civil unrest or military action; changes in government policies or laws; risk that government approvals may be delayed or withheld; and commercial risks relating to the closing of the Viking

farm-out. Additional assumptions and risks relating to the Company and its business and affairs, including assumptions and risks relating to the estimation of reserves, are set out in detail in the Company’s AIF, available on SEDAR at www.sedar.com, and the Corporation's annual report on Form 40-F on file with the U.S. Securities and Exchange Commission.

Although management believes that the expectations reflected in the forward-looking information or forward-looking statements are reasonable, prospective investors should not place undue reliance on forward-looking information or forward-looking statements because Sonde can provide no assurance those expectations will prove to be correct. Sonde bases its forward-looking statements and forward-looking information on information currently available and do not assume any obligation to update them unless required by law.

For Further Information Please Contact:

Sonde Resources Corp.

Suite 3100, 500 - 4th Avenue S.W.

Calgary, Alberta, Canada T2P 2V6

Kurt A. Nelson, Chief Financial Officer

Phone: (403) 503-7944

Fax: (403) 216-2374

www.sonderesources.com

Document 4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

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

1.	Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended March 31, 2013.

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.

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.

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

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

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

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

II.

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

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

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

5.2

N/A

5.3

N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2013 and ended on March 31, 2013 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.

Date: May 6, 2013

/s/ Jack W. Schanck

Jack W. Schanck

Chief Executive Officer

Sonde Resources Corp.

Document 5

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 March 31, 2013.

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

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

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.

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 January 1, 2013 and ended on March 31, 2013 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.

Date: May 6, 2013

/s/ 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:	May 6, 2013	By:	/s/ Cheryl Clark
			Name: Title:	Cheryl Clark Corporate Controller/Assistant Corporate Secretary