Edgar Filing: SONDE RESOURCES CORP.

form6-k.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,	August	2012
Commission File Number	001-31395
Sonde Resources Corp.
(Translation of registrant’s name into English)
Suite 3200, 500 - 4th Avenue SW, Calgary, Alberta, Canada T2P 2V6
(Address of principal executive offices)

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

Form 20-F

Form 40-F

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

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

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

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

DOCUMENTS INCLUDED AS PART OF THIS REPORT

Document		Description


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

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

Document 1

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(unaudited)

	June 30 2012	December 31 2011
(CDN$ thousands)
Assets
Current
Cash and cash equivalents (note 9)	41,314	3,743
Accounts receivable (note 8)	4,030	7,436
Prepaid expenses and deposits	1,502	1,528
	46,846	12,707
Long term portion of prepaid expenses and deposits	357	420
Exploration and evaluation assets (note 3)	53,414	69,015
Property, plant and equipment (note 3)	93,645	104,745
	194,262	186,887

Liabilities
Current
Accounts payable and accrued liabilities	9,981	17,655
Share based compensation liability (note 14)	1,945	2,448
Provisions (note 10)	4	12,730
Derivative financial liabilities (note 9)	51	781
	11,981	33,614
Decommissioning provision	27,137	26,344
	39,118	59,958
Going concern (notes 2b and 7) Contingencies and commitments (note 7) Related party transactions (note 6) Segments (note 15)

Shareholders’ Equity
Share capital	369,892	369,892
Contributed surplus	33,899	33,528
Foreign currency translation reserve	968	550
Deficit	(249,615)	(277,041)
	155,144	126,929
	194,262	186,887

See accompanying notes to the condensed consolidated financial statements

On behalf of the Board,

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

Q2 2012 FS

Page 1

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(unaudited)

	Three months ended June 30		Six months ended June 30
	2012	2011	2012	2011
(CDN$ thousands, except per share amounts)
Revenue
Revenue, net of royalties (note 11)	5,631	7,894	12,880	16,826
Gain (loss) on commodity derivatives (notes 8, 9)	554	1,121	638	(543)
	6,185	9,015	13,518	16,283
Expenses
Operating (note 12)	4,234	3,204	8,547	6,909
Transportation	119	257	315	516
Exploration and evaluation (note 3)	21,426	206	22,312	370
General and administrative	2,499	2,144	5,335	4,387
Depletion and depreciation	2,617	2,961	5,712	6,243
Share based compensation (note 14)	(161)	1,431	161	2,676
Property, plant and equipment impairment (note 3)	3,361	--	16,241	--
Loss on settlement of decommissioning liabilities	84	--	84	775
	34,179	10,203	58,707	21,876
Operating loss	(27,994)	(1,188)	(45,189)	(5,593)

Other
Financing costs (note 4)	(241)	(802)	(499)	(1,453)
Gain (loss) on foreign exchange	163	(1,020)	(284)	2,633
Gain on financial derivatives	--	2,255	--	(548)
Other income	42	3	72	59
Gain on disposition of exploration and evaluation assets (note 3)	--	--	73,361	--
	(36)	436	72,650	691
Income (loss) from continuing operations before income taxes	(28,030)	(752)	27,461	(4,902)
Current income taxes	--	120	35	120
Income (loss) from continuing operations	(28,030)	(872)	27,426	(5,022)
Income from discontinued operations, net of tax (note 16)	--	3,891	--	2,665
Net income (loss)	(28,030)	3,019	27,426	(2,357)
Other comprehensive income (loss)
Foreign currency translation adjustment	1,308	(201)	418	(1,118)
Foreign currency translation adjustment relating to assets and liabilities of discontinued operations (note 16)	--	550	--	(1,128)
Foreign currency translation reclassified to net earnings	--	6,365	--	6,365
Other comprehensive income	1,308	6,714	418	4,119
Total comprehensive income (loss)	(26,722)	9,733	27,844	1,762

Basic and diluted income (loss) per common share from continuing operations (note 5)	($0.45)	($0.01)	$0.44	($0.08)
Basic and diluted income per common share from discontinued operations (note 5)	--	$0.06	--	$0.04
Net income (loss) per common share	($0.45)	$0.05	$0.44	($0.04)

See accompanying notes to the condensed consolidated financial statements

Q2 2012 FS

Page 2

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three months ended June 30		Six months ended June 30
	2012	2011	2012	2011
(CDN$ thousands)
Cash provided by (used in):
Operating activities
Net income (loss)	(28,030)	3,019	27,426	(2,357)
Items not involving cash:
Depletion and depreciation	2,617	2,961	5,712	6,243
Share based compensation	(161)	1,431	161	2,676
Exploration and evaluation	21,226	206	22,112	370
Property, plant and equipment impairment	3,361	--	16,241	--
Unrealized (gain) loss on commodity derivatives	(580)	(1,011)	(730)	729
Unrealized (gain) loss on financial derivatives	--	(2,255)	--	(2,633)
Unrealized (gain) loss on foreign exchange	(157)	964	(111)	961
Financing costs	241	1,103	499	1,946
Loss on settlement of decommissioning liabilities	84	--	84	775
Gain on disposition of exploration and evaluation assets	--	--	(73,361)	--
Gain on disposition of discontinued operations	--	(4,600)	--	(4,600)
Interest paid	(70)	(937)	(167)	(1,584)
Decommissioning expenditures	(151)	--	(151)	(846)
Changes in non-cash working capital (note 13)	456	1,654	1,550	1,089
	(1,162)	2,535	(735)	2,769
Financing activities
Exercise of restricted share units	(65)	--	(150)	--
Exercise of stock unit awards	(142)	--	(142)	--
Revolving credit facility repayments	--	(15,126)	(23,400)	(34,562)
Revolving credit facility advances	--	7,793	23,400	21,343
	(207)	(7,333)	(292)	(13,219)
Investing activities
Property, plant and equipment additions	(5,712)	(4,735)	(10,325)	(7,982)
Exploration and evaluation additions	(1,768)	(5,502)	(7,956)	(14,721)
Asset additions in discontinued operations	--	(565)	--	(565)
Proceeds on exploration and evaluation disposition (notes 3, 16)	--	68,026	74,979	87,625
Change in non-cash working capital (note 13)	1,945	(12,263)	(18,211)	(14,786)
	(5,535)	44,961	38,487	49,571
Increase (decrease) in cash and cash equivalents	(6,904)	40,163	37,460	39,121
Effect of foreign exchange on cash and cash equivalents	156	(905)	111	(933)
Cash and cash equivalents, beginning of period	48,062	1,579	3,743	2,649
Cash and cash equivalents, end of period	41,314	40,837	41,314	40,837

See accompanying notes to the condensed consolidated financial statements

Q2 2012 FS

Page 3

SONDE RESOURCES CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(unaudited)

(CDN$ thousands)	Share capital	Contributed surplus	Foreign currency translation	Deficit	Total
At December 31, 2010	369,892	30,718	(5,789)	(236,470)	158,351
Total comprehensive income	--	--	(2,246)	4,008	1,762
Foreign currency translation reserve reclassified to net earnings	--	--	6,365	(6,365)	--
Stock option expense	--	1,535	--	--	1,535
At June 30, 2011	369,892	32,253	(1,670)	(238,827)	161,648

(CDN$ thousands)	Share capital	Contributed surplus	Foreign currency translation	Deficit	Total
At December 31, 2011	369,892	33,528	550	(277,041)	126,929
Total comprehensive income	--	--	418	27,426	27,844
Stock option expense	--	371	--	--	371
At June 30, 2012	369,892	33,899	968	(249,615)	155,144

See accompanying notes to the condensed consolidated financial statements

Q2 2012 FS

Page 4

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2012

(unaudited)

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

1.	Reporting entity

	Sonde Resources Corp. (“Sonde” or the “Company”) is a Canadian based energy company with its registered office located at Suite 3200, 500 – 4th Avenue S.W., Calgary, Alberta. The Company is engaged in the exploration for and production of oil and natural gas. The Company’s operations are located in Western Canada and offshore North Africa. All of the Company’s revenues are generated from its operations in Western Canada. On February 22, 2011, the Company completed the sale of its wholly owned subsidiary Liberty Natural Gas LLC (the “LNG Project”). On June 22, 2011, the Company completed the sale of its offshore operations in the Republic of Trinidad and Tobago (“Trinidad and Tobago”). These dispositions are discussed in more detail in Note 16. The condensed consolidated financial statements (the “Financial Statements”) comprise the Company and its wholly owned subsidiaries. The Company’s shares are widely held and publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange MKT.

2.	Basis of preparation

	(a) Statement of compliance

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

	The Financial Statements were approved and authorized for issue by the Board on August 10, 2012.

	(b) Going concern

	The Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and settlement of liabilities and commitments in the normal course of business and does not reflect adjustments that would otherwise be necessary if the going concern assumption was not valid. For the six months ended June 30, 2012, the Company had an operating loss of $45.2 million, negative cash flows from operations of $0.7 million, and an accumulated deficit of $249.6 million. Management believes that the going concern assumption is appropriate for the Financial Statements; however, items discussed in Note 7 – “Commitments and Contingencies”, describe significant uncertainties that cast significant doubt over the Company’s ability to continue as a going concern. If this assumption were not appropriate, adjustments to the carrying amounts of assets and liabilities, revenues and expenses and the statement of financial position classifications used may be necessary and these adjustments could be material.

	(c) Basis of measurement

	The Financial Statements have been prepared on the historical cost basis except as detailed in the Company’s accounting policies disclosed in the audited consolidated financial statements for the year ended December 31, 2011. The accounting policies have been applied consistently to all periods presented in the Financial Statements. The Financial Statements should be read in conjunction with the audited consolidated financial statements and notes thereto as at and for the year ended December 31, 2011.

	(d) Functional and presentation currencies

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

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2.	Basis of preparation (continued)

	(e) Use of estimates and judgment

	The timely preparation of financial statements requires that management make estimates and assumptions and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as at the date of the Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
3.	Exploration and evaluation assets and property, plant and equipment

	Six months ended June 30, 2012			Year ended December 31, 2011
	Cost	Accum. DD&A	Carrying value	Cost	Accum. DD&A	Carrying value
Exploration and evaluation assets
Beginning of period	79,399	(10,384)	69,015	58,475	(9,114)	49,361
Additions	7,956	--	7,956	19,405	--	19,405
Dispositions	(1,618)	--	(1,618)	--	--	--
Transfers to PP&E	--	--	--	(43)	--	(43)
Impairments, to exploration expense	--	(22,112)	(22,112)	--	(1,270)	(1,270)
Change in decommissioning obligations	--	--	--	41	--	41
Foreign exchange	173	--	173	1,521	--	1,521
End of period	85,910	(32,496)	53,414	79,399	(10,384)	69,015

Property, plant and equipment
Beginning of period	212,453	(107,708)	104,745	161,165	(58,562)	102,603
Additions	10,325	--	10,325	37,509	--	37,509
Acquisitions	--	--	--	11,827	--	11,827
Dispositions	--	--	--	(151)	30	(121)
Transfers from E&E assets	--	--	--	43	--	43
Change in decommissioning obligations	528	--	528	2,060	--	2,060
Depreciation and depletion	--	(5,712)	(5,712)	--	(14,906)	(14,906)
Impairments	--	(16,241)	(16,241)	--	(34,270)	(34,270)
End of period	223,306	(129,661)	93,645	212,453	(107,708)	104,745

	During the three and six months ended June 30, 2012, the Company capitalized $1.4 million and $2.2 million respectively (June 30, 2011 – $0.7 million and $1.8 million) of general and administrative expenses related to exploration and development activities.

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

	Land expiries and impairment on Western Canada exploratory wells charged to exploration and evaluation expense during the three and six months ended June 30, 2012, totaled $0.2 million and $1.1 million respectively (June 30, 2011 – $0.2 million and $0.4 million). As of June 30, 2012, no indicators of impairment were identified in Western Canada that would imply a further decline in exploration and evaluation asset carrying values. Impairment on the Joint Oil Block offshore North Africa charged to exploration and evaluation expense totaled $21.0 million for both the three and six months ended June 30, 2012 (June 30, 2011 – nil for both the three and six month periods). The factors leading to this impairment are further described in Note 7. The Company evaluated the fair value of the Joint Oil Block as described below. This analysis assumed a wide range of potential future outcomes. There is a great deal of uncertainty in the estimate of production, capital and future operating cost for the future development of these assets. The key items that contribute to this uncertainty are oil and natural gas price and production volumes. A series of outcomes were modeled for each variable. The other key model variable is if the Joint Oil Block does not get developed. Factors contributing to this non-commercial variable are described in Note 7. All of these could severally influence the fair value. The recoverable value was determined using a third party valuation firm to estimate the fair value of $45.2 million less costs to sell of $0.5 million. The valuation was performed under the Swanson’s mean methodology utilizing probability-weighted discounted cash flows over the estimated life of the project (estimated to be 2012 -2032). The most significant assumptions used in the determination of the fair value include:

—

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

—

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

—

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

—

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

—

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

Given the number of quantitative and qualitative factors discussed above and in Note 7, each with substantial uncertainties, and the interdependency of factors, the Company is unable to identify the sensitivities associated with individual factors. A number of the potential scenarios result in no value for the North African assets; however, as of the report date management does not believe that this is the most likely outcome and the fair value of $45.2 million was determined to be the most probable value in the range of possible values. The Company believes that the issues identified above are ongoing and is actively working towards finding appropriate solutions for these complex issues. The Company expects more clarity in the near future relating to these issues, including whether the current extension for the exploration wells to December 2013 will be maintained. Possible negotiations regarding additional extensions to the exploration period will occur in the third or fourth quarter of 2012. Additional impairments, including potentially abandoning the project, may result in the future as conditions unfold and clarity is obtained with respect to the Company’s North African operations.

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

	An impairment test was carried out on property, plant, and equipment at June 30, 2012, using the following forward commodity price projections:

Year	AECO Gas (Cdn/mmbtu) (1)	Edmonton Light Sweet Crude Oil (Cdn/bbl) (1)
2012 (Q3 – Q4)	$ 2.87	$ 79.08
2013	3.44	86.73
2014	3.90	95.92
2015	4.36	101.02
2016	4.82	101.02
2017	5.28	101.02
2018	5.68	102.40
2019	5.80	104.47
2020	5.91	106.58
2021	6.03	108.73
Remainder(2)	2.0%	2.0%
(1) Source: Independent qualified reserves evaluator’s price forecast, effective July 1, 2012.
(2) Percentage change represents the change in each year after 2021 to the end of the reserve life.

	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. During the three months ended June 30, 2012, the Company recognized an impairment of $3.4 million to property, plant and equipment to reflect an expected decline in realized oil prices for future production, primarily as a result of an increased differential between the Edmonton Light Sweet Crude and West Texas Intermediate benchmarks. During the three months ended March 31, 2012, the Company recognized an impairment of $12.9 million to property, plant and equipment to reflect the low natural gas price environment for future production. Impairments recognized during the three months ended June 30, 2012 and March 31, 2012 were calculated using a 12% discount rate.

	The Company’s net impairments by CGU were as follows:

Three months ended		Three months ended	Six months ended
June 30, 2012		March 31, 2012	June 30 2012
Northern Alberta CGU	951	709	1,660
Central Alberta CGU	--	2,444	2,444
Southern Alberta CGU	2,410	9,696	12,106
BC CGU	--	31	31
Property, plant and equipment impairment	3,361	12,880	16,241
Discount rate	12%	12%	12%
Reduction to impairment of using 10%	(2,721)	(8,515)	(11,236)
Increase to impairment of using 15%	9,659	10,417	20,076

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

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4.	Short term debt and financing costs

	As at June 30, 2012, the Company had issued three letters of credit for $0.2 million (December 31, 2011 – two letters of credit for $0.1 million) against the $30.0 million (December 31, 2011 - $40.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75% as at June 30, 2012 and December 31, 2011. Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company. Credit Facility A has covenants, as defined in the Company’s credit agreement, that require the Company to maintain an adjusted working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative expenditures in excess of $7.0 million per year and all foreign capital expenditures are not funded from Credit Facility A nor domestic cash flow while Credit Facility A is outstanding. The Company can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility. As at June 30, 2012, the Company was in compliance with all of its debt covenants. The Company is subject to the next semi-annual review of its credit facilities on or before September 30, 2012.

	Financing costs for the Company are as follows:

	Three months ended June 30		Six months ended June 30
	2012	2011	2012	2011
Accretion of decommissioning provision(1)	171	167	332	323
Interest on credit facilities(1)	70	383	167	632
Interest on preferred shares	--	252	--	498
	241	802	499	1,453

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

5.	Weighted average common shares outstanding
	For the three and six months ended June 30, 2012, the diluted weighted average common shares outstanding were 62,301,446 and 62,304,026 respectively (June 30, 2011 – 62,301,446 for both periods). For the calculation of diluted earnings per share the Company excluded 3,504,724 and 3,209,625 stock options that are anti-dilutive for the three and six months ended June 30, 2012 (June 30, 2011 – 2,814,639 and 2,718,929). The basic weighted average common shares outstanding was 62,301,446 for all periods.

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

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7.	Contingencies and commitments

	(a) North Africa

	On August 27, 2008, the Company entered into an Exploration and Production Sharing Agreement (“EPSA”) with a Tunisian company, Joint Oil. Joint Oil is owned equally by the governments of Tunisia and Libya. The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, the Company is the operator. Under the EPSA, the minimum work program for the first phase (four years) of the seven year exploration period includes the Zarat North-1 appraisal well, three exploration wells and 500 square kilometres of 3D seismic. The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15.0 million per exploration well, and the Company has provided a corporate guarantee to a maximum of US$45.0 million to secure its minimum work program obligations. The potential cost of drilling the three wells could exceed US$100.0 million. The first phase of the exploration period has been extended until December 23, 2013, conditioned by Joint Oil on the Company securing a rig for the three well commitment by the end of September 2012. Without this extension, the commitment must be met by December 23, 2012. In January 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North–1 well. In December 2011, the Company commenced the acquisition of 512 square kilometres of 3D seismic in accordance with the requirements of the EPSA and completed the acquisition in January 2012.

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

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

	·	Drilling Rig Availability - The initial results indicate that the global demand for offshore drilling units is higher in other parts of the world than North Africa. Subsequent to June 30, 2012, one contractor submitted a bid for a technically acceptable jack up drilling rig that may be available in the second quarter of 2013. The commercial terms of their offer were unacceptable to the Company. As a result, the Company will be unable to meet the terms of the one year extension of the initial exploration period to December 2013. Without the extension the exploration period will expire in December 2012. This expiration can trigger the US$45.0 million penalty in the event that Joint Oil does not agree to restructure the three well exploratory well obligation to the second exploration period. Combined, the first and second exploration periods would expire in December 2015.

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

	·	Exploratory Well Obligations – The Company plans to discuss with Joint Oil the restructuring 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

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	parties can find merit in an additional discovery of high inert and acid gases at this time without a clear commercialization path that includes a solution to this issue.

7.	Contingencies and commitments (continued)

	Whether the Company can secure additional financing for the North Africa three exploratory well commitment or whether the US$45.0 million penalty will be triggered is uncertain. This uncertainty casts significant doubt about the Company’s ability to continue as a going concern. The Company continues its efforts to secure alternate financing or other arrangements on acceptable terms for the Joint Oil Block. The Company also plans to discuss these issues with Joint Oil in an effort to restructure its exploratory well commitment. Public and private debt and equity markets are not accessible now or in the near term for exploratory or development projects on the Joint Oil Block and the Company’s Western Canada operations will not provide sufficient cash flows to meet the exploratory commitment. Without access to third party financing or a party to assume the Joint Oil Block exploratory obligations, the Company may not be able to continue as a going concern. The Financial Statements do not include any adjustments to the amounts and classification of assets (with the exception of a partial impairment of the Joint Oil Block component of the exploration and evaluation assets) and liabilities that may be necessary should the Company be unable to continue as a going concern, and these adjustments may be material.

	(b) Commitments and financial liabilities

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

	2012	2013	2014	2015	2016	Thereafter	Total
Accounts payable and accrued liabilities	9,981	--	--	--	--	--	9,981
Stock based compensation liability	1,945	--	--	--	--	--	1,945
Derivative financial liabilities	51	--	--	--	--	--	51
North Africa exploration commitments (note 7a)	--	45,815	--	--	--	--	45,815
Office rent	681	1,212	1,212	1,217	1,233	7,159	12,714
Equipment	2	--	--	--	--	--	2
	12,660	47,027	1,212	1,217	1,233	7,159	70,508

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

	(c) Swap agreement

	At the time it entered into the North Africa EPSA, the Company also signed a "Swap Agreement" awarding an overriding royalty interest and optional participating interest to Joint Oil in the Company's "Mariner" Block, offshore Nova Scotia, Canada. No well was drilled on the Mariner Block and Joint Oil had the right to put back the overriding royalty to the Company for US$12.5 million. Joint Oil exercised its put rights and the Company made a payment of US$12.5 million on January 15, 2012. Prior to the payment, the Company confirmed that the EPSA remains in full force and effect.

	(d) Litigation and claims

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

Q2 2012 FS

Page 10

8.	Risk Management

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

Three months ended

June 30, 2012

June 30, 2011

Term

Contract

Volume

Fixed Price

Realized loss

Unrealized gain

Realized gain (loss)

Unrealized gain (loss)

March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

$194

($97)

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($26)

$580

($84)

$1,108

Six months ended

June 30, 2012

June 30, 2011

Term

Contract

Volume

Fixed Price

Realized loss

Unrealized gain

Realized gain (loss)

Unrealized gain (loss)

March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

$291

$410

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($92)

$730

($105)

($1,139)

	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 June 30, 2012 or December 31, 2011. The Company’s exposure to fluctuations in interest expense on its net loss and comprehensive income, assuming reasonably possible changes in the variable interest rate of +/- 1%, is insignificant. This analysis assumes all other variables remain constant.

	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:

	June 30	December 31
	2012	2011
(US$ thousands)
Cash and cash equivalents	6,971	1,020
North Africa receivables	--	111
Foreign denominated financial assets	6,971	1,131

North Africa payables	618	1,720
Mariner swap provision	--	12,500
Foreign denominated financial liabilities	618	14,220

These balances are exposed to fluctuations in the U.S. dollar. At this time, the Company has chosen not to enter into any risk management agreements to mitigate foreign exchange risk. The Company’s exposure to foreign currency exchange risk on its comprehensive income, assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent, is $0.5 million. This analysis assumes all other variables remain constant.

Q2 2012 FS

Page 11

8.	Risk Management (continued)

	Credit risk

	The Company’s credit risk exposure is as follows:

	June 30	December 31
	2012	2011
(CDN$ thousands)
Western Canada joint interest billings	1,810	2,830
Goods and Services Tax receivable	212	740
North Africa recoverable expenses	--	113
Revenue accruals and other receivables	2,008	3,753
Accounts receivable	4,030	7,436
Cash and cash equivalents	41,314	3,743
Maximum credit exposure	45,344	11,179

	The Company’s allowance for doubtful accounts is currently $1.8 million (December 31, 2011 – $2.0 million). This amount offsets $1.7 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2011 – $1.8 million) and $0.1 million of Western Canada joint interest and miscellaneous receivables (December 31, 2011 – $0.2 million). The Company considers all amounts greater than 90 days to be past due. As at June 30, 2012, $0.6 million of accounts receivable are past due, all of which are considered to be collectible.

9.	Financial instruments

	At June 30, 2012, cash and cash equivalents were comprised of $29.9 million in short term investment instruments and $11.4 million of cash held at financial institutions (December 31, 2011 – $3.7 million cash held at financial institutions).

	The following tables provide fair value measurement information for financial assets and liabilities as of June 30, 2012 and December 31, 2011. The carrying value of cash and cash equivalents, accounts receivables, provisions, accounts payable and accrued liabilities included in the consolidated statement of financial position approximate fair value due to the short term nature of those instruments. These assets and liabilities are not included in the table.

		Fair value measurements using:
Carrying value		Fair value	Level 1	Level 2	Level 3
Financial liabilities
Commodity contracts – as at June 30, 2012	51	51	--	51	--
Commodity contracts – as at December 31, 2011	781	781	--	781	--

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

10.	Provisions

	June 30 2012	December 31 2011
Mariner swap (note 7c)	--	12,713
Onerous contracts	4	17
Provisions	4	12,730

Q2 2012 FS

Page 12

11.	Revenue

	The following summarizes the Company’s revenue:

	Three months ended June 30		Six months ended June 30
	2012	2011	2012	2011
Petroleum and natural gas sales	6,314	9,599	14,743	18,976
Royalties	(683)	(1,705)	(1,863)	(2,150)
	5,631	7,894	12,880	16,826

12.	Operating expense

	Operating costs for the Company are as follows:

	Three months ended June 30		Six months ended June 30
	2012	2011	2012	2011
Operating	3,458	2,989	7,294	6,106
Well workovers	776	215	1,253	803
	4,234	3,204	8,547	6,909

13.	Supplemental cash flow information

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

	Three months ended June 30		Six months ended June 30
	2012	2011	2012	2011
Accounts receivable	1,122	1,434	3,406	1,199
Prepaid expenses and deposits	282	297	89	457
Accounts payable and accrued liabilities	1,006	(12,622)	(7,674)	(15,685)
Provisions	(8)	(71)	(12,726)	(606)
Foreign currency translation adjustment	(1)	353	244	938
Change in non-cash working capital	2,401	(10,609)	(16,661)	(13,697)

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

	Three months ended June 30		Six months ended June 30
	2012	2011	2012	2011
Operating	456	1,654	1,550	1,089
Investing	1,945	(12,263)	(18,211)	(14,786)
Change in non-cash working capital	2,401	(10,609)	(16,661)	(13,697)

Q2 2012 FS

Page 13

14.	Share based compensation

	(a) Stock option plan

	The Company has a stock option plan for its directors, officers and employees. The exercise price for stock options granted is the quoted market price on 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 vest over four years with a maximum term of five years.

	Six months ended June 30, 2012		Twelve months ended December 31, 2011
	Number of options	Weighted average exercise price	Number of options	Weighted average exercise price
($ thousands, except per share price)
Balance, beginning of period	2,974	3.43	1,910	$5.78
Granted	747	2.36	1,984	3.49
Exercised	--	--	--	--
Forfeited	(288)	3.31	(920)	8.43
Balance, end of period	3,433	3.21	2,974	3.43

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

	Options outstanding			Options exercisable
Exercise price ($)	Number of options (thousands)	Average remaining contractual life (years)	Weighted average exercise price ($)	Number of options (thousands)	Weighted average exercise price ($)
1.93 – 2.50	792	4.69	2.36	--	--
2.51 – 3.00	716	3.93	2.85	299	2.86
3.01 – 4.00	1,071	8.09	3.10	985	3.09
4.01 – 11.80	854	8.33	4.42	722	4.45
1.93 – 11.80	3,433	6.50	3.21	2,006	3.54

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

	Six months ended June 30, 2012	Twelve months ended December 31,2011
Share price ($)	2.36	3.49
Exercise price ($)	2.36	3.49
Risk free rate (%)	1.5	2.0
Expected life (years)	3.7	3.7
Expected dividend yield (%)	--	--
Expected volatility (%)	78.1	87.6
Weighted average fair value of options granted ($)	1.32	2.13

Q2 2012 FS

Page 14

14.	Share based compensation (continued)

	A forfeiture rate of 25.5% (December 31, 2011 – 27.6%) was used when recording stock based compensation. This estimate is based on the historical forfeiture rate and adjusted to the actual forfeiture rate. Stock option expense incurred for the three and six months ended June 30, 2012 of $0.1 million and $0.4 million respectively (June 30, 2011 - $0.7 million and $1.5 million) was expensed. No stock based compensation expense was capitalized during 2012 or 2011.

	In the course of preparing the Financial Statements management identified an error in the comparative numbers for the three and six months ended June 30, 2011. The Company had previously recognized stock option expense of $1.0 million and $2.7 million for the three and six months respectively. This error was corrected in the audited consolidated financial statements and notes thereto for the year ended December 31, 2011.

	(b) Employee stock savings plan

	The Company has an employee stock savings plan (“ESSP”) in which employees are provided with the opportunity to receive a portion of their salary in common shares, which is then matched on a share for share basis by the Company. The Company purchased approximately 71,708 and 123,598 shares on the open market under the ESSP during the three and six months ended June 30, 2012 (June 30, 2011 – 32,770 and 59,562 shares). The costs related to this plan are expensed as incurred.

	(c) Stock unit awards

	At June 30, 2012, the Company had 1.4 million (December 31, 2011 – 1.5 million) stock unit awards outstanding, issued to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the applicable vesting date. The stock units have time and/or share based performance vesting terms which vary depending on whether the holder is an executive officer or director. If subsequent to the grant date, the shareholders of the Company approve an equity compensation plan under which the stock units may be paid with common shares of the Company, then the Board may determine that the stock units may be paid in cash or common shares. As of June 30, 2012, the Company recorded a liability of $1.8 million to recognize the fair value of the vested stock units (December 31, 2011 - $2.0 million). During the six months ended June 30, 2012, the Company paid $0.1 million to settle awards held by a director who retired from the Board.

	(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. In the six months ended June 30, 2012, 66,666 RSUs were redeemed for a total of $0.1 million (June 30, 2011 – Nil).

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

	Units outstanding			Units vested
Floor price ($)	Number of units (thousands)	Average remaining contractual life (years)	Weighted average floor price ($)	Number of units (thousands)	Weighted average floor price ($)
0.00 – 3.00	229	1.42	2.56	94	3.00
3.01 – 3.50	28	0.84	3.10	14	3.09
3.51 – 3.64	11	1.54	3.64	4	3.64
0.00 – 3.64	268	1.36	2.66	112	3.03

Q2 2012 FS

Page 15

14.	Share based compensation (continued)

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

	Valuation at June 30, 2012	Valuation at grant date
Share price ($)	1.79	2.47
Risk free rate (%)	1.0	1.5
Expected life (years)	1.4	2.4
Expected volatility (%)	55	55
Weighted average fair value ($)	0.81	1.99

Share based compensation is a recovery of $0.2 million for the three months ended June 30, 2012, due to a decrease in the liability associated with stock unit awards and restricted share units as a result of a lower share price and a reduction to the number of awards outstanding as a result of the retirement of a director. The following table summarizes share based compensation expense:

	Three months ended June 30		Six months ended June 30
	2012	2011	2012	2011
Stock option expense	130	731	372	1,535
Stock unit award expense	(141)	339	(18)	780
Restricted share unit expense	(150)	361	(193)	361
	(161)	1,431	161	2,676

The following table summarizes the share based compensation liability:

	June 30 2012	December 31 2011
Stock unit award liability	1,795	1,955
Restricted share unit liability	149	493
Share based compensation liability	1,944	2,448

15.	Segments and cash generating units

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

	(a) Western Canada

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

	(b) North Africa

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

Q2 2012 FS

Page 16

15.	Segments and cash generating units (continued)

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

Three months ended	Western Canada	North Africa	Total June 30, 2012	Western Canada	North Africa	Total – June 30, 2011
(CDN$ thousands)
Revenue
Revenue, net of royalties	5,631	--	5,631	7,894	--	7,894
Gain (loss) on commodity derivatives	554	--	554	1,121	--	1,121
	6,185	--	6,185	9,015	--	9,015
Expenses
Operating	4,234	--	4,234	3,204	--	3,204
Transportation	119	--	119	257	--	257
Exploration and evaluation	439	20,987	21,426	206	--	206
General and administrative	2,499	--	2,499	2,144	--	2,144
Depletion and depreciation	2,617	--	2,617	2,961	--	2,961
Share based compensation	(161)	--	(161)	1,431	--	1,431
Property, plant and equipment impairment	3,361	--	3,361	--	--	--
Loss on settlement of decommissioning liabilities	84	--	84	--	--	--
	13,192	20,987	34,179	10,203	--	10,203
Operating loss	(7,007)	(20,987)	(27,994)	(1,188)	--	(1,188)
Other
Financing costs (note 5)	(241)	--	(241)	(802)	--	(802)
Gain (loss) on foreign exchange	163	--	163	(1,020)	--	(1,020)
Gain on financial derivatives	--	--	--	2,255	--	2,255
Other income	42	--	42	3	--	3
	(36)	--	(36)	436	--	436
Income (loss) from continuing operations before income taxes	(7,043)	(20,987)	(28,030)	(752)	--	(752)
Current income taxes	--	--	--	120	--	120
Loss from continuing operations	(7,042)	(20,987)	(28,030)	(872)	--	(872)

Q2 2012 FS

Page 17

15.	Reportable segments and cash generating units (continued)

Six months ended	Western Canada	North Africa	Total June 30, 2012	Western Canada	North Africa	Total June 30, 2011
Revenue
Revenue, net of royalties	12,880	--	12,880	16,826	--	16,826
Gain (loss) on commodity derivatives	638	--	638	(543)	--	(543)
	13,518	--	13,518	16,283	--	16,283
Expenses
Operating	8,547	--	8,547	6,909	--	6,909
Transportation	315	--	315	516	--	516
Exploration and evaluation	1,325	20,987	22,312	370	--	370
General and administrative	5,335	--	5,335	4,387	--	4,387
Depletion and depreciation	5,712	--	5,712	6,243	--	6,243
Share based compensation	161	--	161	2,676	--	2,676
Property, plant and equipment impairment	16,241	--	16,241	--	--	--
Loss on settlement of decommissioning liabilities	84	--	84	775	--	775
	37,720	20,987	58,707	21,876	--	21,876
Operating loss	(24,202)	(20,987)	(45,189)	(5,593)	--	(5,593)
Other
Financing costs (note 5)	(499)	--	(499)	59	--	59
Gain (loss) on foreign exchange	(284)	--	(284)	2,633	--	2,633
Gain on financial derivatives	--	--	--	(548)	--	(548)
Other income	72	--	72	(1,453)	--	(1,453)
Gain on disposition of exploration and evaluation assets	73,361	--	73,361	--	--	--
	72,650	--	72,650	691	--	691
Income (loss) from continuing operations before income taxes	48,448	(20,987)	27,461	(4,902)	--	(4,902)
Current income taxes	35	--	35	120	--	120
Income (loss) from continuing operations	48,413	(20,987)	27,426	(5,022)	--	(5,022)

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

	Western Canada	North Africa	Total – As at June 30, 2012	Western Canada	North Africa	Total – As at December 31, 2011
(CDN$ thousands)
Assets
Current
Cash and cash equivalents	41,154	160	41,314	3,012	731	3,743
Accounts receivable	4,030	--	4,030	7,323	113	7,436
Prepaid expenses and deposits	1,468	34	1,502	1,488	40	1,528
	46,652	194	46,846	11,823	884	12,707
Long term portion of prepaid expenses and deposits	357	--	357	420	--	420
Exploration and evaluation assets	8,703	44,711	53,414	8,907	60,108	69,015
Property, plant and equipment	93,645	--	93,645	104,745	--	104,745
Total assets	149,357	44,905	194,262	125,895	60,992	186,887
Liabilities
Current
Accounts payable and accrued liabilities	9,352	629	9,981	15,906	1,749	17,655
Share based compensation liability	1,945	--	1,945	2,448	--	2,448
Provisions	4	--	4	17	12,713	12,730
Derivative financial liabilities	51	--	51	781	--	781
	11,352	629	11,981	19,152	14,462	33,614
Decommissioning provision	27,137	--	27,137	26,344	--	26,344
Total liabilities	38,489	629	39,118	45,496	14,462	59,958

Q2 2012 FS

Page 18

16.	Discontinued operations

	(a) Trinidad and Tobago

	On June 22, 2011, the Company completed the sale of its remaining 25% interest in Block 5(c) and the Mayaro-Guayaguayare block (“MG Block”) exploration and production license for cash proceeds of US$78.1 million and the assumption of the Company’s performance guarantee provided for the MG Block of US$12.0 million. On February 8, 2011, as part of the agreement, the Company had issued a US$20.0 million debenture to the purchaser. The debenture accrued interest at 6.0% per annum and was secured against the Company’s Block 5(c) interests. Upon closing of the agreement, the US$20.0 million was applied against the proceeds of US$78.1 million.

	Proceeds from disposition	(CDN$ thousands)
	Cash received	56,877
	Debenture retired	19,898
	MG Block performance guarantee assumed by purchaser	11,716
	Transaction costs	(583)
	Proceeds net of transaction costs	87,908

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

	(b) LNG Project

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

	(c) Financial information from discontinued operations

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

	Three months ended			Six months ended
For the three and six months ended June 30, 2011	Trinidad and Tobago	LNG Project	Total	Trinidad and Tobago	LNG Project	Total
(CDN$ thousands)
Expenses
General and administrative	(400)	(8)	(408)	(534)	(908)	(1,442)
Finance costs	(301)	--	(301)	(493)	--	(493)
Gain (loss) on disposition of foreign operations, net of realized foreign currency translation reserve	4,989	(389)	4,600	4,989	(389)	4,600
Income (loss) from discontinued operations	4,288	(397)	3,891	3,962	(1,297)	2,665
Foreign currency translation gain (loss) relating to assets and liabilities held for sale	542	8	550	(1,148)	20	(1,128)
Reclassified from foreign currency translation reserve to net earnings	5,976	389	6,365	5,976	389	6,365
Total comprehensive income (loss) from discontinued operations	10,806	--	10,806	8,790	(888)	7,902

Q2 2012 FS

Page 19

Document 2

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") has been prepared by management as of August 10, 2012, and reviewed and approved by the Board of Directors (the “Board”) of Sonde Resources Corp. (“Sonde”). This MD&A is a review of the operational results of Sonde. This MD&A should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ended December 31, 2011, and 2010. The reporting currency is the Canadian dollar unless otherwise stated.

Non-IFRS Measures – This MD&A contains references to funds from (used for) operations, funds from (used for) operations per share and operating netback, which are not defined under International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board and are therefore non-IFRS financial measures that do not have any standardized meaning prescribed by IFRS and are, therefore, unlikely to be comparable to similar measures presented by other issuers. Management of Sonde believes funds from (used for) operations, funds from (used for) operations per share and operating netback are relevant indicators of Sonde’s financial performance, and its ability to fund future capital expenditures. Funds from (used for) operations and operating netback should not be considered an alternative to or more meaningful than cash provided by (used in) operating activities, as determined in accordance with IFRS, as an indicator of Sonde's performance. In the operating netback and funds from (used for) operations section of this MD&A, reconciliation has been prepared to cash provided by (used in) operating activities, the most comparable measure calculated in accordance with IFRS.

Boe Presentation – Production information is commonly reported in units of barrel of oil equivalent ("boe"). For purposes of computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet to one barrel of oil (6:1). This conversion ratio of 6:1 is based on an energy equivalency conversion method primary applicable at the burner tip and does not represent a value equivalency at the wellhead. Such disclosure of 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 6:1, utilizing a conversion ratio of 6:1 may be misleading as an indication of value. Readers should be aware that historical results are not necessarily indicative of future performance. Natural gas production is expressed in thousand cubic feet (“mcf”). Oil and natural gas liquids are expressed in barrels (“bbls”).

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

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

business strategy, plans and priorities;

planned exploration and development activities;

potential restructuring of Sonde’s exploratory well commitment in North Africa;

planned capital expenditures;

expected sources of funding for the capital program;

expected increases in oil and gas production;

continued plans to seek financing through a partnering process for North Africa; and

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

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Undue reliance should not be placed on forward-looking information. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks which could cause actual results to vary and in some instances to differ materially from those anticipated by Sonde and described in the forward-looking information contained in this interim MD&A. Assumptions have been made regarding, among other things, operating conditions, management’s expectations regarding future growth, plans for and results of drilling activity, availability of capital , future commodity prices and differentials, and other expenditures. Material risk factors affecting forward-looking information include, but are not limited to:

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

risks and uncertainties involving geology of oil and gas deposits;

uncertainty related to production, marketing and transportation;

availability of experienced service industry personnel and equipment;

availability of qualified personnel and the ability to attract or retain key employees or members of management;

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

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

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

delays due to adverse weather conditions;

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

the outcome and effects of any future acquisitions and dispositions;

health, safety and environmental risks;

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

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

risks associated with competition from other producers;

changes in general economic and business conditions; and

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

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

Sonde operates in many different jurisdictions and could be adversely affected by violations of the Corruption of Foreign Public Officials Act (Canada) or the U.S. Foreign Corrupt Practices Act and similar worldwide anti-corruption laws. The Acts (collectively “FCPA”) and similar worldwide anti-corruption laws, including the U.K. Bribery Act 2010, generally prohibit companies and their intermediaries from making improper payments to government and other officials for the purpose of obtaining or retaining business. Sonde’s internal policies mandate compliance with these anti-corruption laws. Despite training and compliance programs, Sonde cannot be assured that internal control policies and procedures will always protect it from acts of corruption committed by employees or agents. Continued expansion outside Canada, including in developing countries, could increase the risk of such violations in the future. Violations of these laws, or allegations of such violations, could disrupt the business and result in a material adverse effect on Sonde’s financial condition, results of operations and cash flows.

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

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

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Business Overview and Strategy

Sonde Resources Corp. is a Calgary, Alberta, Canada based energy company engaged in the exploration for and production of oil and natural gas. Sonde’s operations are located in Western Canada and offshore North Africa. Sonde derives all of its production and cash flow from operations in Western Canada. Sonde’s Western Canadian oil and gas assets are primarily high working interest properties that are geographically concentrated in southern and west-central Alberta, the most significant being Sonde’s Southern Alberta cash generating unit (“CGU”) (or Greater Drumheller, Alberta area), which accounts for approximately 83% of Sonde’s production. The balance of production largely comes from the Kaybob/Windfall and Boundary Lake/Eaglesham areas in west-central Alberta. Sonde holds a Western Canadian land position of 388,038 gross (276,423 net) acres.

Sonde has drilled and fracked three of the five originally planned short radius horizontal oil wells in Michichi (Drumheller area). The last two wells were postponed, and the area workover and recompletion program suspended, due to capital conservation requirements and falling realized crude oil prices. Transportation capacity constraints for crude oil produced in Alberta has resulted in a large basis differential to the West Texas Intermediate (“WTI”) benchmark. Management has elected to defer additional drilling at Michichi until the basis differential returns to historical levels. The results of the first three wells will be announced after full recovery of frac oil and sustained production tests. Sonde has drilled and cased the 4-19-67-26W5, its first horizontal Montney exploration oil well (Ante Creek North area) and is planning to frac the well in mid-August. Sonde has continued to acquire acreage in the play and currently has 44,800 net acres of Montney rights at Waskahigan, Ante Creek North and Bezanson.

Sonde has licensed its first Duvernay horizontal well (also in the Ante Creek North area, spud date indefinite) and has continued to acquire acreage in the play. The Company currently has 78,720 net acres of Duvernay rights in the oil window in various parts of the basin where Sonde believes that improved reservoir quality will allow oil and condensate to be produced in commercial quantities. Management has continued regional core studies and other geologic investigations of the oil phase of the play, and are highly encouraged by its prospectivity when compared against proven oil resource plays such as the Bakken and Eagleford. In February 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 million.

Sonde continues to evaluate its natural gas properties in light of the low price environment. To date, Sonde has shut-in 375 boe/d (2,250 mcf/d) of operated and non-operated production. Management continues to work with operators and gas-processing facilities to reduce costs.

The Company continues to accumulate undeveloped acreage in oil-prospective areas in Alberta, with one significant new consolidated position of 41,120 net acres. Undeveloped acreage cost has been declining with the reduction in commodity prices, and Sonde is using a portion of available cash to build a large future drilling inventory at highly attractive prices. Sonde has been engaged in joint venture discussions with industry and financial partners to provide financial leverage and risk-mitigation in the early phases of these plays.

The ability to attract partners and the amount and timing of of Sonde’s activities in Western Canada are heavily dependent upon the outcome of Sonde’s efforts to find financial alternatives and restructure its North Africa commitments.

In December 2011 Sonde commenced the acquisition of 512 square kilometres of 3D seismic in accordance with the requirements of the Joint Oil Block Exploration and Production Sharing Agreement (“EPSA”). Sonde completed the acquisition in January 2012 and submitted the data for processing, with delivery of the final product received in the second quarter. In January 2012, Sonde engaged an advisor to identify and evaluate alternatives to finance Sonde’s remaining North Africa obligations. While the three exploratory well commitment is supported by a US$45 million corporate guarantee, the potential cost of drilling the wells could exceed US$100 million. Despite an extensive effort, Sonde has thus far been unable to obtain financing or find other arrangements on acceptable terms for the Joint Oil Block. Sonde believes this is due to a number of issues identified during the marketing process (see discussion below and under the “Contingencies and Commitments” section.) Sonde is continuing its efforts to secure alternate financing and is engaged in an effort to structure a plan to mitigate the risks posed by these issues. Sonde

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also plans to discuss these issues with Joint Oil in an effort to restructure its exploratory well commitment. Sonde may not be successful in any of these efforts.

Sonde plans to discuss with Joint Oil the restructuring of the three exploratory well commitment due to three key issues:

The Tunisia ministry of energy announced an initiative requiring Gulf of Gabes operators offshore Tunisia (which includes the Joint Oil Block) to study options for sequestration of carbon dioxide and other inert and acid gases to allow the currently trapped high inert content gas to be developed commercially and brought to the Tunisian market. This study is anticipated to take twelve to eighteen months.

The initial results indicate that the global demand for offshore drilling units is higher in other parts of the world than North Africa. Subsequent to June 30, 2012, one contractor submitted a technically acceptable bid for a jack up drilling rig that may be available in the second quarter of 2013. The commercial terms of their offer were unacceptable to Sonde.

Since the Zarat Field extends into an adjacent block, Joint Oil and Sonde must unitize the field with an adjacent license holder and agree upon a Unit Plan of Development.

No assurance can be provided that Sonde will be successful in finding financing alternatives, however the Company is looking at all options to meet its commitments under the EPSA. Neither Sonde nor interested parties can find merit in an additional discovery of high inert and acid gases at this time without a clear commercialization path that includes a solution to the inert and acid gas initiative. These issues, the resulting impairment recorded to the Joint Oil Block and the going concern paragraph are discussed in further detail in the “Contingencies and Commitments” section.

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

cautiously using available cash and borrowing capacity while waiting for the outcome of the North African unitization, exploitation and financing alternative program;

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

currently evaluating its entire acreage position and initiating an aggressive oil and liquids oriented, multi-year drilling program;

establishing organic growth through repeatable drilling programs;

providing shareholders access to high-leverage oil-oriented growth in Western Canada by annually purchasing significant lease acreage in emerging “oil-resource” plays such as the Montney and Duvernay oil plays; and

taking the actions necessary to preserve Sonde’s assets in North Africa while exploring options.

The success of Sonde’s ongoing operations are dependent upon several factors, including but not limited to, the price of energy commodity products, Sonde’s ability to manage price volatility (specifically North American natural gas), 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 or alternative third party financing, hiring and retaining qualified personnel and managing political and government risk, particularly with respect to its interests in North Africa.

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Operating netback and funds from (used for) operations

	($ thousands)			($ per boe)
Three months ended June 30	2012	2011	% change	2012	2011	% change
Petroleum and natural gas sales	6,314	9,599	(34)	29.45	40.82	(28)
Realized gain (loss) on financial instruments	(25)	110	--	(0.12)	0.47	--
Transportation	(119)	(257)	(54)	(0.56)	(1.09)	(49)
Royalties	(683)	(1,705)	(60)	(3.18)	(7.25)	(56)
	5,487	7,747	(29)	25.59	32.95	(22)
Operating expense	(3,458)	(2,989)	16	(16.13)	(12.71)	27
Well workover expense	(776)	(215)	--	(3.62)	(0.91)	--
Operating netback(2)	1,253	4,543	(72)	5.84	19.33	(70)
General and administrative	(2,499)	(2,553)	(2)	(11.66)	(10.86)	7
Foreign exchange gain (loss)	7	(55)	---	0.03	(0.23)	--
Interest and other income	42	3	--	0.20	0.01	--
Interest	(70)	(937)	(93)	(0.33)	(3.98)	(92)
Income taxes	--	(120)	--	--	(0.51)	--
Funds from (used for) operations(1,2)	(1,267)	881	(244)	(5.92)	3.76	(257)
Farm-in penalty (exploration expense)	(200)	--	--	(0.93)	--	--
Decommissioning expenditures	(151)	--	--	(0.70)	--	--
Changes in non-cash working capital	456	1,654	(72)	2.13	7.03	(70)
Cash provided by (used in) operating activities (1)	(1,162)	2,535	(146)	(5.42)	10.79	(150)

(1) Table includes both continuing and discontinued operations. Discontinued operations relate to the sale of certain exploration and production licenses in Trinidad and Tobago in June 2011 and the sale of a wholly-owned subsidiary, Liberty Natural Gas LLC, in February 2011. There were no revenues associated with discontinued operations, which consisted of nil (2011 – $0.4 million) general and administrative and nil (2011 – $0.2 million) interest expense.

(2) Non-IFRS measure.

For the three months ended June 30, 2012, funds used for operations was $1.3 million compared to funds from operations of $0.9 million for the same period in 2011. This was primarily the result of reduced operating netbacks as a result of significantly lower natural gas prices and lower production volumes. This was partially offset by a lower interest expense on repayment of debt in 2012.

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	($ thousands)			($ per boe)
Six months ended June 30	2012	2011	% change	2012	2011	% change
Petroleum and natural gas sales	14,743	18,976	(22)	31.75	39.39	(19)
Realized gain (loss) on financial instruments	(92)	186	--	(0.20)	0.39	--
Transportation	(315)	(516)	(39)	(0.68)	(1.07)	(36)
Royalties	(1,863)	(2,150)	(13)	(4.00)	(4.46)	(10)
	12,473	16,496	(24)	26.87	34.25	(22)
Operating expense	(7,294)	(6,106)	19	(15.71)	(12.68)	24
Well workover expense	(1,253)	(803)	56	(2.70)	(1.67)	62
Operating netback(2)	3,926	9,587	(59)	8.46	19.90	(57)
General and administrative	(5,335)	(5,830)	(8)	(11.49)	(12.10)	(5)
Foreign exchange gain (loss)	(395)	414	---	(0.85)	0.86	--
Interest and other income	72	59	22	0.16	0.12	33
Interest	(167)	(1,584)	(89)	(0.36)	(3.29)	(89)
Income taxes	(35)	(120)	(71)	(0.08)	(0.25)	(68)
Funds from (used for) operations(1,2)	(1,934)	2,526	(177)	(4.16)	5.24	(179)
Farm-in penalty (exploration expense)	(200)	--	--	(0.43)	--	--
Decommissioning expenditures	(151)	(846)	(82)	(0.33)	(1.76)	(81)
Changes in non-cash working capital	1,550	1,089	42	3.34	2.26	48
Cash provided by (used in) operating activities (1)	(735)	2,769	(127)	(1.58)	5.74	(128)

(1) Table includes both continuing and discontinued operations. Discontinued operations relate to the sale of certain exploration and production licenses in Trinidad and Tobago in June 2011 and the sale of a wholly-owned subsidiary, Liberty Natural Gas LLC, in February 2011. There were no revenues associated with discontinued operations, which consisted of nil (2011 – $1.4 million) general and administrative and nil (2011 – $0.4 million) interest expense.

(2) Non-IFRS measure.

For the six months ended June 30, 2012, funds used for operations was $1.9 million compared to funds from operations of $2.5 million for the same period in 2011. This was primarily the result of reduced operating netbacks as a result of significantly lower natural gas prices and lower production volumes. This was partially offset by a lower interest expense.

Production

	Q2	Q1	Q2	Six months ended
Commodity	2012	2012	2011	2012	2011
Natural gas (mcf/d)	9,665	11,553	11,509	10,609	11,941
Crude oil (bbls/d)	554	565	463	560	466
Natural gas liquids (bbls/d)	191	255	203	223	205
Total production (boe/d) (6:1)	2,356	2,746	2,584	2,551	2,661

	Q2	Q1	Q2	Six months ended
Region	2012	2012	2011	2012	2011
Southern Alberta (boe/d)	1,956	2,129	1,906	2,043	2,002
Central Alberta (boe/d)	217	408	377	312	315
Other Western Canada (boe/d)	183	209	301	196	344
Total production (boe/d) (6:1)	2,356	2,746	2,584	2,551	2,661

For the three months ended June 30, 2012, production averaged 2,356 boe/d. The decrease in production from the first quarter of 2012 is primarily due to decreased gas volumes due to shut-in gas wells and natural decline of gas reserves, along with a third party outage for the month of June in Central Alberta at

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SemCAM’s Kaybob South #3 plant. Sonde’s 13-17 well at Michichi recovered the last of its frac fluid in late May and added additional oil production in Southern Alberta for the month of June.

Petroleum and natural gas sales

	Q2	Q1	Q2	Six months ended
	2012	2012	2011	2012	2011
($ thousands, except where otherwise noted)
Petroleum and natural gas sales
Natural gas	1,844	2,314	4,087	4,158	8,694
Crude oil	3,406	4,673	4,191	8,079	7,723
Natural gas liquids	1,064	1,442	1,321	2,506	2,559
Transportation	(119)	(196)	(257)	(315)	(516)
Royalties	(683)	(1,180)	(1,705)	(1,863)	(2,150)
Realized gain (loss) on commodity derivatives	(25)	(67)	110	(92)	186
Total	5,487	6,986	7,747	12,473	16,496
Average sales price (including commodity derivatives)
Natural gas ($/mcf)	2.10	2.20	4.09	2.15	4.16
Crude oil ($/bbl)	67.10	89.54	97.35	78.44	90.32
Natural gas liquids ($/bbl)	61.07	62.08	71.35	61.65	68.61
Average sales price ($/boe)	29.33	33.47	41.29	31.56	39.78
AECO Gas ($/mcf)(1)	1.94	2.19	3.84	2.07	3.82
Edmonton Light ($/bbl) (1)	83.00	92.72	103.58	87.86	95.99

(1) Source: Independent qualified reserves evaluator.

For the three months ended June 30, 2012, petroleum and natural gas sales, net of transportation and royalties was $5.5 million, consisting of $1.8 million in natural gas, $3.4 million in crude oil and $1.1 million in natural gas liquids sales, less $0.7 million of royalties and $0.1 million of transportation costs. Sonde realized an average sales price of $29.33 per boe during the three months ended June 30, 2012 compared to $33.47 per boe in the three months ended March 31, 2012, exclusive of royalties and transportation, due to depressed natural gas prices and an increased negative differential between realized crude prices and the WTI benchmark.

For the six months ended June 30, 2012, petroleum and natural gas sales, net of transportation and royalties was $12.5 million, consisting of $4.2 million in natural gas, $0.1 million in realized losses on commodity derivatives, $8.1 million in crude oil and $2.5 million in natural gas liquids sales, less $1.9 million of royalties and $0.3 million of transportation costs. Sonde realized an average sales price of $31.56 per boe during the six months ended June 30, 2012 compared to $39.78 per boe in the six months ended June 30, 2011, exclusive of royalties and transportation, due to depressed natural gas and lower crude oil prices.

Royalties

	Q2	Q1	Q2	Six months ended
	2012	2012	2011	2012	2011
($ thousands, except where otherwise noted)
Royalties
Crown	435	922	1,396	1,357	1,871
Freehold and overriding	248	258	309	506	279
Total	683	1,180	1,705	1,863	2,150
Royalties per boe ($)	3.18	4.72	7.25	4.00	4.46
Average royalty rate (%)	11.1	14.5	18.0	13.0	11.5

Sonde pays royalties to provincial governments, freehold landowners and overriding royalty owners. Royalties are calculated and paid based on petroleum and natural gas sales net of transportation. Crown royalties on Alberta natural gas production are calculated based on the Alberta Reference Price, which

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may vary from Sonde’s realized corporate price, impacting the average royalty rate. In addition, various items impact the average royalty rate paid, such as cost of service credits and other royalty credit programs. Royalties on horizontal gas wells drilled in Alberta in 2011 and beyond generally bear royalties at a maximum of 5% for 18 months or until cumulative production reaches 50,000 boe. Horizontal oil wells generally bear royalties at a maximum of 5% for 18 to 48 months until cumulative production reaches 50,000 boe to 100,000 boe, depending on well depth. Sonde anticipates that production from wells drilled in 2012 would qualify for these lower royalty rates.

Natural gas and liquids royalties for the three months ended June 30, 2012 were $0.7 million or 11.1% of total petroleum and natural gas sales compared to 14.5% in in the three months ended March 31, 2012. The decrease is due primarily to lower realized prices and a positive Gas Cost Allowance adjustment.

Operating and well workover expense

Combined operating and well workover expenses for the three months ended June 30, 2012 were $4.2 million or $19.75 per boe, compared to $4.3 million or $17.26 per boe in the three months ended March 31, 2012. The decrease in aggregate expenses from the three months ended March 31, 2012, is due to decreased volumes, offset partially by an increase in well workovers. The increase in per-unit expenses is attributable to lower volumes for shut-in and declines in natural gas wells as a result of fixed operating costs and additional well workovers.

Capital expenditures

	Q2	Q1	Q2	Six months ended
	2012	2012	2011	2012	2011
($ thousands)
Exploration and evaluation	(851)	4,785	2,218	3,934	10,345
Drilling and completions	4,424	1,782	5,513	6,206	7,205
Plants, facilities and pipelines	797	2,050	807	2,847	2,187
Land and lease	1,392	754	1,456	2,146	1,628
Capital well workovers	488	569	75	1,057	133
Capitalized general and administrative expenses	1,382	861	722	2,243	1,758
Capital expenditures	7,632	10,801	10,791	18,433	23,256
Dispositions	--	(74,979)	(68,611)	(74,979)	(88,210)
Western Canada exploration and evaluation expense	(239)	(886)	(206)	(1,125)	(370)
Net capital expenditures	7,393	(65,064)	(58,026)	(57,671)	(65,324)

	Q2	Q1	Q2	Six months ended
	2012	2012	2011	2012	2011
($ thousands)
Canada	7,452	(70,825)	7,683	(63,373)	10,703
North Africa	(16)	5,433	1,979	5,417	10,956
Corporate Assets	(43)	328	278	285	637
Trinidad and Tobago	--	--	(67,966)	--	(87,620)
Net capital expenditures	7,393	(65,064)	(58,026)	(57,671)	(65,324)

Western Canada

For the three months ended June 30, 2012, Sonde drilled and fracked three of the five originally planned short radius horizontal oil wells in Michichi. The last two wells were postponed indefinitely due to capital conservation requirements and falling realized crude oil prices. Transportation capacity constraints for crude oil produced in Alberta has resulted in a large basis differential to the WTI benchmark. Management has elected to defer additional drilling at Michichi until the basis differential returns to historical levels. The three wells were completed using a diesel-based frac during the third quarter and will be tied in shortly. Sonde expects these wells to contribute production starting early in the fourth quarter after the recovery of

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all frac oil. In the third quarter Sonde spud its initial Montney oil well in Ante Creek North, with completion expected late in the third quarter.

Sonde continued its well re-activation program concentrated on an extensive portfolio of suspended wells. Sonde performed 43 net workovers and recompletions in the six months ended June 30, 2012. With the current downturn in natural gas prices, Sonde has not allocated capital to stemming the base decline on natural gas production, and instead is focused solely on maintaining existing liquids production while the drilling program is underway.

North Africa

On December 21, 2011, Sonde commenced the shooting of 512 square kilometres of 3D seismic in accordance with the requirements of the EPSA. Sonde completed the acquisition in January 2012 and submitted the data for processing, with delivery of the final product received in the second quarter. The seismic program was completed for $3.4 million, significantly under the initial expected cost of $6.3 million. On January 15, 2012, Sonde paid Joint Oil US$12.5 million under the terms of the Mariner Swap, which had been accrued as a capital expenditure in the year ended December 31, 2010.

Contingencies and commitments

North Africa

On August 27, 2008, Sonde entered into the EPSA with a Tunisian company, Joint Oil. Joint Oil is owned equally by the governments of Tunisia and Libya. The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, Sonde 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 Sonde 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 first phase of the exploration period has been extended until December 23, 2013, conditioned by Joint Oil on Sonde securing a rig for the three well commitment by the end of September 2012. Without this extension, the commitment must be met by December 23, 2012. In January 2011, Sonde announced the successful drilling and production testing of its 100% working interest in the Zarat North–1 well.

In January 2012, Sonde engaged an advisor to identify and evaluate alternatives to finance the Company’s remaining North Africa obligations. Information learned during the process throughout the three months ended June 30, 2012, has adversely impacted the currently available financing alternatives and may delay the outcome and drilling of the three exploratory wells. Sonde has recorded an impairment of $21.0 million to the Joint Oil Block as at June 30, 2012, charged to exploration and evaluation expense. This is a result of the following information:

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

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

·	Unitization and Plan of Development – Sonde has filed a Plan of Development with Joint Oil for the development of the Zarat field. Sonde expected Joint Oil to approve the plan of development expediently so that we could demonstrate to the market an asset with an approved Exploitation Plan.

Q2 2012 MD&A

Page 9

However, Joint Oil has deferred approval of Sonde’s Plan of Development pending negotiations with the other license holder and Entreprise Tunisienne d’Activities Petrolicres (ETAP) on Unitization and a Unit Plan of Development for Zarat, which will in the Company’s opinion be heavily dependent on the outcome of the inert and acid gases initiative described above. As a result, Sonde expects approval of its Zarat Plan of Development will be delayed for some time.

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

Despite an extensive effort, Sonde has thus far been unable to obtain financing or find other arrangements on acceptable terms for the Joint Oil Block. Sonde is continuing its efforts to secure alternate financing. Whether Sonde can secure additional financing for the North Africa three exploratory well commitment or the US$45.0 million penalty is uncertain. This uncertainty casts significant doubt on Sonde’s ability to continue as a going concern. Sonde continues to work to secure funding. Public and private debt and equity markets are not accessible now or in the near term on reasonable terms for exploratory or development projects on the Joint Oil Block and Sonde’s Western Canada operations will not provide sufficient cash flows to meet the exploratory commitment. Without access to third party financing or a party to assume the Joint Oil Block exploratory obligations, Sonde may not be able to continue as a going concern. Sonde’s consolidated financial statements as at June 30, 2012 and December 31, 2011 and for the three and six month periods ended June 30, 2012 and 2011, do not include any adjustments to the amounts and classification of assets (with the exception of a partial impairment of the Joint Oil Block component of the exploration and evaluation assets) and liabilities that may be necessary should Sonde be unable to continue as a going concern, and these adjustments could be material.

Litigation and claims

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

Liquidity and capital resources

	June 30	December 31
	2012	2011
($ thousands)
Cash and cash equivalents	41,314	3,743
Accounts receivable	4,030	7,436
Prepaid expenses and deposits	1,502	1,528
Accounts payable and accrued liabilities	(9,981)	(17,655)
Stock based compensation liability	(1,945)	(2,448)
Provisions	(4)	(12,730)
Derivative financial liabilities	(51)	(781)
Working capital surplus (deficit)	34,865	(20,907)

As at June 30, 2012, Sonde had a working capital surplus of $34.9 million (December 31, 2011 – $20.9 million deficit) and had issued three letters of credit for $0.2 million (December 31, 2011 – two letters of credit of $0.1 million) against the $30.0 million (December 31, 2011 - $40.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75% as at June 30, 2012 and at December 31, 2011.

Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of Sonde and a general security agreement covering all the assets of Sonde. Credit Facility A has covenants, as defined in Sonde’s credit agreement, that require Sonde to maintain an adjusted working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative expenditures in excess of $7.0 million per year and all foreign capital expenditures are not funded from Credit Facility A nor domestic cash flow

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Page 10

while Credit Facility A is outstanding. Sonde can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility. As at June 30, 2012, Sonde was in compliance with all debt covenants. Sonde is subject to the next semi-annual review of its credit facilities on or before September 30, 2012.

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

	2012	2013	2014	2015	2016	Thereafter	Total
Accounts payable and accrued liabilities	9,981	--	--	--	--	--	9,981
Stock based compensation liability	1,945	--	--	--	--	--	1,945
Derivative financial liabilities	51	--	--	--	--	--	51
North Africa exploration commitments	--	45,815	--	--	--	--	45,815
Office rent	681	1,212	1,212	1,217	1,233	7,159	12,714
Equipment	2	--	--	--	--	--	2
	12,660	47,027	1,212	1,217	1,233	7,159	70,508

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

General and administrative expenses

	Q2	Q1	Q2	Six months ended
	2012	2012	2011	2012	2011
($ thousands, except where otherwise noted)
Continuing operations
Gross general and administrative expense	3,892	3,685	2,867	7,577	6,145
Capitalized general and administrative expense	(1,381)	(861)	(722)	(2,242)	(1,758)
	2,511	2,824	2,145	5,335	4,387
Discontinued operations
Gross and net general and administrative expense	--	--	408	--	1,443
Total net general and administrative expense	2,511	2,824	2,553	5,335	5,830
General and administrative expense ($/boe)	11.66	11.35	10.86	11.49	12.10

For the three months ended June 30, 2012, gross general and administrative (“G&A”) expenses increased to $3.9 million from $3.7 million for the three months ended March 31, 2012. Gross G&A for continuing operations consists of $1.1 million (March 31, 2012 – $0.7 million) relating to North Africa and $2.8 million (March 31, 2012 – $3.0 million) related to Western Canada administration and corporate head office. This increase is due to $0.5 million in one-time charges related to the North Africa financing alternatives and $0.2 million in severance from a reduction in Western Canada staff levels. Sonde is working to reduce its break-even costs. As of June 30, 2012, Sonde had eliminated all consulting staff and reduced its Calgary head count by six employees and three full time consultants, expected to result in approximately $1.3 million in savings.

Depletion, depreciation and impairment

For the three months ended June 30, 2012, depletion and depreciation was $2.6 million or $12.21 per boe compared to $3.0 million or $12.59 per boe for the same period in 2011. The calculation of depletion and depreciation included an estimated $9.7 million (June 30, 2011 - $21.5 million) for future development capital associated with proved plus probable undeveloped reserves and excluded $51.7 million (June 30, 2011 – $62.2 million) related to exploration and evaluation assets. The variance is caused by a lower depletion base due to asset impairments for the three months ended March 31, 2012 and December 31, 2011, along with lower production volumes.

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Page 11

An impairment test was carried out on property, plant, and equipment at June 30, 2012, using the following forward commodity price projections:

Year	AECO Gas (Cdn/mmbtu) (1)	Edmonton Light Sweet Crude Oil (Cdn/bbl) (1)
2012 (Q3 – Q4)	$ 2.87	$ 79.08
2013	3.44	86.73
2014	3.90	95.92
2015	4.36	101.02
2016	4.82	101.02
2017	5.28	101.02
2018	5.68	102.40
2019	5.80	104.47
2020	5.91	106.58
2021	6.03	108.73
Remainder(2)	2.0%	2.0%
(1) Source: Independent qualified reserves evaluator’s price forecast, effective July 1, 2012.
(2) Percentage change represents the change in each year after 2021 to the end of the reserve life.

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. During the three months ended June 30, 2012, the Company recognized an impairment of $3.4 million to property, plant and equipment to reflect an expected decline in realized oil prices for future production as a result of an increased differential between the Edmonton Light Sweet Crude and WTI benchmarks. During the three months ended March 31, 2012, the Company recognized an impairment of $12.9 million to property, plant and equipment to reflect the low natural gas price environment for future production. Impairments recognized during the three months ended June 30, 2012 and March 31, 2012 were calculated using a 12% discount rate.

The Company’s net impairments by CGU were as follows:

Three months ended		Three months ended	Six months ended
June 30, 2012		March 31, 2012	June 30 2012
Northern Alberta CGU	951	709	1,660
Central Alberta CGU	--	2,444	2,444
Southern Alberta CGU	2,410	9,696	12,106
BC CGU	--	31	31
Property, plant and equipment impairment	3,361	12,880	16,241
Discount rate	12%	12%	12%
Reduction to impairment of using 10%	(2,721)	(8,515)	(11,236)
Increase to impairment of using 15%	9,659	10,417	20,076

Related party transactions

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

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Page 12

Share based compensation

	Q2	Q1	Q2	Six months ended
	2012	2012	2011	2012	2011
($ thousands)
Stock option expense	130	242	731	372	1,535
Stock unit award expense	(141)	123	339	(18)	780
Restricted share unit expense	(150)	(43)	361	(193)	361
Share based compensation	(161)	322	1,431	161	2,676

During the three months ended June 30, 2012, Sonde incurred a share based compensation recovery of $0.2 million compared to expense of $1.4 million for the three months ended June 30, 2011. The recovery is due to a decrease in the value of stock unit awards and restricted share unit awards as a result of cancelled awards and a decline in the Company’s share price.

The Restricted Share Unit Plan (“RSUs” or the “Plan”) became effective March 2011 to attract and retain experienced personnel with incentive compensation tied to shareholder return. Under the Plan, upon vesting each holder of RSUs will be entitled to, in respect of each RSU, a cash amount equal to the fair market value of one common share in the capital of Sonde on the vesting date. Under the Plan, RSUs vest over a three year period, subject to a minimum floor share price. In the six months ended June 30, 2012, 66,666 RSUs were redeemed for a total of $0.1 million (June 30, 2011 – Nil).

At June 30, 2012, the Company had 1.4 million (December 31, 2011 – 1.5 million) stock unit awards outstanding, issued to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the applicable vesting date. The stock units have time and/or share based performance vesting terms which vary depending on whether the holder is an executive officer or director. If subsequent to the grant date, the shareholders of the Company approve an equity compensation plan under which the stock units may be paid with common shares of the Company, then the Board may determine that the stock units may be paid in cash or common shares. As of June 30, 2012, the Company recorded a liability of $1.8 million to recognize the fair value of the vested stock units (December 31, 2011 - $2.0 million). During the six months ended June 30, 2012, the Company paid $0.1 million to settle awards held by a director who retired from the Board.

Share capital

As at August 10, 2012, Sonde had 62,301,446 common shares and 3,300,384 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 June 30, 2012, and is based on the balances disclosed in this MD&A and the consolidated financial statements for the three months ended June 30, 2012:

($ thousands)		Petroleum and Natural Gas Sales(1)
Change in average sales price for natural gas by $1.00/mcf		880
Change in the average sales price for crude oil and natural gas liquids by $1.00/bbl		68
Change in natural gas production by 1 mmcf/d (2)		191
Change in crude oil and natural gas liquids production by 100 bbls/d (2)		600

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

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

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Page 13

Commodity price risk

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

Three months ended

June 30, 2012

June 30, 2011

Term

Contract

Volume

Fixed Price

Realized loss

Unrealized gain

Realized gain (loss)

Unrealized gain (loss)

March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

$194

($97)

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($26)

$580

($84)

$1,108

Six months ended

June 30, 2012

June 30, 2011

Term

Contract

Volume

Fixed Price

Realized loss

Unrealized gain

Realized gain (loss)

Unrealized gain (loss)

March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

$291

$410

March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($92)

$730

($105)

($1,139)

Foreign exchange risk

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

	June 30	December 31
	2012	2011
(US$ thousands)
Cash and cash equivalents	6,971	1,020
North Africa receivables	--	111
Foreign denominated financial assets	6,971	1,131

North Africa payables	618	1,720
Mariner swap provision	--	12,500
Foreign denominated financial liabilities	618	14,220

These balances are exposed to fluctuations in the U.S. dollar. At this time, Sonde has chosen not to enter into any risk management agreements to mitigate foreign exchange risk. Sonde’s exposure to foreign currency exchange risk on its comprehensive income, assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent, is $0.5 million. This analysis assumes all other variables remain constant.

Interest rate risk

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

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Page 14

Credit risk

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

Sonde’s accounts receivable are with natural gas and liquids marketers and joint venture partners in the petroleum and natural gas business under substantially normal industry sale and payment terms and are subject to normal industry credit risks. Sonde’s credit risk exposure is as follows:

	June 30	December 31
	2012	2011
(CDN$ thousands)
Western Canada joint interest billings	1,810	2,830
Goods and Services Tax receivable	212	740
North Africa recoverable expenses	--	113
Revenue accruals and other receivables	2,008	3,753
Accounts receivable	4,030	7,436
Cash and cash equivalents	41,314	3,743
Credit exposure	45,344	11,179

The Company’s allowance for doubtful accounts is currently $1.8 million (December 31, 2011 – $2.0 million). This amount offsets $1.7 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2011 – $1.8 million) and $0.1 million of Western Canada joint interest and miscellaneous receivables (December 31, 2011 – $0.2 million). The Company considers all amounts greater than 90 days to be past due. As at June 30, 2012, $0.6 million of accounts receivable are past due, all of which are considered to be collectible.

Income taxes

Sonde’s current and future income taxes are dependent on factors such as production, commodity prices and tax classification of drilling costs related to exploration and development wells. At June 30, 2012, Sonde has estimated $306.6 million in tax pools (December 31, 2011 – $348.6 million) including $103.5 million in non-capital losses (December 31, 2011 – $126.0 million) that are available for future deduction against taxable income. The sale of undeveloped land in the six months ended June 30, 2012, reduced Canadian oil and gas property expense by approximately $46.6 million and non-capital losses by $28.4 million. Non-capital losses expire in the years 2026 – 2031.

	June 30	December 31
	2012	2011
(CDN$ thousands)
Canadian exploration expense	56,931	56,537
Canadian oil and gas property expense	--	44,474
Canadian development expense	37,554	31,905
Undepreciated capital costs	27,593	24,660
Foreign exploration expense	48,709	32,563
Non-capital losses	103,460	126,038
Capital losses	30,094	30,094
Share issue costs and other	2,285	2,285
	306,626	348,556

Off-balance sheet arrangements

Sonde has no off-balance sheet arrangements.

Q2 2012 MD&A

Page 15

Disclosure controls and procedures and internal control over financial reporting

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

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

Quarterly financial summary

($ thousands except per share and production amounts)

	2012	2012	2011	2011	2011	2011	2010	2010
	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Production
Natural gas (mcf/d)	9,665	11,553	12,186	12,673	11,509	12,377	14,140	12,417
Crude oil and natural gas liquids (bbl/d)	745	820	880	834	666	677	730	646
Total (boe/d)	2,356	2,746	2,911	2,946	2,584	2,740	3,087	2,716
Petroleum & natural gas sales (2)	5,487	6,986	9,445	9,011	7,747	8,749	10,002	7,847
Net income (loss) from continuing operations	(28,030)	55,456	(37,529)	(924)	(872)	(4,150)	(40,952)	(3,333)
Net income (loss) from continuing operations per share – basic and diluted	(0.45)	0.89	(0.60)	(0.01)	(0.01)	(0.07)	(0.66)	(0.05)
Net income (loss) (1)	(28,030)	55,456	(37,546)	(668)	3,019	(5,376)	(74,177)	(3,362)
Net income (loss) per share – basic and diluted(1)	(0.45)	0.89	(0.60)	(0.01)	0.05	(0.09)	(1.19)	(0.05)
Funds from (used for) operations (3)	(1,267)	(667)	3,155	1,945	881	1,645	871	2,528
Funds from (used for) operations per share – basic and diluted (3)	(0.02)	(0.01)	0.05	0.03	0.01	0.03	0.01	0.04

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

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

(3) Non-IFRS measures.

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

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

Fluctuations in Sonde’s petroleum and natural gas sales from quarter to quarter are primarily caused by variations in production volumes, realized oil and natural gas prices and the related impact of royalties.

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

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

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

Q2 2012 MD&A

Page 16

Additional Information

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

Q2 2012 MD&A

Page 17

Document 3

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

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

1.	Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended June 30, 2012.

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

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

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

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

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

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

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

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

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

5.2	N/A

5. 3	N/A

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

Date: August 10, 2012

(Signed) Jack W. Schanck__

Jack W. Schanck

Chief Executive Officer

Sonde Resources Corp.

Document 4

FORM 52-109F2

CERTIFICATION OF INTERIM FILINGS

FULL CERTIFICATE

I, Kurt A. Nelson, the Chief Financial Officer of Sonde Resources Corp., certify the following:

1.	Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended June 30, 2012.

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

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

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

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

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

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

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

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

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

5.2	N/A

5. 3	N/A

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

Date: August 10, 2012

(Signed) Kurt A, Nelson___

Kurt A. Nelson

Chief Financial Officer

Sonde Resources Corp.

SIGNATURES

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

		SONDE RESOURCES CORP.
		(Registrant)
Date:	August 10, 2012	By:	/s/ Kurt A. Nelson
			Name:	Kurt A. Nelson
			Title:	Chief Financial Officer