SOQ 6K 2013 Q2


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
2013
Commission File Number  
001-31395
 
 
 
 
Sonde Resources Corp.
(Translation of registrant’s name into English)
 
Suite 3100, 500 - 4th Avenue SW, Calgary, Alberta, Canada T2P 2V6
(Address of principal executive offices)

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

 
Form 40-F X
 


Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): _____
 
Note: Regulation S-T Rule 101(b)(1) only permits the submission in paper of a Form 6-K if submitted solely to provide an attached annual report to security holders.

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



DOCUMENTS INCLUDED AS PART OF THIS REPORT


Document
 
Description
 
 
 
 
 
 
1.
 
Financial Statements for the quarter ended June 30, 2013
 
 
 
2.
 
Management Discussion and Analysis for the quarter ended June 30, 2013
 
 
 
3.
 
News Release, dated August 1, 2013
 
 
 
4.
 
Canadian Form 52-109F2 Certification of Interim Filings – CEO
 
 
 
5.
 
Canadian Form 52-109F2 Certification of Interim Filings – CFO

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



Document 1


 
 
 
 
SONDE RESOURCES CORP. CONDENSED CONSOLIDATED
STATEMENTS OF FINANCIAL POSITION
Note
June 30
2013

December 31
2012

(CDN$ thousands)
(Unaudited)
 
 
 
Assets
 
 
 
Current
 
 
 
Cash and cash equivalents
5
16,136

19,695

Accounts receivable
6
10,491

4,683

Prepaid expenses and deposits
 
381

733

 
 
27,008

25,111

Long term portion of prepaid expenses and deposits
 
1,014

732

Exploration and evaluation assets
3
55,511

56,499

Property, plant and equipment
3
93,734

104,144

 
 
177,267

186,486

 
 
 
 
Liabilities
 
 
 
Current
 
 
 
Accounts payable and accrued liabilities
 
6,009

6,850

Share based compensation liability
4
633

1,074

 
 
6,642

7,924

Decommissioning provision
 
29,205

29,972

 
 
35,847

37,896

Contingencies and commitments
7
 
 
 
 
 
 
Shareholders’ Equity
 
 
 
Share capital
11
369,892

369,892

Contributed surplus
 
34,807

34,290

Foreign currency translation reserve
 
2,548

(34
)
Deficit
 
(265,827
)
(255,558
)
 
 
141,420

148,590

Going concern
2(b)
 
 
Segments
13
 
 
Subsequent event
14
 
 
 
 
177,267

186,486


See accompanying notes to the condensed consolidated financial statements

 
On behalf of the Board,
(Signed) “William Dirks”
 
(Signed) “W. Gordon Lancaster”
 
 
 
William Dirks
 
W. Gordon Lancaster
President and Chief Operating Officer
 
Director and Chair of the Audit Committee

 
   Q2 2013 Financial Statements | 1


SONDE RESOURCES CORP. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE (LOSS) INCOME
 
Three months ended
June 30
 
Six months ended
June 30
 
Note
2013

2012

2013

2012

(CDN$ thousands, except per share amounts)
(Unaudited)
 
 
 
 
 
Revenue
 
 
 
 
 
Revenue, net of royalties
9
6,236

5,631

13,020

12,880

Gain on commodity derivatives
6
—

554

—

638

 
 
6,236

6,185

13,020

13,518

Expenses
 
 
 
 
 
Operating
10
3,155

4,234

7,373

8,547

Transportation
 
165

119

342

315

Exploration and evaluation
3
998

21,426

2,953

22,312

General and administrative
 
2,274

2,499

5,098

5,335

Depletion and depreciation
3
2,246

2,617

4,783

5,712

Share based compensation
4
(35
)
(161
)
275

161

Property, plant and equipment impairment
3
—

3,361

—

16,241

(Gain) loss on settlement of decommissioning liabilities
 
(222
)
84

(222
)
84

 
 
8,581

34,179

20,602

58,707

Operating loss
 
(2,345
)
(27,994
)
(7,582
)
(45,189
)
 
 
 
 
 
 
Other
 
 
 
 
 
Financing costs
8
(236
)
(241
)
(425
)
(499
)
Gain (loss) on foreign exchange
 
20

163

42

(284
)
Other income
 
33

42

56

72

(Loss) gain on disposition of assets
3
(2,329
)
—

(2,360
)
73,361

 
 
(2,512
)
(36
)
(2,687
)
72,650

(Loss) income before taxes
 
(4,857
)
(28,030
)
(10,269
)
27,461

Current income taxes
 
—

—

—

35

Net (loss) income
 
(4,857
)
(28,030
)
(10,269
)
27,426

 
 
 
 
 
 
Other comprehensive income
 
 
 
 
 
Foreign currency translation adjustment
 
1,607

1,308

2,582

418

Total comprehensive (loss) income
 
(3,250
)
(26,722
)
(7,687
)
27,844

 
 
 
 
 
 
Net (loss) income per common share
 
 
 
 
 
Basic and diluted (loss) income per common share
11
$
(0.08
)
$
(0.45
)
$
(0.16
)
$
0.44


See accompanying notes to the condensed consolidated financial statements

 
   Q2 2013 Financial Statements | 2


SONDE RESOURCES CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Three months ended
June 30
 
Six months ended
June 30
 
Note
2013

2012

2013

2012

(CDN$ thousands)
(Unaudited)
 
 
 
 
 
Cash provided by (used in) by:
 
 
 
 
 
Operating
 
 
 
 
 
Net (loss) income
 
(4,857
)
(28,030
)
(10,269
)
27,426

Items not involving cash:
 
 
 
 
 
Depletion and depreciation
3
2,246

2,617

4,783

5,712

Share based compensation
4
(35
)
(161
)
275

161

Exploration and evaluation
3
998

21,226

2,953

22,112

Property, plant and equipment impairment
3
—

3,361

—

16,241

Unrealized gain on commodity derivatives
6
—

(579
)
—

(730
)
Unrealized gain loss on foreign exchange
 
(47
)
(156
)
(112
)
(111
)
Financing costs
8
236

241

425

499

Loss (gain) on disposition of exploration and evaluation assets
3
2,329

—

2,329

(73,361
)
Loss on disposition of property, plant and equipment
3
—

—

31

—

(Gain) loss on settlement of decommissioning liabilities
 
(222
)
84

(222
)
84

Actual decommissioning expenditures
 
(98
)
(151
)
(98
)
(151
)
Interest paid
 
(55
)
(70
)
(72
)
(167
)
Changes in non-cash working capital
12
(391
)
456

(390
)
1,550

 
 
104

(1,162
)
(367
)
(735
)
Financing
 
 
 
 
 
Exercise of restricted share units
4
(32
)
(65
)
(32
)
(150
)
Exercise of stock unit awards
4
—

(142
)
(165
)
(142
)
Revolving credit facility repayments
 
—

—



(23,400
)
Revolving credit facility advances
 
—

—



23,400

 
 
(32
)
(207
)
(197
)
(292
)
Investing
 
 
 
 
 
Property, plant and equipment additions
3
(52
)
(5,712
)
(1,072
)
(10,325
)
Exploration and evaluation additions
3
(1,038
)
(1,768
)
(2,043
)
(7,956
)
Proceeds on disposition of assets
3
—

—

296

74,979

Changes in non-cash working capital attributable to asset dispositions
3
5,837

—

5,837

—

Changes in non-cash working capital
12
(5,499
)
1,945

(6,125
)
(18,211
)
 
 
(752
)
(5,535
)
(3,107
)
38,487

(Decrease) increase in cash and cash equivalents
 
(680
)
(6,904
)
(3,671
)
37,460

Effect of foreign exchange on cash and cash equivalents
 
47

156

112

111

Cash and cash equivalents, beginning of period
 
16,769

48,062

19,695

3,743

Cash and cash equivalents, end of period
5
16,136

41,314

16,136

41,314


See accompanying notes to the condensed consolidated financial statements

 
   Q2 2013 Financial Statements | 3


SONDE RESOURCES CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(CDN$ thousands)
(Unaudited)
Share capital

Contributed surplus

Foreign currency translation

 
Deficit

 
Total

At December 31, 2011
369,892

33,528

550

(277,041
)
126,929

Total comprehensive loss
—

—

418

27,426

27,844

Stock option expense
—

371

—

—

371

At June 30, 2012
369,892

33,899

968

(249,615
)
155,144

(CDN$ thousands)
(Unaudited)
Share capital

Contributed surplus

Foreign currency translation

 
Deficit

 
Total

At December 31, 2012
369,892

34,290

(34
)
(255,558
)
148,590

Total comprehensive gain (loss)
—

—

2,582

(10,269
)
(7,687
)
Stock option expense
—

517

—

—

517

At June 30, 2013
369,892

34,807

2,548

(265,827
)
141,420

 
See accompanying notes to the condensed consolidated financial statements


 
   Q2 2013 Financial Statements | 4


NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2013
(All tabular amounts in CDN$ thousands, except where otherwise noted)
(Unaudited)

1.
Reporting entity

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

The condensed consolidated financial statements (the “Financial Statements”) comprise the Company and its subsidiaries, all of which are wholly owned. The Company’s shares are widely held and publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange MKT.

2.
Basis of presentation

(a)
Statement of compliance

The Financial Statements are prepared in accordance with International Accounting Standards 34 Interim Financial Reporting (“IAS 34”) and present the Company’s results of operations and financial position under International Financial Reporting Standards (“IFRS”) as at June 30, 2013 and December 31, 2012 and for the three and six month periods ended June 30, 2013 and 2012.

The Financial Statements were approved and authorized for issue by the Board on August 1, 2013.

(b)
Going concern

The Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and settlement of liabilities and commitments in the normal course of business and does not reflect adjustments that would otherwise be necessary if the going concern assumption was not valid. For the three months ended June 30, 2013, the Company had an operating loss of $2.3 million and an accumulated deficit of $265.8 million. Management believes that the going concern assumption is appropriate for the Financial Statements; however, items discussed in Note 7 – “Commitments and Contingencies”, describe significant uncertainties that cast substantial doubt over the Company’s ability to continue as a going concern. If this assumption is not appropriate, adjustments to the carrying amounts of assets and liabilities, revenues and expenses and the statement of financial position classifications used may be necessary and these adjustments could be material.

(c)
Basis of measurement

The Financial Statements have been prepared on the historical cost basis except as detailed in the Company’s accounting policies disclosed in the audited consolidated financial statements for the year ended December 31, 2012. On January 1, 2013, the Company adopted IFRS 10, 11, 12 and 13; the adoption of which did not have a material impact on the Financial Statements. The accounting policies have been applied consistently to all periods presented in the Financial Statements. The Financial Statements should be read in conjunction with the audited consolidated financial statements and notes thereto as at and for the year ended December 31, 2012.

(d)
Functional and presentation currencies

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

(e)
Use of estimates and judgment

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

 
   Q2 2013 Financial Statements | 5


3.
Exploration and evaluation assets and property, plant and equipment
 
Six months ended
Year ended
 
June 30, 2013
December 31, 2012
 
COST

ACCUM. DD&A

Carrying value

COST

ACCUM. DD&A

Carrying value

Exploration and evaluation assets
 
 
 
 
 
 
Beginning of period
79,234

(22,735
)
56,499

69,015

—

69,015

Additions
2,043

—

2,043

13,696

—

13,696

Dispositions
(2,596
)
—

(2,596
)
(1,647
)
—

(1,647
)
Farm-out proceeds
—

—

—

(995
)
—

(995
)
Impairments, to exploration expense
—

(2,953
)
(2,953
)
—

(22,735
)
(22,735
)
Foreign exchange
2,518

—

2,518

(835
)
—

(835
)
End of period
81,199

(25,688
)
55,511

79,234

(22,735
)
56,499

 
 
 
 
 
 
 
Property, plant and equipment
 

 

 

 

 

 

Beginning of period
239,124

(134,980
)
104,144

212,453

(107,708
)
104,745

Additions
1,072

—

1,072

23,506

—

23,506

Dispositions
(5,897
)
—

(5,897
)


—

—

Change in decommissioning obligations
(802
)
—

(802
)
3,165

—

3,165

Depreciation and depletion


(4,783
)
(4,783
)
—

(11,031
)
(11,031
)
Impairments
—

—

—

—

(16,241
)
(16,241
)
End of period
233,497

(139,763
)
93,734

239,124

(134,980
)
104,144


(a)
Western Canada exploration and evaluation assets

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

During the three and six months ended June 30, 2013 the Company capitalized $0.6 million and $1.4 million respectively (June 30, 2012 – $1.4 million and $2.2 million) of general and administrative expenses related to exploration and evaluation activities in North Africa ($0.2 million and $1.1 million respectively) and Western Canada ($0.4 million and $0.3 million respectively).

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

During the three months ended June 30, 2013 the Company executed a letter to sell to an unrelated third party 45,671 net acres of undeveloped land primarily in the Montney play and 44,094 acres of undeveloped land in the Duvernay play in Central Alberta. This land was classified as exploration and evaluation assets at March 31, 2013, and had a carrying value of $2.6 million. In addition, the Company sold related property, plant and equipment associated with the Montney play. This transaction is described in note 3 (c) below.

Land expiries and impairment on Western Canada exploratory wells charged to exploration and evaluation expense during the three and six months ended June 30, 2013 totaled $0.2 million and $0.4 million (June 30, 2012 – $0.2 million and $1.1 million). As at June 30, 2013, no indicators of impairment were identified in Western Canada that would imply a further decline in exploration and evaluation asset carrying values.

(b)
North Africa exploration and evaluation assets

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

 
   Q2 2013 Financial Statements | 6


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

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

This analysis assumed a wide range of potential future outcomes and a series of outcomes were modeled for each variable. All of the factors could individually influence the fair value. The most significant assumptions used in the determination of the fair value included:

•
the estimated low to medium probability of finding a commercial solution to the Inert and Acid Gas Initiative, which could have had an adverse or positive impact on the valuation;
•
the estimated start date of production under the high case scenarios was 2017. Both the base and low case scenarios were determined using delays of three to five years, respectively, in establishing production;
•
estimates of production rates and reserves of the unitized area included in the Joint Oil Block were based on a recent contingent resource study of the Joint Oil Block. Due to the uncertainties with estimating contingent resources, actual reserves ultimately discovered, if any, and the production, if any, from such discoveries may have been materially different than expected;
•
oil prices were estimated using base case scenarios of US$80 per barrel (“bbl”) derived from future expected Brent prices less an estimated differential. The low case scenarios used US$60/bbl and the high case scenarios at US$100/bbl. Future Brent prices were compared to Brent forward contract prices available in the market, as well as historical trends for Brent pricing; and
•
natural gas prices were estimated using base case scenarios of US$6 per million British thermal units (“mmbtu”) derived from Tunisian gas prices expected less an estimated differential. The low case scenarios used US$3/mmbtu and high case scenarios used US$9/mmbtu. Estimates were derived by looking at historical trends of Tunisian and European gas pricing and expectations for the future.
Given the number of quantitative and qualitative factors discussed above and in Note 7 (a), each with substantial uncertainties, and the interdependency of factors, the Company was unable to identify the sensitivities associated with individual factors. A number of the potential scenarios resulted in no value for the North African assets; however as of the date of the valuation management did not believe that they were the most probable outcomes and using the above described methodology and assumptions, the fair value of the North Africa assets was determined by the third party valuation firm to be $46.7 million less costs to sell of $0.5 million (which management determined was the most probable value in a range of possible values). This valuation resulted in the Company booking an impairment loss of $21.0 million during the year ended December 31, 2012.

On December 27, 2012, the Company entered into a farm-out agreement with Viking Exploration and Production Tunisia Limited (“Viking”). The commercial terms of the farm-out agreement are discussed in Note 7 (b). As per note 14 - "Subsequent events", the farm-out agreement was executed by Sonde and Viking on July 31, 2013. Formal closing remains conditioned upon obtaining all of the necessary consents and approvals.

The Company is evaluating a revised unit plan of development, which is subject to approval from Joint Oil, which will, if approved, result in a new development plan that will change the method of development, the costs and the production profile. Based on that fact, the Company evaluated whether the impairment recorded on the Joint Oil Block should be reversed or if further impairment was necessary. The Company believes that the recoverable amount for the North Africa E&E asset may exceed carrying value; however, management does not feel it is appropriate to reverse the previous impairment charges until a final unit plan of development is approved by Joint Oil. The Company has concluded that since there have been no changes to the facts and circumstances since December 31, 2012, the methodology employed during the year ended December 31, 2012 is the Company’s best estimate of fair value. All costs capitalized from January 1, 2013 to June 30, 2013 have been booked to exploration and evaluation expense.

(c)
Property, plant and equipment

During the three months ended March 31, 2013, the Company disposed of facilities with a net book value of $0.4 million for proceeds of $0.3 million, for a loss of $0.1 million (March 31, 2012 - nil).
During the three months ended June 30, 2013, the Company disposed of property, plant and equipment, primarily in the Montney play of Central Alberta, with a net book value of $5.5 million, and the related exploration and evaluation assets with a carrying value of $2.6 million, as discussed in note 3 (a) above, for total net proceeds of $5.8 million, resulting in a loss of $2.3 million (June 30, 2012 – nil).

 
   Q2 2013 Financial Statements | 7


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

An impairment test is performed on capitalized property plant and equipment costs at a cash-generating unit (“CGU”) level on an annual basis and quarterly when indicators of impairment exist. There were no indicators of impairment as at June 30, 2013. During the six months ended June 30, 2012, Sonde recorded an impairment of $16.2 million ($12.1 million in the Southern Alberta CGU, $2.4 million in the Central Alberta CGU, and $1.7 million in the Northern Alberta CGU) to reflect low natural gas prices. Impairments recognized during the six months ended June 30, 2012 were calculated using a 12% discount rate. Using a discount rate of 10% would have reduced the 2012 impairment by $11.2 million. Using a discount rate of 15% would have increased the 2012 impairment by $20.1 million.

4.
Share based compensation

(a)
Employee stock savings plan

The Company has an employee stock savings plan (“ESSP”) in which employees are provided with the opportunity to receive a portion of their salary in common shares, which is then matched on a share for share basis by the Company. The Company purchased approximately 184,645 shares with a value of $0.2 million on the open market under the ESSP during the six months ended June 30, 2013 (June 30, 2012 – 123,598 shares with a value of $0.2 million). The costs related to this plan are recorded as general and administrative expense as incurred.

(b)
Stock option plan

The Company has a stock option plan for its directors, officers and employees. The exercise price for stock options granted is the closing trading price on the Toronto Stock Exchange on the last trading day prior to the grant date. Options issued prior to May 2011 vest over three years with a maximum term of ten years. Options issued after May 2011 generally vest over four years with a maximum term of five years. The Board of Directors can at its discretion alter the vesting terms at the date of the grant.
For the period ended
June 30, 2013
 
December 31, 2012
 
 
Number
 of options

Weighted average exercise price

Number
 of options

Weighted average exercise price

($ thousands, except per share price)
 
 
 
 
Balance, beginning of period
4,728

$
2.40

2,974

$
3.43

Granted
—

—

2,504

1.37

Exercised
—

—

—

—

Forfeited
(108
)
2.69

(750
)
3.03

Balance, end of period
4,620

$
2.40

4,728

$
2.40


The following table summarizes stock options outstanding under the plan at June 30, 2013:

 
Options outstanding
Options exercisable
Exercise price ($)
Number of options (thousands)

Average remaining contractual life (years)

Weighted average exercise price ($)

Number of options (thousands)

Weighted average exercise price ($)

0.75 – 2.50
2,306

3.97

1.31

799

1.22

2.51 – 3.00
545

2.91

2.86

426

2.86

3.01 – 4.00
995

7.14

3.10

990

3.09

4.01 – 11.80
774

7.44

4.40

713

4.41

0.75 – 11.80
4,620

5.11

2.40

2,928

2.87


There were no options granted during the three months ended June 30, 2013. No stock based compensation expense was capitalized during 2013 or 2012.




 
   Q2 2013 Financial Statements | 8


4.
Share based compensation (continued)

(c)
Stock unit awards

At June 30, 2013 the Company had 1.1 million (December 31, 2012 – 1.2 million) stock unit awards outstanding, issued to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the applicable vesting date. The stock units have time and/or share based performance vesting terms which vary depending on whether the holder is an executive officer or director. As of June 30, 2013, the Company recorded a liability of $0.6 million to recognize the fair value of the vested stock units (December 31, 2012 - $0.9 million).

During the six months ended June 30, 2013, the Company paid $0.2 million to settle awards held by current and former directors (June 30, 2012 - $0.1 million).

(d)
Restricted share units

The Restricted Share Unit Plan became effective on March 24, 2011, to attract and retain experienced personnel with incentive compensation tied to shareholder return. Under the plan, each grantee will be entitled to, in respect of each Restricted Share Unit (“RSU”), a cash amount equal to the fair market value of one common share in the capital of the Company on such vesting date, with the vesting subject to a minimum floor share price and/or the lapse of time. During the six months ended June 30, 2013, 33,334 RSUs were redeemed for a total of $0.1 million (June 30, 2012, 66,666 RSUs were redeemed for a total of $0.1 million). The following table summarizes RSUs outstanding under the plan at June 30, 2013:

 
Units outstanding
Units vested
Floor price ($)
Number of units (thousands)

Average remaining contractual life (years)

Weighted average floor price ($)

Number of units (thousands)

Weighted average floor price ($)

0.00  – 3.00
195

0.51

3.00

101

3.00

3.01  – 3.50
3

0.54

3.27

2

3.27

3.51  – 3.64
9

0.54

3.64

6

3.64

0.00  – 3.64
207

0.51

3.03

109

3.04


The following table summarizes the share based compensation liability:

 
June 30
2013

December 31
2012

Stock unit award liability
568

909

Restricted share unit liability
65

165

Share based compensation liability
633

1,074


The following table summarizes share based compensation expense:

 
Three months ended
Six months ended
 
June 30
2013

June 30
2012

June 30
2013

June 30
2012

Stock option expense
210

130

517

372

Stock unit award expense
(201
)
(141
)
(175
)
(18
)
Restricted share unit gain
(44
)
(150
)
(67
)
(193
)
 
(35
)
(161
)
275

161



 
   Q2 2013 Financial Statements | 9


5.
Financial instruments

The Company uses a fair value hierarchy, discussed in Note 3 (g) of the December 31, 2012 financial statements, to categorize the inputs used to measure the fair value of its financial instruments. At June 30, 2013, all fair value measurements related to the Company’s financial instruments were categorized as level 1 in the fair value hierarchy. Cash and cash equivalents, stock unit awards, restricted share units, and derivatives, which include commodity contracts, are designated at fair value through profit or loss. Gains or losses related to periodic revaluation at each reporting period are recorded in net income or loss.

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

At June 30, 2013, cash and cash equivalents were comprised of $16.1 million of cash held at financial institutions (December 31, 2012 – $10.0 million in short term investment instruments and $9.7 million of cash held at financial institutions).

6.
Risk management

(a)
Commodity price risk

The Company enters into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility. These financial instruments are entered into solely for risk mitigation purposes and are not used for trading or other speculative purposes. In 2011, the Company sold a call option on a portion of the Company’s oil production from March 2011 through December 2012. The Company did not hold any such instruments at June 30, 2013. The gains and losses associated with this instrument are as follows:

Three months ended
 
 
 
June 30, 2013
June 30, 2012
Term
Contract
Volume
Fixed Price
Realized
gain (loss)
Unrealized
gain (loss)
Realized (loss)
Unrealized gain
March 1, 2011 – December 31, 2012
Call
250(Bbls/d)
$100($US/bbl)
—
—
$(25)
$579

Six months ended



June 30, 2013
June 30, 2012
Term
Contract
Volume
Fixed Price
Realized
gain (loss)
Unrealized
gain (loss)
Realized (loss)
Unrealized gain
March 1, 2011 – December 31, 2012
Call
250(Bbls/d)
$100($US/bbl)
—
—
$(92)
$730
 
(b)
Interest rate risk

The Company is exposed to interest rate risk as the credit facilities bear interest at floating market interest rates. The Company had no interest rate swaps or hedges to mitigate interest rate risk at June 30, 2013 or December 31, 2012. The Company’s exposure to fluctuations in interest expense assuming reasonably possible changes in the variable interest rate of +/- 1%, is insignificant. This analysis assumes all other variables remain constant.

(c)
Capital management

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

•
maintain a flexible capital structure which optimizes the costs of capital at an acceptable level of risk;
•
maintain sufficient liquidity to support ongoing operations, capital expenditure programs, strategic initiatives; and
•
maximize shareholder returns.

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


 
   Q2 2013 Financial Statements | 10


6.
Risk management (continued)

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

 
June 30
2013

December 31
2012

Share capital
369,892

369,892

Contributed surplus
34,807

34,290

Foreign currency translation reserve
2,548

(34
)
Deficit
(265,827
)
(255,558
)
Total capital
141,420

148,590


(d)
Foreign exchange risk

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

(US$ thousands)
June 30
2013

December 31
2012

Cash and cash equivalents
1,567

2,184

North Africa receivables
—

1

Foreign denominated financial assets
1,567

2,185

 
 
 
North Africa payables
441

566

Foreign denominated financial liabilities
441

566


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

(e) Liquidity risk

The Company generally relies on a combination of cash flow from operating activities and credit facility availability to fund its capital requirements and to provide liquidity for all operations.

(f) Credit risk

As at June 30, 2013 the Company’s allowance for doubtful accounts is $1.7 million (December 31, 2012 – $1.7 million). This amount offsets $1.8 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2012 – $1.8 million). The Company considers all amounts greater than 90 days to be past due. As at June 30, 2013, $1.0 million of accounts receivable are past due, all of which are considered to be collectible (December 31, 2012 - $0.9 million). As described in note 3 (c), the Company disposed of assets for net proceeds of $5.8 million ($6.1 million gross) during the three months ended June 30, 2013, all of which has been subsequently collected. The Company’s credit risk exposure is as follows:

(CDN$ thousands)
June 30
2013

December 31
2012

Western Canada joint interest billings
1,995

2,310

Revenue accruals and other receivables
8,496

2,373

Accounts receivable
10,491

4,683

Cash and cash equivalents
16,136

19,695

Maximum credit exposure
26,627

24,378


 
   Q2 2013 Financial Statements | 11


7.
Contingencies and commitments

(a)
North Africa Exploration and Production Sharing Agreement ("EPSA")

On August 27, 2008, the Company entered into an Exploration and Production Sharing Agreement (“EPSA”) with a Tunisian company, Joint Oil. Joint Oil is owned equally by the governments of Tunisia and Libya. The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, the Company is the operator. Under the EPSA, the minimum work program for the first phase (four years) of the seven year exploration period includes the Zarat North – 1 appraisal well, three exploration wells and 500 square kilometres of 3D seismic.

The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15.0 million per exploration well, and the Company has provided a corporate guarantee to a maximum of US$45.0 million to secure its minimum work program obligations. The potential cost of drilling the three wells could exceed US$100.0 million.
 
The Company recorded an impairment of $21.0 million to the Joint Oil Block during the year ended December 31, 2012, charged to exploration and evaluation expense. This was a result of the following information obtained during the second quarter of 2012:

•
Inert and Acid Gas Initiative – On June 12, 2012, DGE (Tunisian Direction Generale de L’Energie) announced an initiative for the Gulf of Gabes operators offshore Tunisia to study options for sequestration of carbon dioxide and other inert and acid gases (which comprise a high percentage of all known oil and gas accumulations in the Gulf of Gabes, including the Joint Oil Block) to allow the currently stranded high inert content gas to be developed commercially and brought to the Tunisian market. This initiative will ensure that the Zarat Development and other developments in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments with international organizations such as the Kyoto Accord on greenhouse gas emissions. This study is anticipated to take eighteen months. The Company is currently proposing a new unit plan of development which will allow for the re-injection of produced gases into the reservoir.
•
Drilling Rig Availability – The Company’s initial assessment indicated that the global demand for offshore drilling units was higher in other parts of the world than North Africa.
•
Unitization and Plan of Development – The Company filed a plan of development with Joint Oil for the development of the Zarat field. The Company expected Joint Oil to approve the plan of development expediently so that the Company could demonstrate to the market an asset with an approved exploitation plan. However, Joint Oil deferred approval of the Company’s Plan of Development pending negotiations with the other license holder and Entreprise Tunisienne d’Activities Petrolicres (ETAP) on Unitization and a unit plan of development for Zarat. The Company is currently proposing a new unit plan of development which will allow for the re-injection of produced gases into the reservoir. This will allow for a more cost effective development and the expedited receipt of liquids sales proceeds.
•
Exploratory Well Obligations – The Company planned to discuss with Joint Oil the timing of the three well exploratory commitment due to lack of availability of a suitable drilling rig. As discussed in Note 7 (b), on December 24, 2012 the Company received an extension on its exploratory well obligations until December 23, 2015.
(b)
North Africa exploratory well extension and farm-out

On December 24, 2012, Joint Oil approved the amendment to the EPSA allowing for the extension of the first phase of the exploration period under the EPSA to December 23, 2015. The extension provides for the drilling of three exploration wells, one each year, due December 23, 2013, 2014 and 2015. Penalties for non-fulfillment of the minimum work program are US$15.0 million for each well. In addition, the extension provides for the acquisition and processing of 200 square kilometers of 3D seismic in the Libyan sector of the Joint Oil Block, estimated to cost US$3.5 million, beginning in the third quarter of 2013.







 
   Q2 2013 Financial Statements | 12


7.
Contingencies and commitments (continued)
On December 27, 2012, the Company entered into a farm-out agreement with Viking covering the Joint Oil Block. The farm-out agreement initially contained the following terms:
•
Viking would pay Sonde in total a US$3.0 million non-refundable signature bonus. As at December 31, 2012, US$1.0 million of the signature bonus had been received by the Company and credited against exploration and evaluation assets, with the remaining US$2.0 million due upon formal closing;
•
Viking would assume responsibility for the three well exploration commitment under the terms of the EPSA and fund 100% of the Joint Oil Block share of the Unit Plan of Development for the Zarat Field. The first well, Fisal, is to be drilled in 2013 along with the acquisition of 3D seismic data in Libyan waters;
•
Viking would provide to Sonde, prior to closing, the appropriate form of corporate guarantee with the agreed upon commercial terms from one of their affiliated companies, in order to secure the remaining work commitment under the terms of the EPSA;
•
Sonde would receive 20% of the cost recovery and profit share revenue until Sonde recovers US$70 million. After payout of all Sonde and Viking expenditures, the revenue will be split 33.33% to Sonde and 66.67% to Viking;
•
Sonde retained the option to fund its 33.33% share of the last two of the exploration wells; and
•
Any future discoveries would be shared 33.33% to Sonde and 66.67% to Viking.
The initial farm-out agreement was subject to the following conditions:
•
Viking (or one of its affiliates) was to provide Sonde with a corporate guarantee sufficient to offset the current US$45.0 million guarantee for the potential penalties in respect of the three well drilling commitment and 3D seismic; and
•
Joint Oil would consent to the transfer of the interest to Viking as a second party to the EPSA and the naming of Viking as Operator of the Joint Oil Block under the EPSA.
On May 3, 2013, Sonde received approval from Joint Oil's Board of Directors to farm-out 66.67% of its potential Zarat Field Unit Area and 50% of the remainder of its interest in the Joint Oil Block to Viking. In order to receive Joint Oil approval, certain terms of the farm-out agreement as described above were required to be amended. The amendments to the initial farm-out agreement as discussed above are as follows:
•
Sonde will remain the operator of the Joint Oil Block;
•
Sonde and Viking will post a bank guarantee equivalent to US$50.995 million as a guarantee for the 2013 through 2015 work obligations the (“Bank Guarantee”). Viking will contribute US$40 million to the guarantee and Sonde will contribute US$10.995 million (the “Balance”) to the guarantee. Amounts under the Bank Guarantee will be released in accordance with a pre-determined formula as the work obligations are performed;
•
Viking will acquire a 66.67% participating interest and Sonde will retain a 33.33% participating interest in the Zarat Field Unit Area;
•
In consideration for contributing the Balance, Sonde will retain a 50% participating interest in the Joint Oil Block that is not covered by the exploitation area around the Zarat Field development. In addition, Sonde will recover US$11.0 million and 20% of the cost recovery and profit share revenue until Sonde recovers US$70.0 million. After payout of all Viking expenditures, the revenue will be split 33.33% to Sonde and 66.67% to Viking in the Zarat Field Unit Area;
•
Any future discoveries will be shared 50% to Sonde and 50% to Viking; and
•
The EPSA terms are the reference for and shall govern the Petroleum Operations under the EPSA as amended on January 17, 2013.
Joint Oil's approval of the assignment to Viking was subject to approval of the definitive form of Assignment Agreement and format of the Bank Guarantee (discussed above). Completion of the assignment required the execution of the definitive amendment to the farm-out agreement with Viking and closing of the farm-out.

As per note 14 - "Subsequent events", the farm-out agreement was executed by Sonde and Viking on July 31, 2013. Formal closing remains conditioned upon obtaining all of the necessary consents and approvals.

 
   Q2 2013 Financial Statements | 13


7.
Contingencies and commitments (continued)
(c)
Commitments and financial liabilities

The Company generally relies on a combination of cash flow from operating activities, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for domestic and international operations. At June 30, 2013, the Company has committed to future payments over the next five years and thereafter, as follows:
 
2013

2014

2015

2016

2017

Thereafter

Total

Accounts payable and accrued liabilities
6,009

—

—

—

—

—

6,009

Share based compensation liability
633

—

—

—

—

—

633

North Africa exploration commitments (note 7 (a), (b))
19,458

15,777

15,777

—

—

—

51,012

Office rent payable
606

1,212

1,217

1,233

1,233

5,925

11,426

Office rent receivable
—

(404
)
(1,014
)
(1,233
)
(1,233
)
(5,925
)
(9,809
)
 
26,706

16,585

15,980

—

—

—

59,271


(d)
Litigation and claims

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

8.
Short term debt and financing costs

As at June 30, 2013, the Company had issued four letters of credit for $0.3 million (December 31, 2012 – three letters of credit for $0.2 million) against the $25.0 million (December 31, 2012 - $30.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75%.

Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company. Credit Facility A has covenants, as defined in the Company’s credit agreement, that require the Company to maintain an adjusted working capital ratio of 1:1 or greater and to ensure that non-domestic general and administrative and capital expenditures are funded from cash flow, equity and proceeds from foreign asset sales. The Company can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility.

As at June 30, 2013, the Company was in compliance with all of its debt covenants. The Company is subject to a review of its credit facilities on or before August 1, 2013.

Financing costs for the Company were as follows:
 
Three months ended
Six months ended
 
June 30
2013

June 30
2012

June 30
2013

June 30
2012

Accretion of decommissioning provision
181

171

353

332

Interest on credit facilities
55

70

72

167

 
236

241

425

499


 
   Q2 2013 Financial Statements | 14


9.
Revenue

The following summarizes the Company’s revenue:
 
 
Three months ended
Six months ended
 
June 30
2013

June 30
2012

June 30
2013

June 30
2012

Petroleum and natural gas sales
6,867

6,314

14,116

14,743

Royalties
(631
)
(683
)
(1,096
)
(1,863
)
 
6,236

5,631

13,020

12,880

 
10.
Operating expense

Operating costs for the Company are as follows:
 
 
Three months ended
Six months ended
 
June 30
2013

June 30
2012

June 30
2013

June 30
2012

Operating
3,033

3,458

6,659

7,294

Well workovers
122

776

714

1,253

 
3,155

4,234

7,373

8,547

 

11.
Share capital

The number of common and preferred shares authorized, each with no par value, is unlimited.

For the three and six months ended June 30, 2013 and June 30, 2012, the basic weighted average common shares outstanding was 62,301,446. For the three and six months ended June 30, 2013, the diluted weighted average common shares outstanding was 62,466,466 and 62,773,323 respectively (three and six months ended June 30, 2012 – 62,301,446 and 62,304,026). For the calculation of diluted earnings per share the Company excluded 2.9 million and 3.0 million options that are anti-dilutive for the three and six months ended June 30, 2013 (June 30, 2012 – 3.5 million and 3.2 million).
 
12.
Supplemental cash flow information

The changes in non-cash working capital are as follows:
 
 
Three months ended
Six months ended
 
June 30
2013

June 30
2012

June 30
2013

June 30
2012

Accounts receivable
(5,858
)
1,122

(5,808
)
3,406

Prepaid expenses and deposits
130

282

70

89

Accounts payable and accrued liabilities
(189
)
1,006

(841
)
(7,674
)
Provisions
—

(8
)
—

(12,726
)
Foreign currency translation adjustment
27

(1
)
64

244

Change in non-cash working capital
(5,890
)
2,401

(6,515
)
(16,661
)


 
   Q2 2013 Financial Statements | 15


12.
Supplemental cash flow information (continued)

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

 
Three months ended
Six months ended
 
June 30
2013

June 30
2012

June 30
2013

June 30
2012

Operating
(6,228
)
456

(6,227
)
1,550

Investing
338

1,945

(288
)
(18,211
)
Change in non-cash working capital
(5,890
)
2,401

(6,515
)
(16,661
)

13.
Segments and cash generating units

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

(a)
Western Canada

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

(b)
North Africa

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

The Company has five cash-generating units (“CGUs”), including the North Africa CGU, which is classified as exploration and evaluation assets. The four remaining CGUs are included in the Western Canada reportable segment and include Northern Alberta, Central Alberta, Southern Alberta and British Columbia. The CGUs have been chosen primarily based on their geographical location, similar reservoir characteristics, similar development plans, shared infrastructure, discrete processing and gathering facilities, regulatory regimes (e.g. Alberta vs. British Columbia) and management’s basis for internal reporting and monitoring. The statements of financial position by operating segment as at June 30, 2013 and December 31, 2012 are as follows:

As at
June 30, 2013
December 31, 2012
(CDN$ thousands)
Western
 Canada

North
Africa

Total

Western
 Canada

North
Africa

Total

Assets
 
 
 
 
 
 
Current
 
 
 
 
 
 
Cash and cash equivalents
15,189

947

16,136

18,024

1,671

19,695

Accounts receivable
10,491

—

10,491

4,682

1

4,683

Prepaid expenses and deposits
360

21

381

714

19

733

 
26,040

968

27,008

23,420

1,691

25,111

Long term portion of prepaid expenses and deposits
1,014

—

1,014

732

—

732

Exploration and evaluation assets
9,320

46,191

55,511

11,799

44,700

56,499

Property, plant and equipment
93,734



93,734

104,144



104,144

Total assets
130,108

47,159

177,267

140,095

46,391

186,486

Liabilities
 
 
 
 
 
 
Current
 
 
 
 
 
 
Accounts payable and accrued liabilities
5,545

464

6,009

6,288

562

6,850

Share based compensation liability
633

—

633

1,074

—

1,074

 
6,178

464

6,642

7,362

562

7,924

Decommissioning provision
29,205

—

29,205

29,972

—

29,972

Total liabilities
35,383

464

35,847

37,334

562

37,896


 
   Q2 2013 Financial Statements | 16


13.
Segments and cash generating units (continued)

The statements of operations for the three months ended June 30, 2013 and June 30, 2012 by operating segment are as follows:

Three months ended
June 30, 2013
June 30, 2012
 
Western
 Canada

North
Africa

Total

Western
 Canada

North
Africa

Total

Revenue
 

 

 

 

 

 

Revenue, net of royalties
6,236

—

6,236

5,631

—

5,631

Gain on commodity derivatives
—

—

—

554

—

554

 
6,236

—

6,236

6,185

—

6,185

Expenses
 

 

 

 

 

 

Operating
3,155

—

3,155

4,234

—

4,234

Transportation
165

—

165

119

—

119

Exploration and evaluation
247

751

998

439

20,987

21,426

General and administrative
2,274

—

2,274

2,499

—

2,499

Depletion and depreciation
2,246

—

2,246

2,617

—

2,617

Share based compensation
(35
)
—

(35
)
(161
)
—

(161
)
Property, plant and equipment impairment
—

—

—

3,361

—

3,361

(Gain) loss on settlement of decommissioning liabilities
(222
)
—

(222
)
84

—

84

 
7,830

751

8,581

13,192

20,987

34,179

Operating loss
(1,594
)
(751
)
(2,345
)
(7,007
)
(20,987
)
(27,994
)
Other
 

 

 

 

 

 

Financing costs
(236
)
—

(236
)
(241
)
—

(241
)
Gain (loss) on foreign exchange
20

—

20

163

—

163

Other income
33

—

33

42

—

42

(Loss) gain on disposition of assets
(2,329
)
—

(2,329
)
—

—

—

 
(2,512
)
—

(2,512
)
(36
)
—

(36
)
(Loss) income before income taxes
(4,106
)
(751
)
(4,857
)
(7,043
)
(20,987
)
(28,030
)
Current income taxes
—

—

—

—

—

—

Net (loss) income
(4,106
)
(751
)
(4,857
)
(7,043
)
(20,987
)
(28,030
)


























 
   Q2 2013 Financial Statements | 17


13.
Segments and cash generating units (continued)

The statements of operations for the six months ended June 30, 2013 and June 30, 2012 by operating segment are as follows:

Six months ended
June 30, 2013
June 30, 2012
 
Western
 Canada

North
Africa

Total

Western
 Canada

North
Africa

Total

Revenue
 
 
 
 
 
 
Revenue, net of royalties
13,020

—

13,020

12,880

—

12,880

Gain on commodity derivatives
—

—

—

638

—

638

 
13,020

—

13,020

13,518

—

13,518

Expenses
 
 
 
 
 
 
Operating
7,373

—

7,373

8,547

—

8,547

Transportation
342

—

342

315

—

315

Exploration and evaluation
413

2,540

2,953

1,325

20,987

22,312

General and administrative
5,098

—

5,098

5,335

—

5,335

Depletion and depreciation
4,783

—

4,783

5,712

—

5,712

Share based compensation
275

—

275

161

—

161

Property, plant and equipment impairment
—

—

—

16,241

—

16,241

(Gain) loss on settlement of decommissioning liabilities
(222
)
—

(222
)
84

—

84

 
18,062

2,540

20,602

37,720

20,987

58,707

Operating loss
(5,042
)
(2,540
)
(7,582
)
(24,202
)
(20,987
)
(45,189
)
Other
 
 
 
 
 
 
Financing costs
(425
)
—

(425
)
(499
)
—

(499
)
Gain (loss) on foreign exchange
42

—

42

(284
)
—

(284
)
Other income
56

—

56

72

—

72

(Loss) gain on disposition of assets
(2,360
)
—

(2,360
)
73,361

—

73,361

 
(2,687
)
—

(2,687
)
72,650

—

72,650

(Loss) income before income taxes
(7,729
)
(2,540
)
(10,269
)
48,448

(20,987
)
27,461

Current income taxes
—

—

—

35

—

35

Net (loss) income
(7,729
)
(2,540
)
(10,269
)
48,413

(20,987
)
27,426


14.
Subsequent events

On July 16, 2013, the Company closed the sale of assets as discussed in note 3 (a) and (c).
On July 31, 2013, the Viking farm-out agreement was executed by Sonde and Viking. Formal closing remains conditioned upon obtaining all of the necessary consents and approvals.

    


 
   Q2 2013 Financial Statements | 18


Document 2


MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") has been prepared by management as of August 1, 2013, and reviewed and approved by the Board of Directors (the “Board”) of Sonde Resources Corp. ("Sonde" or the "Company").
 
Effective January 1, 2011 the Company adopted International Financial Reporting Standards (“IFRS”). This MD&A should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ended December 31, 2012 and 2011.

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

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

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

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

•
the impact of the closing of the Viking Exploration and Production Tunisia Limited (“Viking”) farm-out agreement on the Company's future plans for the Joint Oil Block;
•
expected sources of funding for the capital program;
•
the ability to locate and secure an offshore drilling rig for the Fisal and future drilling obligations in North Africa;
•
the proposed unitization of the Zarat field and development of a revised Zarat field unit plan of development reflecting the re-injection of gas;
•
business strategy, plans, priorities and planned exploration and development activities;
•
exploration potential relating to the Company’s Western Canadian properties;
•
the possible results of Sonde’s strategic alternatives process beyond the sale of the primarily Montney undeveloped lands and related wells in Western Canada and the impact it may have on sources of funding for future exploration and development activities;
•
expected volume and product mix of the Company's oil and gas production and future oil and gas prices and interest rates in respect of the Company's risk management programs;
•
other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance; and
•
the Company's tax pools.
Undue reliance should not be placed on forward-looking information. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks which could cause actual results to vary and in some instances to differ materially from those anticipated by the Company and described in the forward-looking information contained in this interim MD&A. The material risk factors include, but are not limited to:

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

 
Q2 2013 MD&A | 1


•
uncertainty related to production, marketing and transportation;
•
availability of experienced service industry personnel and equipment;
•
availability of qualified personnel and the ability to attract or retain key employees or members of management;
•
the uncertainty of reserves estimates, reserves life and underlying reservoir risk;
•
the uncertainty of estimates and projections relating to production, costs and expenses;
•
potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
•
delays due to adverse weather conditions;
•
fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;
•
the outcome and effects of any future acquisitions and dispositions;
•
health, safety and environmental risks;
•
uncertainties as to the availability and cost of financing and changes in capital markets;
•
risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action);
•
risks associated with competition from other producers;
•
changes in general economic and business conditions;
•
the possibility that government policies or laws may change or government approvals may be delayed or withheld;
•
the impact on the Company’s financing abilities relating to its North African obligations;
•
the negotiation of the proposed unitization of the Zarat field; and
•
general economic, market and business conditions.
The foregoing list of risk factors is not exhaustive. Additional information on these and other factors which could affect the Company’s operations or financial results are included in the Company’s most recent Annual Information Form. In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission. Forward-looking information is based on the estimates and opinions of the Company’s management at the time the information is presented. The Company assumes no obligation to update forward-looking information should circumstances or management’s estimates or opinions change, except as required by law. Statements contained in this document relating to estimates, results, events and expectations are forward-looking statements within the meaning of Section 27A of the United States Securities Act of 1933, as amended and Section 21E of the United States Securities Exchange Act of 1934, as amended.

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

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

 
Q2 2013 MD&A | 2


Business overview and strategy

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

Western Canada

The Company derives all of its production and cash flow from operations in Western Canada. The Company’s Southern Alberta cash generating unit (“CGU”), (or Greater Drumheller, Alberta area), accounts for approximately 85% of the Company’s production. The balance of production comes largely from the Kaybob/Windfall and Boundary Lake/Eaglesham areas in west-central Alberta. The Company’s Western Canadian oil and gas assets are primarily high potential, high working interest producing properties which are complemented by a portfolio of highly prospective undeveloped land positions throughout Greater Alberta.

Western Canada Strategic Alternatives Process

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

During the three months ended June 30, 2013 the Company executed a letter to sell to an unrelated third party 45,671 net acres of undeveloped land primarily in the Montney play and 44,094 acres of undeveloped land in the Duvernay play in Central Alberta. This land was classified as exploration and evaluation assets at March 31, 2013 and had a carrying value of $2.6 million. In addition, the Company sold related property, plant and equipment associated with the Montney play with a net book value of $5.5 million. These assets were sold for total net proceeds of $5.8 million, resulting in a loss of $2.3 million. This sale closed on July 16, 2013.

The Company has exited the Montney play and divested certain licenses which contain Duvernay rights. Sonde retains undeveloped acreage in the Duvernay (54,648 acres net), Wabamun (50,736 acres net) and Detrital/Banff (46,677 acres net) plays. Of these lands, 85% have been purchased within the past 18 months, and as such, there are no land expiry issues. These land positions are typically large, consolidated and 100% working interest holdings with outstanding characteristics and growth potential.

The Board has established a Special Committee comprised of independent directors to oversee the strategic review process. Various prospects and options continue to be evaluated by the Special Committee.

2013 Western Canada Drilling Program

No wells were drilled during the three and six months ended June 30, 2013 due to the strategic alternatives process discussed above. During the three and six months ended June 30, 2013, Sonde continued its well re-activation program. Sonde performed 13 and 27 net workovers and recompletions during the three and six months ended June 30, 2013.

North Africa

On December 27, 2012, the Company entered into a farm-out agreement with Viking covering the Joint Oil Block. On July 31, 2013, the farm-out agreement was executed by Sonde and Viking. Formal closing remains conditioned upon obtaining all of the necessary consents and approvals. See "Contingencies and commitments" for further discussion related to the Viking farm-out.

 
Q2 2013 MD&A | 3


Operating netback and funds from (used for) operations

 
(CDN$ thousands)
 
($ per boe)
 
Three months ended June 30
2013

2012

% change

2013

2012

% change

Petroleum and natural gas sales
6,867

6,314

9

40.59

29.45

38

Realized loss on financial instruments
—

(25
)
(100
)
—

(0.12
)
(100
)
Transportation
(165
)
(119
)
39

(0.98
)
(0.56
)
75

Royalties
(631
)
(683
)
(8
)
(3.72
)
(3.19
)
17

 
6,071

5,487

11

35.89

25.58

40

Operating expense
(3,033
)
(3,458
)
(12
)
(17.93
)
(16.13
)
11

Well workover expense
(122
)
(776
)
(84
)
(0.72
)
(3.62
)
(80
)
Operating netback(1)
2,916

1,253

133

17.24

5.83

196

General and administrative
(2,274
)
(2,499
)
(9
)
(13.44
)
(11.66
)
15

Foreign exchange loss
(27
)
7

486

(0.16
)
0.03

633

Interest and other income
33

42

(21
)
0.20

0.20

—

Interest expense
(55
)
(70
)
(21
)
(0.33
)
(0.33
)
—

Funds from (used for) operations(1)
593

(1,267
)
147

3.51

(5.93
)
159

Farm-in penalty (exploration expense)
—

(200
)
(100
)
—

(0.93
)
(100
)
Decommissioning expenditures
(98
)
(151
)
(35
)
(0.58
)
(0.70
)
(17
)
Changes in non-cash working capital
(391
)
456

(186
)
(2.31
)
2.13

(208
)
Cash provided by (used in) operating activities
104

(1,162
)
109

0.62

(5.43
)
111

(1)
Non-IFRS measure.

For the three months ended June 30, 2013, funds from operations was $0.6 million compared to funds used for operations of $1.3 million for the same period in 2012. This was primarily the result of a 9% increase in petroleum and natural gas revenue, a 12% decrease in operating expense and an 84% decrease in well workover expense.
 
(CDN$ thousands)
 
($ per boe)
 
Six months ended June 30
2013

2012

% change

2013

2012

% change

Petroleum and natural gas sales
14,116

14,743

(4
)
39.82

31.75

25

Realized loss on financial instruments
—

(92
)
(100
)
—

(0.20
)
(100
)
Transportation
(342
)
(315
)
9

(0.96
)
(0.68
)
41

Royalties
(1,096
)
(1,863
)
(41
)
(3.09
)
(4.01
)
(23
)
 
12,678

12,473

2

35.77

26.86

33

Operating expense
(6,659
)
(7,294
)
(9
)
(18.79
)
(15.71
)
20

Well workover expense
(714
)
(1,253
)
(43
)
(2.01
)
(2.70
)
(26
)
Operating netback(1)
5,305

3,926

35

14.97

8.45

77

General and administrative
(5,098
)
(5,335
)
(4
)
(14.38
)
(11.49
)
25

Foreign exchange loss
(70
)
(395
)
(82
)
(0.20
)
(0.85
)
(76
)
Interest and other income
56

72

22

0.16

0.16

—

Interest expense
(72
)
(167
)
(57
)
(0.20
)
(0.36
)
(44
)
Income taxes
—

(35
)
(100
)
—

(0.08
)
(100
)
Funds from (used for) operations(1)
121

(1,934
)
106

0.35

(4.17
)
108

Farm-in penalty (exploration expense)
—

(200
)
(100
)
—

(0.43
)
(100
)
Decommissioning expenditures
(98
)
(151
)
(35
)
(0.28
)
(0.33
)
(15
)
Changes in non-cash working capital
(390
)
1,550

(125
)
(1.10
)
3.34

(133
)
Cash used in operating activities
(367
)
(735
)
50

(1.03
)
(1.59
)
35

(1)
Non-IFRS measure.

For the six months ended June 30, 2013, funds from operations was $0.1 million compared to funds used for operations of $1.9 million for the same period in 2012. This was primarily the result of a 41% decrease in royalty expense, a 9% decrease in operating expense and a 43% decrease in well workover expense.


 
Q2 2013 MD&A | 4


Production

 
Q2

Q1

Q2

Six months ended
Commodity
2013

2013

2012

2013

2012

Natural gas (mcf/d)
7,423

7,934

9,665

7,677

10,609

Crude oil (bbls/d)
461

549

554

505

560

Natural gas liquids (bbls/d)
161

188

191

174

223

Total production (boe/d) (6:1)
1,858

2,059

2,356

1,959

2,551


 
Q2

Q1

Q2

Six months ended
Region
2013

2013

2012

2013

2012

Southern Alberta (boe/d)
1,578

1,738

1,956

1,658

2,043

Central Alberta (boe/d)
163

190

217

177

312

Other Western Canada (boe/d)
117

131

183

124

196

Total production (boe/d) (6:1)
1,858

2,059

2,356

1,959

2,551


For the three months ended June 30, 2013, production averaged 1,858 boe/d, compared to 2,059 boe/d for the three months ended March 31, 2013 and 2,356 boe/d for the three months ended June 30, 2012. The decrease in production during the three months ended June 30, 2013 compared to the three months ended March 31, 2013 and June 30, 2012 is due to natural decline, significant third-party natural gas processing plant outages in Central Alberta, weather related access issues and constrained capex due to the Western Canada strategic alternatives process.

Petroleum and natural gas sales

 
Q2

Q1

Q2

Six months ended
(CDN$ thousands, except where otherwise noted)
2013

2013

2012

2013

2012

Petroleum and natural gas sales
 

 

 

 
 
Natural gas
2,633

2,354

1,844

4,987

4,158

Crude oil
3,507

3,929

3,406

7,436

8,079

Natural gas liquids
727

966

1,064

1,693

2,506

Transportation
(165
)
(177
)
(119
)
(342
)
(315
)
Royalties
(631
)
(465
)
(683
)
(1,096
)
(1,863
)
Realized (loss) on commodity derivatives


—

(25
)


(92
)
Total
6,071

6,607

5,487

12,678

12,473

Average sales price (including commodity derivatives)
 

 

 

  



Natural gas ($/mcf)
3.90

3.30

2.10

3.59

2.15

Crude oil ($/bbl)
83.58

79.58

67.10

81.42

78.44

Natural gas liquids ($/bbl)
49.72

57.03

61.07

53.65

61.65

Average sales price ($/boe)
40.59

39.12

29.33

39.82

31.56

AECO 5a ($/mcf)
3.60

3.13

1.94

3.13

2.07

Edmonton Light ($/bbl)
92.47

87.71

83.00

87.71

87.86


For the three months ended June 30, 2013, petroleum and natural gas sales, net of transportation and royalties, was $6.1 million, compared to $6.6 million for the three months ended March 31, 2013 and $5.5 million for the three months ended June 30, 2012. The decrease in sales during the three months ended June 30, 2013 compared to the three months ended March 31, 2013 was due to lower production. The increase in sales during the three months ended June 30, 2013 compared to the three months ended June 30, 2012 is due to higher commodity prices, partially offset by lower production.

For the six months ended June 30, 2013, petroleum and natural gas sales, net of transportation and royalties, was $12.7 million, compared to $12.5 million for the six months ended June 30, 2012. The increase in sales during the six months ended June 30, 2013 compared to the six months ended June 30, 2012 is due to higher commodity prices, partially offset by lower production.


 
   Q2 2013 Financial Statements | 5


The Company realized an average sales price of $40.59 per boe during the three months ended June 30, 2013 compared to $39.12 per boe during the three months ended March 31, 2013 and $29.33 per boe during the three months ended June 30, 2012, exclusive of royalties and transportation, representing an increase of 3.8% and 28.3% respectively.

Royalties

 
Q2

Q1

Q2

Six months ended
(CDN$ thousands, except where otherwise noted)
2013

2013

2012

2013

2012

Royalties
 

 

 

 
 
Crown
425

251

435

676

1,357

Freehold and overriding
206

214

248

420

506

Total
631

465

683

1,096

1,863

Royalties per boe ($)
3.72

2.51

3.19

3.09

4.00

Average royalty rate (%)
9.4

6.6

11.1

8.0

13.0


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

Royalties on horizontal gas wells drilled in Alberta in 2012, 2013 and beyond generally bear royalties at a maximum of 5% for 18 months or until cumulative production reaches 50,000 boe. Horizontal oil wells generally bear royalties at a maximum of 5% for 18 to 48 months until cumulative production reaches 50,000 boe to 100,000 boe, depending on well depth.
 
For the three months ended June 30, 2013, natural gas and liquids royalties were $0.6 million, or 9.4% of total petroleum and natural gas sales, compared to $0.5 million or 7% of total petroleum and natural gas sales during the three months ended March 31, 2013 and $0.7 million or 11% of total petroleum and natural gas sales during the three months ended June 30, 2012. The increase in natural gas and liquids royalties during the three months ended June 30, 2013 compared to the three months ended March 31, 2013 is due to a decrease in the Gas Cost Allowance received by the Company. The decrease in natural gas and liquids royalties during the three months ended June 30, 2013 compared to the three months ended June 30, 2012 is attributable to an increase in the Gas Cost Allowance received by the Company.

For the six months ended June 30, 2013, natural gas and liquids royalties were $1.1 million, or 8% of total petroleum and natural gas sales, compared to $1.9 million or 13% of total petroleum and natural gas sales during the six months ended June 30, 2012. The decrease in natural gas and liquids royalties during the six months ended June 30, 2013 compared to the six months ended June 30, 2012 is attributable to an increase in the Gas Cost Allowance received by the Company.

Operating and well workover expense

Combined operating and well workover expenses during the three months ended June 30, 2013 were $3.2 million or $18.65 per boe, compared to $4.2 million or $22.76 per boe during the three months ended March 31, 2013 and $4.2 million or $19.75 per boe during the three months ended June 30, 2012.

Combined operating and well workover expenses during the six months ended June 30, 2013 were $7.4 million or $20.80 per boe, compared to $8.5 million or $18.41 per boe during the six months ended June 30, 2012.



 
Q2 2013 MD&A | 6


Capital expenditures

 
Q2

Q1

Q2

Six months ended
(CDN$ thousands)
2013

2013

2012

2013

2012

Exploration and evaluation
336

79

(851
)
415

3,934

Drilling and completions
(59
)
126

4,424

67

6,206

Plants, facilities and pipelines
162

519

797

681

2,847

Land and lease
294

236

1,392

530

2,146

Capital well workovers
(232
)
259

488

27

1,057

Capitalized general and administrative expenses
589

806

1,382

1,395

2,243

Capital expenditures
1,090

2,025

7,632

3,115

18,433

Western Canada dispositions
(5,837
)
(296
)
—

(6,133
)
(74,979
)
Exploration and evaluation impairment, charged to exploration expense
(246
)
(167
)
(239
)
(413
)
(1,125
)
Net capital expenditures
(4,993
)
1,562

7,393

(3,431
)
(57,671
)

 
Q2

Q1

Q2

Six months ended
(CDN$ thousands)
2013

2013

2012

2013

2012


Continuing operations
 

 

 

 
 
Canada
(5,729
)
847

7,452

(4,882
)
(63,373
)
North Africa
744

769

(16
)
1,513

5,417

Corporate Assets
(8
)
(54
)
(43
)
(62
)
285

Net capital expenditures
(4,993
)
1,562

7,393

(3,431
)
(57,671
)

Western Canada

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

During the three months ended March 31, 2013, the Company disposed of facilities with a net book value of $0.4 million for proceeds of $0.3 million, for a loss of $0.1 million (March 31, 2012 - nil).
During the three months ended June 30, 2013 the Company executed a letter to sell to an unrelated third party 45,671 net acres of undeveloped land primarily in the Montney play and 44,094 acres of undeveloped land in the Duvernay play in Central Alberta. This land was classified as exploration and evaluation assets at March 31, 2013 and had a carrying value of $2.6 million. In addition, the Company sold related property, plant and equipment associated with the Montney play with a net book value of $5.5 million. These assets were sold for total net proceeds of $5.8 million, resulting in a loss of $2.3 million. This sale closed on July 16, 2013.

The Company has exited the Montney play and divested certain licenses which contain Duvernay rights. Sonde retains undeveloped acreage in the Duvernay (54,648 acres net), Wabamun (50,736 acres net) and Detrital/Banff (46,677 acres net) plays. Of these lands, 85% have been purchased within the past 18 months, and as such, there are no land expiry issues. These land positions are typically large, consolidated and 100% working interest holdings with outstanding characteristics and growth potential.

2013 Western Canada Drilling Program

Sonde did not drill any wells during the three and six months ended June 30, 2013 due to the strategic alternatives process discussed previously. During the three months ended June 30, 2012, Sonde initiated a waterflood in the Drumheller Mannville “I” pool and completed the tie-in and equipping of its Michichi detrital 13-17 well. Sonde performed 13 and 27 net workovers and recompletions during the three and six months ended June 30, 2013 (six months ended June 30, 2012 - 43 net workovers and recompletions).





 
Q2 2013 MD&A | 7


Depletion, depreciation and impairment
 
For the three months ended June 30, 2013, depletion and depreciation was $2.2 million or $13.28 per boe compared to $2.5 million or $13.69 per boe during the three months ended March 31, 2013 and $2.6 million or $12.21 per boe during the three months ended June 30, 2012. The calculation of depletion and depreciation excluded $55.5 million (March 31, 2013 – $56.5 million, June 30, 2012 - $9.7 million) related to exploration and evaluation assets, primarily comprised of the Company’s North Africa asset. The decrease in depletion and depreciation during the three months ended June 30, 2013 compared to the three months ended March 31, 2013 and June 30, 2012 is due to a smaller depletion base resulting from production decline and impairments incurred during the twelve months ended December 31, 2012.

For the six months ended June 30, 2013, depletion and depreciation was $4.8 million or $13.49 per boe compared to $5.7 million or $12.30 per boe during the six months ended June 30, 2012. The decrease in depletion and depreciation during the six months ended June 30, 2013 compared to the six months ended June 30, 2012 is due to a smaller depletion base resulting from production decline and impairments incurred during the twelve months ended December 31, 2012.
 
An impairment test is performed on capitalized property plant and equipment costs at a cash-generating unit (“CGU”) level on an annual basis and quarterly when indicators of impairment exist. There were no indicators of impairment as at June 30, 2013. During the six months ended June 30, 2012, Sonde recorded an impairment of $16.2 million ($12.1 million in the Southern Alberta CGU, $2.4 million in the Central Alberta CGU, and $1.7 million in the Northern Alberta CGU) to reflect low natural gas prices. Impairments recognized during the six months ended June 30, 2012 were calculated using a 12% discount rate. Using a discount rate of 10% would have reduced the 2012 impairment by $11.2 million. Using a discount rate of 15% would have increased the 2012 impairment by $20.1 million.

General and administrative expenses

 
Q2

Q1

Q2

Six months ended
(CDN$ thousands, except where otherwise noted)
2013

2013

2012

2013

2012

Gross general and administrative expense
2,863

3,630

3,880

6,493

7,577

Capitalized general and administrative expense
(589
)
(806
)
(1,381
)
(1,395
)
(2,242
)
 
2,274

2,824

2,499

5,098

5,335

General and administrative expense ($/boe)
(13.44
)
(15.24
)
(11.66
)
(14.38
)
(11.49
)

For the three months ended June 30, 2013, gross general and administrative (“G&A”) expenses for continuing operations decreased to $2.9 million from $3.6 million during the three months ended March 31, 2013 and $3.9 million during the three months ended June 30, 2012. Gross G&A for the three months ended June 30, 2013 consists of $0.4 million (three months ended March 31, 2013 and June 30, 2012 – $0.7 million and $1.1 million) relating to North Africa and $2.5 million (three months ended March 31, 2013 and June 30, 2012 – $2.9 million and $2.8 million) related to Western Canada administration and corporate head office.

For the six months ended June 30, 2013, gross general and administrative (“G&A”) expenses for continuing operations decreased to $6.5 million from $7.6 million during the six months ended June 30, 2012. Gross G&A consists of $1.1 million (six months ended June 30, 2012 – $1.8 million) relating to North Africa and $5.4 million (six months ended June 30, 2012 – $5.8 million) related to Western Canada administration and corporate head office.

Share based compensation
 
Q2

Q1

Q2

Six months ended
(CDN$ thousands)
2013

2013

2012

2013

2012

Stock option expense
210

307

130

517

372

Stock unit award expense
(201
)
26

(141
)
(175
)
(18
)
Restricted share unit expense
(44
)
(23
)
(150
)
(67
)
(193
)
Share based compensation
(35
)
310

(161
)
275

161


Stock based compensation expense for the year six months ended June 30, 2013 was $0.3 million compared to $0.2 million for the six months ended June 30, 2012. The increase was due to higher stock option expense during the six months ended June 30, 2013.


 
Q2 2013 MD&A | 8


Liquidity and capital resources

(CDN$ thousands)
June 30
2013

December 31
2012

Cash and cash equivalents
16,136

19,695

Accounts receivable
10,491

4,683

Prepaid expenses and deposits
381

733

Accounts payable and accrued liabilities
(6,009
)
(6,850
)
Stock based compensation liability
(633
)
(1,074
)
Working capital surplus
20,366

17,187


At June 30, 2013, the Company had $16.1 in cash and cash equivalents (December 31, 2012 – $19.7 million). In 2012 cash flow was augmented by the February 8, 2012 sale of 24,383 net acres of undeveloped land in the Kaybob Duvernary play in Central Alberta for cash proceeds of $75 million, resulting in a gain of 73.4 million.

As described above, the Company disposed of assets for net proceeds of $5.8 million ($6.1 million gross) during the three months ended June 30, 2013. This amount was included in accounts receivable at June 30, 2013. The entire $5.8 million has been subsequently collected.

As at June 30, 2013, the Company had working capital of $20.4 million (December 31, 2012 – $17.2 million) and had issued four letters of credit for $0.3 million (December 31, 2012 – three letters of credit for $0.2 million) against the $25.0 million (December 31, 2012 - $30.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75% as at June 30, 2013 and at December 31, 2012.

Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company. Credit Facility A has covenants, as defined in the Company’s credit agreement, that require the Company to maintain an adjusted working capital ratio at 1:1 or greater and to ensure that non-domestic general and administrative and capital expenditures are funded from cash flow, equity and proceeds from foreign asset sales.

The Company can use Credit Facility A at its discretion and continues to pay standby fees on the undrawn facility. As at June 30, 2013 and December 31, 2012 the Company was in compliance with all of its debt covenants. The Company is subject to the next review of its credit facilities on or before August 1, 2013.

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

Substantial capital requirements

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

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

The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's financial condition, results of operations or prospects.

The Company's financial statements contain a "going concern" note based on developments involving the Company's inability to meet its three exploratory well obligation in respect of the Joint Oil Block, unitization, the proposal of a new unit plan of development which will allow for the re-injection of produced gases into the reservoir and drilling rig availability.


 
Q2 2013 MD&A | 9


Contingencies and commitments

(a)
North Africa EPSA

On August 27, 2008, the Company entered into an Exploration and Production Sharing Agreement (“EPSA”) with a Tunisian company, Joint Oil. Joint Oil is owned equally by the governments of Tunisia and Libya. The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, the Company is the operator. Under the EPSA, the minimum work program for the first phase (four years) of the seven year exploration period includes the Zarat North – 1 appraisal well, three exploration wells and 500 square kilometres of 3D seismic.

The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15.0 million per exploration well, and the Company has provided a corporate guarantee to a maximum of US$45.0 million to secure its minimum work program obligations. The potential cost of drilling the three wells could exceed US$100.0 million.
 
The Company recorded an impairment of $21.0 million to the Joint Oil Block during the year ended December 31, 2012, charged to exploration and evaluation expense. This was a result of the following information obtained during the second quarter of 2012:

•
Inert and Acid Gas Initiative – On June 12, 2012, DGE (Tunisian Direction Generale de L’Energie) announced an initiative for the Gulf of Gabes operators offshore Tunisia to study options for sequestration of carbon dioxide and other inert and acid gases (which comprise a high percentage of all known oil and gas accumulations in the Gulf of Gabes, including the Joint Oil Block) to allow the currently stranded high inert content gas to be developed commercially and brought to the Tunisian market. This initiative will ensure that the Zarat Development and other developments in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments with international organizations such as the Kyoto Accord on greenhouse gas emissions. This study is anticipated to take eighteen months. The Company is currently proposing a new unit plan of development which will allow for the re-injection of produced gases into the reservoir.
•
Drilling Rig Availability – The Company’s initial assessment indicated that the global demand for offshore drilling units was higher in other parts of the world than North Africa.
•
Unitization and Plan of Development – The Company filed a plan of development with Joint Oil for the development of the Zarat field. The Company expected Joint Oil to approve the plan of development expediently so that the Company could demonstrate to the market an asset with an approved exploitation plan. However, Joint Oil deferred approval of the Company’s Plan of Development pending negotiations with the other license holder and Entreprise Tunisienne d’Activities Petrolicres (ETAP) on Unitization and a unit plan of development for Zarat. The Company is currently proposing a new unit plan of development which will allow for the re-injection of produced gases into the reservoir. This will allow for a more cost effective development and the expedited receipt of liquids sales proceeds.
•
Exploratory Well Obligations – The Company planned to discuss with Joint Oil the timing of the three well exploratory commitment due to lack of availability of a suitable drilling rig. As discussed in "Contingencies and commitments", "(b) North Africa exploratory well extension and farm-out" below, on December 24, 2012 the Company received an extension on its exploratory well obligations until December 23, 2015.
(b)
North Africa exploratory well extension and farm-out

On December 24, 2012, Joint Oil approved the amendment to the EPSA allowing for the extension of the first phase of the exploration period under the EPSA to December 23, 2015. The extension provides for the drilling of three exploration wells, one each year, due December 23, 2013, 2014 and 2015. Penalties for non-fulfillment of the minimum work program are US$15.0 million for each well. In addition, the extension provides for the acquisition and processing of 200 square kilometers of 3D seismic in the Libyan sector of the Joint Oil Block, estimated to cost US$3.5 million, beginning in the third quarter of 2013.

On December 27, 2012, the Company entered into a farm-out agreement with Viking covering the Joint Oil Block. The farm-out agreement initially contained the following terms:
•
Viking would pay Sonde in total a US$3.0 million non-refundable signature bonus. As at December 31, 2012, US$1.0 million of the signature bonus had been received by the Company and credited against exploration and evaluation assets, with the remaining US$2.0 million due upon formal closing;
•
Viking would assume responsibility for the three well exploration commitment under the terms of the EPSA and fund 100% of the Joint Oil Block share of the Unit Plan of Development for the Zarat Field. The first well, Fisal, is to be drilled in 2013 along with the acquisition of 3D seismic data in Libyan waters;

 
Q2 2013 MD&A | 10


•
Viking would provide to Sonde, prior to closing, the appropriate form of corporate guarantee with the agreed upon commercial terms from one of their affiliated companies, in order to secure the remaining work commitment under the terms of the EPSA;
•
Sonde would receive 20% of the cost recovery and profit share revenue until Sonde recovers US$70 million. After payout of all Sonde and Viking expenditures, the revenue will be split 33.33% to Sonde and 66.67% to Viking;
•
Sonde retained the option to fund its 33.33% share of the last two of the exploration wells; and
•
Any future discoveries would be shared 33.33% to Sonde and 66.67% to Viking.
The initial farm-out agreement was subject to the following conditions:
•
Viking (or one of its affiliates) was to provide Sonde with a corporate guarantee sufficient to offset the current US$45.0 million guarantee for the potential penalties in respect of the three well drilling commitment and 3D seismic; and
•
Joint Oil would consent to the transfer of the interest to Viking as a second party to the EPSA and the naming of Viking as Operator of the Joint Oil Block under the EPSA.
On May 3, 2013, Sonde received approval from Joint Oil's Board of Directors to farm-out 66.67% of its potential Zarat Field Unit Area and 50% of the remainder of its interest in the Joint Oil Block to Viking. In order to receive Joint Oil approval, certain terms of the farm-out agreement as described above were required to be amended. The amendments to the initial farm-out agreement as discussed above are as follows:
•
Sonde will remain the operator of the Joint Oil Block;
•
Sonde and Viking will post a bank guarantee equivalent to US$50.995 million as a guarantee for the 2013 through 2015 work obligations the (“Bank Guarantee”). Viking will contribute US$40 million to the guarantee and Sonde will contribute US$10.995 million (the “Balance”) to the guarantee. Amounts under the Bank Guarantee will be released in accordance with a pre-determined formula as the work obligations are performed;
•
Viking will acquire a 66.67% participating interest and Sonde will retain a 33.33% participating interest in the Zarat Field Unit Area;
•
In consideration for contributing the Balance, Sonde will retain a 50% participating interest in the Joint Oil Block that is not covered by the exploitation area around the Zarat Field development. In addition, Sonde will recover US$11.0 million and 20% of the cost recovery and profit share revenue until Sonde recovers US$70.0 million. After payout of all Viking expenditures, the revenue will be split 33.33% to Sonde and 66.67% to Viking in the Zarat Field Unit Area;
•
Any future discoveries will be shared 50% to Sonde and 50% to Viking; and
•
The EPSA terms are the reference for and shall govern the Petroleum Operations under the EPSA as amended on January 17, 2013.
Joint Oil's approval of the assignment to Viking was subject to approval of the definitive form of Assignment Agreement and format of the Bank Guarantee (discussed above). Completion of the assignment required the execution of the definitive amendment to the farm-out agreement with Viking and closing of the farm-out.

The farm-out agreement was executed by Sonde and Viking on July 31, 2013. Formal closing remains conditioned upon obtaining all of the necessary consents and approvals.
(c)
Commitments and financial liabilities

At June 30, 2013, the Company has committed to future payments over the next five years and thereafter, as follows:
(CDN$ thousands)
2013

2014

2015

2016

2017

Thereafter

Total

Accounts payable and accrued liabilities
6,009

—

—

—

—

—

6,009

Stock based compensation liability
633

—

—

—

—

—

633

North Africa exploration commitments
19,458

15,777

15,777

—

—

—

51,012

Office rent payable
606

1,212

1,217

1,233

1,233

5,925

11,426

Office rent receivable
—

(404
)
(1,014
)
(1,233
)
(1,233
)
(5,925
)
(9,809
)
 
26,706

16,585

15,980

—

—

—

59,271


 
Q2 2013 MD&A | 11



The Company generally relies on a combination of cash flow from operating activities, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for domestic and international operations.
 
(d)
Litigation and claims

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

Income taxes
 
The Company’s current and future income taxes are dependent on factors such as production, commodity prices and tax classification of drilling costs related to exploration and development wells. At June 30, 2013, the Company has estimated $277.1 million in tax pools (December 31, 2012 - $281.3 million) including $150.7 million in non-capital losses (December 31, 2012 - $137.4 million) that are available for future deduction against taxable income. Non-capital losses expire in the years 2026 – 2033.
 
(CDN$ thousands)
June 30
2013

December 31
2012

Canadian exploration expense
56,845

56,802

Canadian oil and gas property expense
390

—

Canadian development expense
9,804

21,791

Undepreciated capital costs
22,276

29,041

Foreign exploration expense
5,187

4,354

Non-capital losses
150,739

137,414

Capital losses
31,274

30,094

Share issue costs and other
567

1,767

 
277,082

281,263


Share capital
 
As at August 1, 2013, the Company had 62,301,446 common shares and 4.62 million 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, 2013, and is based on the balances disclosed in this MD&A and the condensed consolidated financial statements for the three months ended June 30, 2013:

(CDN$ thousands)
Petroleum and Natural Gas Sales

Change in average sales price for natural gas by $1.00/mcf
1,390

Change in the average sales price for oil and gas liquids by $1.00/bbl
123

Change in natural gas production by 1 mmcf/d
355

Change in crude oil and natural gas liquids production by 100 bbls/d
1,213


Interest rate risk

The Company is exposed to interest rate risk as the credit facilities bear interest at floating market interest rates. The Company has no interest rate swaps or hedges to mitigate interest rate risk at June 30, 2013. The Company’s exposure to fluctuations in interest expense on its net loss and comprehensive income, assuming reasonably possible changes in the variable interest rate of +/- 1% is insignificant. This analysis assumes all other variables remain constant.


 
Q2 2013 MD&A | 12


Credit risk

As at June 30, 2013 the Company’s allowance for doubtful accounts is $1.7 million (December 31, 2012 – $1.7 million). This amount offsets $1.8 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2012 – $1.8 million). The Company considers all amounts greater than 90 days to be past due. As at June 30, 2013, $1.0 million of accounts receivable are past due, all of which are considered to be collectible (December 31, 2012 - $0.9 million). As described in above, the Company disposed of assets for net proceeds of $5.8 million ($6.1 million gross) during the six months ended June 30, 2013, all of which has been subsequently collected. The Company’s credit risk exposure is as follows:

(CDN$ thousands)
June 30
2013

December 31
2012

Western Canada joint interest billings
1,995

2,310

Revenue accruals and other receivables
8,496

2,373

Accounts receivable
10,491

4,683

Cash and cash equivalents
16,136

19,695

Maximum credit exposure
26,627

24,378


Commodity price risk

The Company enters into commodity sales agreements and certain derivative financial instruments to reduce its exposure to commodity price volatility. These financial instruments are entered into solely for risk mitigation purposes and are not used for trading or other speculative purposes. In 2011, the Company sold a call option on a portion of the Company’s oil production from March 2011 through December 2012. The Company did not hold any such instruments at June 30, 2013. The gains and losses associated with this instrument are as follows:

Six months ended



June 30, 2013
June 30, 2012
Term
Contract
Volume
Fixed Price
Realized
gain (loss)
Unrealized
gain (loss)
Realized (loss)
Unrealized gain
March 1, 2011 – December 31, 2012
Call
250(Bbls/d)
$100($US/bbl)
—
—
$(92)
$730

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:

(US$ thousands)
June 30
2013

December 31
2012

Cash and cash equivalents
1,567

2,184

North Africa receivables
—

1

Foreign denominated financial assets
1,567

2,185

 
 
 
North Africa payables
441

566

Foreign denominated financial liabilities
441

566

 

 
Q2 2013 MD&A | 13


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

Liquidity Risk

The Company generally relies on a combination of cash flow from operations, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for operations. At June 30, 2013, the Company has committed to future payments over the next five years, as follows:

(CDN$ thousands)
2013

2014

2015

2016

2017

Thereafter

Total

Accounts payable and accrued liabilities
6,009

—

—

—

—

—

6,009

Stock based compensation liability
633

—

—

—

—

—

633

North Africa exploration commitments
19,458

15,777

15,777

—

—

—

51,012

Office rent payable
606

1,212

1,217

1,233

1,233

5,925

11,426

Office rent receivable
—

(404
)
(1,014
)
(1,233
)
(1,233
)
(5,925
)
(9,809
)
 
26,706

16,585

15,980

—

—

—

59,271


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 President and Chief Operating Officer (“COO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding public disclosure.

In addition, during the period beginning April 1, 2013 and ending June 30, 2013, there were no changes to the Company’s internal controls that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

Off-balance sheet arrangements
 
The Company has no off-balance sheet arrangements.


 
Q2 2013 MD&A | 14


Quarterly financial summary

 
2013

2013

2012

2012

2012

2012

2011

2011

($ thousands except per share and production amounts)
Q2

Q1

Q4

Q3

Q2

Q1

Q4

Q3

Production
 

 

 

 

 

 

 

 

Natural gas (mcf/d)
7,423

7,934

8,940

8,757

9,665

11,553

12,186

12,673

Crude oil and natural gas liquids (bbl/d)
622

737

761

695

745

820

880

834

Total (boe/d)
1,858

2,059

2,251

2,155

2,356

2,746

2,911

2,946

 
















Petroleum & natural gas sales (2)
6,071

6,607

6,792

5,631

5,487

6,986

9,445

9,011

Net (loss) income from continuing operations
(4,857
)
(5,412
)
(3,870
)
(2,073
)
(28,030
)
55,456

(36,483
)
(847
)
Net (loss) income from continuing operations per share – basic and diluted
(0.08
)
(0.09
)
(0.06
)
(0.03
)
(0.45
)
0.89

(0.58
)
(0.01
)
Net (loss) income (1)
(4,857
)
(5,412
)
(3,870
)
(2,073
)
(28,030
)
55,456

(36,500
)
(591
)
Net (loss) income per share – basic and diluted(1)
(0.08
)
(0.09
)
(0.06
)
(0.03
)
(0.45
)
0.89

(0.58
)
(0.01
)
Funds from (used for) operations (3)
593

(472
)
123

494

(1,267
)
(667
)
3,155

1,945

Funds used for (from) operations per share – basic and diluted (3)
0.01

(0.01
)
0.01

0.01

(0.02
)
(0.01
)
0.05

0.03

(1)
This table includes both continuing operations and discontinued operations.
(2)
Petroleum and natural gas sales and realized gains on financial instruments net of royalties and transportation.
(3)
Non-IFRS measures.

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

•
Revenue is directly impacted by the Company’s ability to replace existing production and add incremental production through its on-going workover, recompletion and capital expenditure program.
•
Fluctuations in the Company’s petroleum and natural gas sales and net income (loss) from quarter to quarter are primarily caused by variations in production volumes, realized oil and natural gas prices and the related impact of royalties and impairments and subsequent reversals.
Please refer to the other sections of this MD&A for the detailed discussions on changes for the three months ending June 30, 2013.

Additional Information

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

 
Q2 2013 MD&A | 15


Document 3

 
 
 
 
 


For Immediate Release
August 1, 2013

SONDE RESOURCES CORP. ANNOUNCES SECOND QUARTER 2013 FINANCIAL AND OPERATING RESULTS

CALGARY, ALBERTA - (Marketwire – August 1, 2013) - Sonde Resources Corp. ("Sonde" or the "Company") (TSX: SOQ) (NYSE MKT: SOQ) announced today the release of its financial and operating results for the second quarter ended June 30, 2013. The Management's Discussion and Analysis and Financial Statements for the quarter ended June 30, 2013 can be viewed on the System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com, and on the Securities and Exchange Commission's Electronic Document Gathering and Retrieval System (EDGAR) at www.sec.gov. Shareholders have the ability to receive a hard copy of the Company's complete second quarter financial statements free of charge upon request.

Sonde will be hosting a conference call on Friday, August 2, 2013 at 1:30 p.m. MDT to provide a report on the second quarter 2013 results. Mr. Kurt Nelson, Chief Financial Officer, will host the call. All interested parties may join the call by dialing 416-340-8018 or 866-223-7781. Please dial-in 15 minutes prior to the call to secure a line. The conference call will be archived for replay on the Sonde website within 48 hours of this conference call.
 
North Africa

On December 27, 2012, the Company entered into a farm-out agreement with Viking Exploration and Production Tunisia Limited ("Viking") covering the Joint Oil Block. The farm-out agreement was executed by Sonde and Viking on July 31, 2013. Formal closing remains conditioned upon obtaining all of the necessary consents and approvals. The steps for consent and approval have already been discussed and the appropriate forms are being prepared which will assign the respective interests to Viking and Sonde. As the appropriate instruments are completed, Joint Oil will notify the parties and the parties will have twenty-one days to fund the US$50.995 bank guarantee. Expectations are that the formal closing will occur in mid to late September. Please see Sonde's July 31, 2013 news release for further information.

Toufic Nassif, President of Sonde North Africa, reiterated his earlier comments "The execution of the Viking farm-out is a milestone to the development of the Joint Oil Block and looks forward to working with Viking and Joint Oil to realize the full potential of the Block." Mr. Nassif further added, "Joint Oil has worked closely with Sonde on the process necessary to accept the Viking farm-out and such process is limited to the approval of the formal instruments. Joint Oil has assured Sonde that everything is in place to formalize the Viking farm-out once the bank guarantee is in place."

Mr. Kerry Brittain, Sonde's Chairman of the Board, stated "The execution of the Viking farm-out is a significant milestone to unlocking the unrealized potential of the North Africa assets for Joint Oil, Sonde and Viking. The farm-out shifts the three well exploratory obligation, or the US$45 million penalty, to Viking and takes Sonde one step closer to seeing the development of this significant resource. Perhaps of equal importance, the Viking farmout will provide management with the opportunity to focus on the Western Canada Strategic Alternatives process announced earlier. I and the Sonde Board want to personally thank Sonde's management and employees for their persistence and dedication in completing the Viking farm-out under difficult circumstances."


1


Western Canada

Western Canada Strategic Alternatives Process

On January 9, 2013, Sonde announced that it had initiated a process to explore and evaluate potential strategic alternatives to enhance shareholder value with regard to Sonde's Western Canadian production and exploratory acreage. A step in the strategic alternative process was the sale of Sonde's undeveloped Montney license (which included some Duvernay rights) which resulted in realizing approximately $65 per net acre with an average cost of approximately $23 per net acre. The loss Sonde recorded was related to the net book value of the recently drilled Montney well. By selling the non-producing well with the acreage the Company has exited this play. Current market conditions for cash transactions have remained soft but the cash sale was insurance in the event that the Viking farm-out was not executed.

Sonde retains undeveloped acreage in the Duvernay (54,648 acres net), Wabamun (50,736 acres net) and Detrital/Banff (46,677 acres net) plays. Of these lands, 85% have been purchased within the past 18 months, and as such, there are no land expiry issues. These land positions are typically large, consolidated and 100% working interest holdings with outstanding characteristics and growth potential.

2013 Western Canada Drilling Program

No wells were drilled during the three and six months ended June 30, 2013 due to the strategic alternatives process discussed above.

During the three and six months ended June 30, 2013, Sonde continued its well re-activation program. Sonde performed 13 and 27 net workovers and recompletions during the three and six months ended June 30, 2013.

Second Quarter Financial and Operational Review
 
Q2

Q1

%

Q2

%

(CDN$ thousands, except where otherwise noted)
2013

2013

Change

2012

Change

Financial
 
 
 
 
 
Petroleum & natural gas sales(1)
6,071

6,607

(8
)
5,487

11

Net loss
(4,857
)
(5,412
)
(10
)
(28,030
)
(83
)
Net loss per share – basic and diluted
(0.08
)
(0.09
)
(11
)
(0.45
)
(82
)
Funds from (used for) operations (2)
593

(472
)
226

(1,267
)
(147
)
Funds from (used for) operations per share(2)
0.01

(0.01
)
200

(0.02
)
110

Capital expenditures
1,090

2,025

(46
)
7,632

(86
)
Working capital surplus
20,366

15,063

35

34,865

(42
)
Average shares outstanding
62,301

62,301

—

62,301

—

Production
 
 
 
 
 
Natural gas (mcf/d)
7,423

7,934

(6
)
9,665

(23
)
Crude oil (bbl/d)
461

549

(16
)
554

(17
)
Natural gas liquids (bbl/d)
161

188

(14
)
191

(16
)
Total (boe/d)
1,858

2,059

(10
)
2,356

(21
)
Pricing
 
 
 
 
 
Natural gas ($/mcf)
3.90

3.30

18

2.10

86

Crude oil ($/bbl)
83.58

79.58

5

67.10

25

Natural gas liquids ($/bbl)
49.72

57.03

(13
)
61.07

(19
)
Average sales price ($/boe)
40.59

39.12

4

29.33

38

1)
Petroleum and natural gas sales and realized losses on financial instruments net of royalties and transportation.
2)
Non-IFRS measure reconciled in our MD&A filed on www.sedar.com

For the three months ended June 30, 2013, funds from operations was $0.6 million compared to funds used for operations of $1.3 million for the same period in 2012. This was primarily the result of a 9% increase in petroleum and natural gas revenue, a 12% decrease in operating expense and an 84% decrease in well workover expense.




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For the three months ended June 30, 2013, production averaged 1,858 boe/d, compared to 2,059 boe/d for the three months ended March 31, 2013 and 2,356 boe/d for the three months ended June 30, 2012. The decrease in production during the three months ended June 30, 2013 compared to the three months ended March 31, 2013 and June 30, 2012 is due to natural decline, significant third-party natural gas processing plant outages in Central Alberta, weather related access issues and constrained capex due to the Western Canada strategic alternatives process.

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

Non-IFRS Measures – This document contains references to funds from (used for) operations and funds from (used for) operations per share, which are not defined under IFRS as issued by the International Accounting Standards Board and are therefore non-IFRS financial measures that do not have any standardized meaning prescribed by IFRS and are, therefore, unlikely to be comparable to similar measures presented by other issuers.

Management of the Company believes funds from (used for) operations and funds from (used for) operations per share are relevant indicators of the Company’s financial performance, and ability to fund future capital expenditures.

Funds from (used for) operations should not be considered an alternative to or more meaningful than cash flow from operating activities, as determined in accordance with IFRS, as an indicator of the Company's performance. In our MD&A, a reconciliation has been prepared of funds from (used for) operations to cash (used in) provided by operating activities, the most comparable measure calculated in accordance with IFRS.

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

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

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

Actual results could differ materially due to a number of factors, including, without limitation, changes in market conditions, operational risks in development, exploration and production; commodity price volatility; the uncertainty of reserve estimates; risks and uncertainties involving geology of oil and gas deposits; the uncertainty of estimates and projections in relation to production; volatility in the capital markets and changes in the availability of capital generally; risks in conducting foreign operations, including political and fiscal instability and the possibility of civil unrest or military action; changes in government policies or laws; risk that government approvals may be delayed or withheld; and commercial risks related to the Joint Oil Block. Additional assumptions and risks relating to the Company and its business and affairs, including assumptions and risks relating to the estimation of reserves, are set out in detail in the Company’s AIF, available on SEDAR at www.sedar.com, and the Corporation's annual report on Form 40-F on file with the U.S. Securities and Exchange Commission.

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


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

For Further Information Please Contact:

Sonde Resources Corp.
Suite 3100, 500 - 4th Avenue S.W.
Calgary, Alberta, Canada T2P 2V6

Kurt A. Nelson, Chief Financial Officer
Phone: (403) 503-7944
Fax:      (403) 216-2374
www.sonderesources.com

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Document 4

 
 
 
 
 

FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
 
I, William Dirks, the President and Chief Operating Officer of Sonde Resources Corp., acting in the capacity of Chief Executive Officer, 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, 2013.
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, 2013 and ended on June 30, 2013 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.
Date: August 1, 2013
 

/s/ William Dirks      
William Dirks
President and Chief Operating Officer
Acting in the capacity of Chief Executive Officer
Sonde Resources Corp.



Document 5

 
 
 
 
 

FORM 52-109F2
CERTIFICATION OF INTERIM FILINGS
FULL CERTIFICATE
 
I, Kurt A. Nelson, the Chief Financial Officer of Sonde Resources Corp., certify the following:
 
1.
Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended June 30, 2013.
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, 2013 and ended on June 30, 2013 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.
Date: August 1, 2013


/s/ Kurt A, Nelson      
Kurt A. Nelson
Chief Financial Officer
Sonde Resources Corp.



SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
 
 
SONDE RESOURCES CORP.
 
 
 
 
(Registrant)
Date:
August 1, 2013
By:
/s/ Cheryl Clark
 
 
 
Name:
Title: 
Cheryl Clark
Corporate Controller/Assistant Corporate Secretary