Q3 2013 SOQ 6K (Word)


SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 6-K

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of
the Securities Exchange Act of 1934

For the month of
November
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 September 30, 2013
 
 
 
2.
 
Management Discussion and Analysis for the quarter ended September 30, 2013
 
 
 
3.
 
News Release, dated November 7, 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
September 30
2013

December 31
2012

(CDN$ thousands)
(Unaudited)
 
 
 
Assets
 
 
 
Current
 
 
 
Cash and cash equivalents
5
21,313

19,695

Accounts receivable
6
3,871

4,683

Prepaid expenses and deposits
 
537

733

 
 
25,721

25,111

Long term portion of prepaid expenses and deposits
 
731

732

Exploration and evaluation assets
3
54,626

56,499

Property, plant and equipment
3
90,356

104,144

 
 
171,434

186,486

 
 
 
 
Liabilities
 
 
 
Current
 
 
 
Accounts payable and accrued liabilities
 
5,508

6,850

Share based compensation liability
4
814

1,074

 
 
6,322

7,924

Decommissioning provision
 
28,880

29,972

 
 
35,202

37,896

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

369,892

Contributed surplus
 
34,975

34,290

Foreign currency translation reserve
 
1,591

(34
)
Deficit
 
(270,226
)
(255,558
)
 
 
136,232

148,590

Going concern
2(b)
 
 
Segments
13
 
 
Subsequent events
14
 
 
 
 
171,434

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

 
   Q3 2013 Financial Statements | 1


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

2012

2013

2012

(CDN$ thousands, except per share amounts)
(Unaudited)
 
 
 
 
 
Revenue
 
 
 
 
 
Revenue, net of royalties
9
6,718

5,776

19,738

18,656

Gain on commodity derivatives
6
—

21

—

659

 
 
6,718

5,797

19,738

19,315

Expenses
 
 
 
 
 
Operating
10
3,269

3,829

10,642

12,376

Transportation
 
235

145

577

460

Exploration and evaluation
3
741

196

3,694

22,508

General and administrative
 
2,172

1,301

7,270

6,636

Depletion and depreciation
3
2,492

2,604

7,275

8,316

Share based compensation
4
348

(553
)
623

(392
)
Property, plant and equipment impairment
3
871

—

871

16,241

Loss on settlement of decommissioning liabilities
 
868

—

646

84

 
 
10,996

7,522

31,598

66,229

Operating loss
 
(4,278
)
(1,725
)
(11,860
)
(46,914
)
 
 
 
 
 
 
Other
 
 
 
 
 
Financing costs
8
(208
)
(260
)
(633
)
(759
)
Loss on foreign exchange
 
(55
)
(162
)
(13
)
(446
)
Other income
 
32

74

88

146

(Loss) gain on disposition of assets
3
—

—

(2,360
)
73,361

 
 
(231
)
(348
)
(2,918
)
72,302

(Loss) income before taxes
 
(4,509
)
(2,073
)
(14,778
)
25,388

Current income taxes
 
(110
)
—

(110
)
35

Net (loss) income
 
(4,399
)
(2,073
)
(14,668
)
25,353

 
 
 
 
 
 
Other comprehensive (loss) income
 
 
 
 
 
Foreign currency translation adjustment
 
(957
)
(1,528
)
1,625

(1,110
)
Total comprehensive (loss) income
 
(5,356
)
(3,601
)
(13,043
)
24,243

 
 
 
 
 
 
Net (loss) income per common share
 
 
 
 
 
Basic and diluted (loss) income per common share
11
$
(0.07
)
$
(0.03
)
$
(0.24
)
$
0.41


See accompanying notes to the condensed consolidated financial statements

 
   Q3 2013 Financial Statements | 2


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

2012

2013

2012

(CDN$ thousands)
(Unaudited)
 
 
 
 
 
Cash provided by (used in) by:
 
 
 
 
 
Operating
 
 
 
 
 
Net (loss) income
 
(4,399
)
(2,073
)
(14,668
)
25,353

Items not involving cash:
 
 
 
 
 
Depletion and depreciation
3
2,492

2,604

7,275

8,316

Share based compensation
4
348

(553
)
623

(392
)
Exploration and evaluation
3
741

196

3,694

22,308

Property, plant and equipment impairment
3
871

—

871

16,241

Unrealized gain on commodity derivatives
6
—

(21
)
—

(751
)
Unrealized loss (gain) on foreign exchange
 
75

185

(37
)
74

Financing costs
8
208

260

633

759

Loss (gain) on disposition of assets
3
—

—

2,360

(73,361
)
Loss on settlement of decommissioning liabilities
 
868

—

646

84

Actual decommissioning expenditures
 
(1,186
)
—

(1,284
)
(151
)
Interest paid
 
(13
)
(104
)
(85
)
(271
)
Changes in non-cash working capital
12
561

2,461

171

4,011

 
 
566

2,955

199

2,220

Financing
 
 
 
 
 
Exercise of restricted share units
4
—

—

(32
)
(150
)
Exercise of stock unit awards
4
—

(653
)
(165
)
(795
)
Revolving credit facility repayments
 
—

—

—

(23,400
)
Revolving credit facility advances
 
—

—

—

23,400

 
 
—

(653
)
(197
)
(945
)
Investing
 
 
 
 
 
Property, plant and equipment additions
3
(185
)
(11,013
)
(1,257
)
(21,338
)
Exploration and evaluation additions
3
(794
)
(3,705
)
(2,837
)
(11,661
)
Proceeds on disposition of assets
3
5,837

—

6,133

74,979

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

—

—

Changes in non-cash working capital
12
5,665

(4,125
)
(460
)
(22,336
)
 
 
4,686

(18,843
)
1,579

19,644

Increase (decrease) in cash and cash equivalents
 
5,252

(16,541
)
1,581

20,919

Effect of foreign exchange on cash and cash equivalents
 
(75
)
(185
)
37

(74
)
Cash and cash equivalents, beginning of period
 
16,136

41,314

19,695

3,743

Cash and cash equivalents, end of period
5
21,313

24,588

21,313

24,588


See accompanying notes to the condensed consolidated financial statements

 
   Q3 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) income
—

—

(1,110
)
25,353

24,243

Stock option expense
—

507

—

—

507

At September 30, 2012
369,892

34,035

(560
)
(251,688
)
151,679

(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 income (loss)
—

—

1,625

(14,668
)
(13,043
)
Stock option expense
—

685

—

—

685

At September 30, 2013
369,892

34,975

1,591

(270,226
)
136,232

 
See accompanying notes to the condensed consolidated financial statements


 
   Q3 2013 Financial Statements | 4


NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
September 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 issued by the International Accounting Standards Board as at September 30, 2013 and December 31, 2012 and for the three and nine month periods ended September 30, 2013 and 2012.

The Financial Statements were approved and authorized for issue by the Board on November 7, 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 and nine months ended September 30, 2013, the Company had operating losses of $4.3 million and $11.9 million respectively. As at September 30, 2013, the Company had an accumulated deficit of $270.2 million. Management believes that the going concern assumption is appropriate for the Financial Statements; however, items discussed in Note 7 – “Contingencies and commitments”, 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.

 
   Q3 2013 Financial Statements | 5


3.
Exploration and evaluation assets and property, plant and equipment
 
Nine months ended
Year ended
 
September 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
2,837

—

2,837

13,696

—

13,696

Dispositions
(2,596
)
—

(2,596
)
(1,647
)
—

(1,647
)
Farm-out proceeds
—

—

—

(995
)
—

(995
)
Impairments, to exploration expense
—

(3,694
)
(3,694
)
—

(22,735
)
(22,735
)
Foreign exchange
1,580

—

1,580

(835
)
—

(835
)
End of period
81,055

(26,429
)
54,626

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
1,257

—

1,257

23,506

—

23,506

Dispositions
(5,897
)
—

(5,897
)
—

—

—

Change in decommissioning obligations
(1,002
)
—

(1,002
)
3,165

—

3,165

Depreciation and depletion
—

(7,275
)
(7,275
)
—

(11,031
)
(11,031
)
Impairments
—

(871
)
(871
)
—

(16,241
)
(16,241
)
End of period
233,482

(143,126
)
90,356

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 nine months ended September 30, 2013 the Company capitalized $0.9 million and $2.3 million respectively of general and administrative expenses related to exploration and evaluation activities (three and nine months ended September 30, 2012 – $1.2 million and $3.4 million respectively), of which $0.4 million and $0.7 million respectively related to Western Canada (three and nine months ended September 30, 2012 – $0.5 million and $1.0 million respectively).
  
In 2012 the Company completed the sale of 24,383 net acres of undeveloped land in the Kaybob Duvernay play in Central Alberta to an unrelated third party 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 nine months ended September 30, 2013 the Company sold 45,671 net acres of undeveloped land in the Montney play and 44,094 acres of undeveloped land in the Duvernay play in Central Alberta to an unrelated third party. This land was classified as exploration and evaluation assets, and had a net book 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 nine months ended September 30, 2013 totaled $0.2 million and $0.6 million (September 30, 2012 – $0.2 million and $1.3 million). As at September 30, 2013, no indicators of impairment were identified in Western Canada that would imply a further decline in Western Canada exploration and evaluation asset carrying values.

On November 4, 2013 the Company entered into an Arrangement Agreement with Marquee Energy Ltd. ("Marquee") whereby Marquee would acquire substantially all of the Western Canadian assets of Sonde, including all of its Southern Alberta properties (the "Transaction"). See note 14 - "Subsequent events (a)" for further discussion regarding the Transaction.

 


 
   Q3 2013 Financial Statements | 6


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

(b)
North Africa exploration and evaluation assets

During the three and nine months ended September 30, 2013, $0.5 million and $1.6 million respectively of general and administrative expenses related to North Africa were capitalized (three and nine months ended September 30, 2012 – $0.7 million and $2.4 million respectively).

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

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

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. Using the above described methodology and assumptions, the fair value of the North Africa assets was determined by the third party valuation firm to be $45.7 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). The farm-out agreement was executed by Sonde and Viking on July 31, 2013. Joint Oil’s Board of Directors and General Assembly approved the Assignments and the Amendment to the Exploration and Production Sharing Agreement on September 25, 2013, subject to confirmation of funding the previously disclosed bank guarantee. Closing the farm-out is subject to, among other conditions, that the previously disclosed US$50.995 million bank guarantee, of which Viking is responsible for US$40 million and Sonde is responsible for the remainder, must be fully funded prior to closing.

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.

 
   Q3 2013 Financial Statements | 7


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

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. As such, all costs capitalized in relation to North Africa from January 1, 2013 to September 30, 2013 have been booked to exploration and evaluation expense. These costs totaled $0.5 million and $3.0 million during the three and nine months ended September 30, 2013 (three and nine months ended September 30, 2012 – nil and $21 million).

(c)
Property, plant and equipment

During the nine months ended September 30, 2013, the Company disposed of property, plant and equipment, primarily in the Montney play of Central Alberta, with a net book value of $5.9 million, and the related exploration and evaluation assets with a net book value of $2.6 million, as discussed in note 3 (a) above, for total net proceeds of $6.1 million, resulting in a loss of $2.4 million.
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. During the nine months ended September 30, 2013, Sonde recorded an impairment of $0.9 million ($0.6 million in the Northern Alberta CGU and $0.3 in the BC CGU) to reflect low natural gas prices. During the nine months ended September 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 nine months ended September 30, 2013 were calculated using a 14% discount rate. Using a discount rate of 13% would have reduced the impairment by $0.1 million. Using a discount rate of 15% would have increased the impairment by $0.1 million. Impairments recognized during the nine months ended September 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.

On November 4, 2013 the Company entered into an Arrangement Agreement with Marquee whereby Marquee would acquire substantially all of the Western Canadian assets of Sonde, including all of its Southern Alberta properties. See note 14 - "Subsequent events (a)" for further discussion regarding the Transaction.

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. During the three and nine months ended September 30, 2013 the Company purchased approximately 121,253 and 305,898 shares with a value of $0.1 million and $0.3 million respectively on the open market under the ESSP (three and nine months ended September 30, 2012 – 87,506 and 211,104 shares with a value of $0.1 million and $0.4 million respectively). 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.
 
Nine months ended
 
Twelve months ended
 
 
September 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

Forfeited
(119
)
2.70

(750
)
3.03

Balance, end of period
4,609

$
2.40

4,728

$
2.40


 
   Q3 2013 Financial Statements | 8


4.
Share based compensation (continued)

During the nine months ended September 30, 2013 no stock options were granted by the Company (nine months ended September 30, 2012 – 0.8 million stock options granted at a weighted average exercise price of $2.34).

During the nine months ended September 30, 2013 0.1 million stock options with a weighted average exercise price of $2.70 were forfeited by employees due to their resignation or termination as employees of the Company (nine months ended September 30, 2012 – 0.5 million stock options with a weighted average exercise price of $3.20).
 
The following table summarizes stock options outstanding under the plan at September 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
2,302

3.72

1.31

814

1.24

2.51 – 3.00
538

2.66

2.86

419

2.86

3.01 – 4.00
995

6.89

3.10

990

3.09

4.01 – 11.80
774

7.19

4.40

717

4.41

0.75 – 11.80
4,609

4.86

2.40

2,940

2.87


No stock based compensation expense was capitalized during 2013 or 2012.

(c)
Stock unit awards

At September 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 September 30, 2013, the Company recorded a liability of $0.7 million to recognize the fair value of the vested stock units (December 31, 2012 - $0.9 million).

During the three and nine months ended September 30, 2013, the Company paid nil and $0.2 million respectively to settle awards held by current and former directors (three and nine months ended September 30, 2012 - nil and $0.8 million respectively).

(d)
Restricted share units

The Restricted Share Unit (“RSU”) 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 RSU, a cash amount equal to the fair market value of one common share in the capital of the Company on such vesting date, with the vesting subject to a minimum floor share price and/or the lapse of time. During the three and nine months ended September 30, 2013, nil and 33,334 RSUs were redeemed for a total of nil and $0.1 million (three and nine months ended September 30, 2012, nil and 66,666 RSUs were redeemed for a total of nil and $0.1 million respectively). The following table summarizes RSUs outstanding under the plan at September 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

0.26

3.00

101

3.00

3.01  – 3.50
3

0.28

3.27

2

3.27

3.51  – 3.64
9

0.28

3.64

6

3.64

0.00  – 3.64
207

0.26

3.03

109

3.04




 
   Q3 2013 Financial Statements | 9


4.
Share based compensation (continued)

The following table summarizes the share based compensation liability:
 
September 30
2013

December 31
2012

Stock unit award liability
737

909

Restricted share unit liability
77

165

Share based compensation liability
814

1,074


The following table summarizes share based compensation expense:

 
Three months ended
Nine months ended
 
September 30
2013

September 30
2012

September 30
2013

September 30
2012

Stock option expense
168

134

685

507

Stock unit award expense
169

(572
)
(6
)
(590
)
Restricted share unit gain
11

(115
)
(56
)
(309
)
 
348

(553
)
623

(392
)

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 September 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 September 30, 2013, cash and cash equivalents were comprised of $21.3 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 September 30, 2013. The gains and losses associated with this instrument are as follows:

Three months ended
 
 
 
September 30, 2013
September 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)
—
—
—
$21

Nine months ended



September 30, 2013
September 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)
$751

 
   Q3 2013 Financial Statements | 10


6.
Risk management (continued)
 
(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 September 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.

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:

 
September 30
2013

December 31
2012

Share capital
369,892

369,892

Contributed surplus
34,975

34,290

Foreign currency translation reserve
1,591

(34
)
Deficit
(270,226
)
(255,558
)
Total capital
136,232

148,590


(d)
Foreign exchange risk

The Company’s foreign exchange risk denominated in US dollars is as follows:

(US$ thousands)
September 30
2013

December 31
2012

Cash and cash equivalents
12,233

2,184

North Africa receivables
—

1

Foreign denominated financial assets
12,233

2,185

 
 
 
North Africa payables
425

566

Foreign denominated financial liabilities
425

566


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




 
   Q3 2013 Financial Statements | 11


6.
Risk management (continued)

(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. See note 14 - "Subsequent Events" for an update regarding the Company's future cash flow from operating activities.

(f) Credit risk

As at September 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 September 30, 2013, $0.7 million of accounts receivable are past due, all of which are considered to be collectible (December 31, 2012 - $0.9 million). The Company’s credit risk exposure is as follows:

(CDN$ thousands)
September 30
2013

December 31
2012

Western Canada joint interest billings
1,849

2,310

Revenue accruals and other receivables
2,022

2,373

Accounts receivable
3,871

4,683

Cash and cash equivalents
21,313

19,695

Maximum credit exposure
25,184

24,378


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, as amended in June 2013, the minimum remaining work program for Phase II of the seven year exploration period (2013-2015) consists of three exploration wells and 200 square kilometers of 3D seismic.  Sonde has previously fulfilled its Phase I (2008-2012) commitments to drill the Zarat North-1 appraisal well and shoot 500 square kilometers of seismic. See note 7 (b) for details regarding the revised minimum work program.

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. The 2012 impairment was a result of the information discussed in note 12 (a) of the Company's annual financial statements for the year ended December 31, 2012, which has been updated below:

•
Inert and Acid Gas Initiative – In June, 2012, the 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 first phase of the study has been completed and work on the second phase has commenced. 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 latest assessment of drilling rig availability for operations offshore Tunisia indicate that the global demand for offshore drilling units is still higher in other parts of the world than North Africa, making it very difficult to attract a suitable drilling rig for a short duration drilling program.

 
   Q3 2013 Financial Statements | 12


7.
Contingencies and commitments (continued)
•
Unitization and Plan of Development – The DGE requested that the parties involved in the Zarat development submit to the DGE, for review and approval, the final draft of the Unitization Agreement by the first week of October 2013 and the Unit Plan of Development no later than December 31, 2013. Working with Joint Oil and ETAP, the Company finalized the draft Unitization Agreement and submitted it to the DGE before the deadline. The Company has proposed a new plan of development for Zarat that 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. The new plan of development is being finalized for submittal to Joint Oil for review and approval. With the final draft of the Unitization Agreement being agreed upon by Joint Oil, the Company expects Joint Oil to approve the Unit Plan of Development.
•
Exploratory Well Obligations – 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 fourth quarter of 2013.

On December 27, 2012, the Company entered into an agreement with Viking providing for the farm-out of the Joint Oil Block. 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, subject to approval of the definitive form of Assignment Agreement and format of the Bank Guarantee (discussed below). The farm-out agreement contains the following terms:
•
Viking will pay Sonde a US$3.0 million non-refundable signature bonus. As at September 30, 2013, 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;
•
Sonde will remain the operator of the Joint Oil Block. Viking will fund 100% of the Joint Oil Block share of the Unit Plan of Development for the Zarat Field;
•
Viking will acquire a 66.67% participating interest and Sonde will retain a 33.33% participating interest in the Zarat Field Unit Area;
•
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;
•
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.
On July 31, 2013, the definitive form of the farm-out agreement was executed by Sonde and Viking.
On September 25, 2013, Joint Oil approved the assignment to Viking and the definitive form of Assignment Agreement. The Assignment Agreement is subject to a condition that the previously disclosed Bank Guarantee must be fully funded prior to closing. As per note 14 – "Subsequent events (b)", Sonde and Viking signed the Assignment Agreement in the form approved by Joint Oil on October 4, 2013, and on October 25, 2013, the deadline to fund the Bank Guarantee and to close the Assignment Agreement and the Viking farm-out was extended to November 15, 2013. As of September 30, 2013, the Bank Guarantee had not been funded and no assurance can be provided that such funding will occur or that the farm-out will close.


 
   Q3 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. See note 14 - "Subsequent Events" for an update regarding the Company's future cash flow from operating activities. At September 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
5,508

—

—

—

—

—

5,508

Share based compensation liability
814

—

—

—

—

—

814

North Africa exploration commitments (note 7 (a), (b))
19,061

15,455

15,455

—

—

—

49,971

Office rent payable
303

1,212

1,217

1,233

1,233

5,925

11,123

Office rent receivable
—

(404
)
(1,014
)
(1,233
)
(1,233
)
(5,925
)
(9,809
)
 
25,686

16,263

15,658

—

—

—

57,607


(d)
Litigation and claims

The Company is not involved in any claims or litigation arising in the ordinary course of business. 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 September 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 September 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 December 1, 2013.

Financing costs for the Company were as follows:
 
Three months ended
Nine months ended
 
September 30
2013

September 30
2012

September 30
2013

September 30
2012

Accretion of decommissioning provision
195

156

548

488

Interest on credit facilities
13

104

85

271

 
208

260

633

759


9.
Revenue

The following summarizes the Company’s revenue: 
 
Three months ended
Nine months ended
 
September 30
2013

September 30
2012

September 30
2013

September 30
2012

Petroleum and natural gas sales
7,278

6,436

21,394

21,179

Royalties
(560
)
(660
)
(1,656
)
(2,523
)
 
6,718

5,776

19,738

18,656

 

 
   Q3 2013 Financial Statements | 14


10.
Operating expense

Operating costs for the Company are as follows:
 
 
Three months ended
Nine months ended
 
September 30
2013

September 30
2012

September 30
2013

September 30
2012

Operating
3,188

3,212

9,847

10,506

Well workovers
81

617

795

1,870

 
3,269

3,829

10,642

12,376


11.
Share capital

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

For the three and nine months ended September 30, 2013 and September 30, 2012, the basic weighted average common shares outstanding was 62,301,446. For the three and nine months ended September 30, 2013, the diluted weighted average common shares outstanding was 62,304,755 and 62,671,535 respectively (three and nine months ended September 30, 2012 – 62,301,446 and 62,301,707). For the calculation of diluted earnings per share the Company excluded 4.6 million and 2.9 million options that are anti-dilutive for the three and nine months ended September 30, 2013 (September 30, 2012 – 3.3 million and 3.3 million).
 
12.
Supplemental cash flow information

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

September 30
2012

September 30
2013

September 30
2012

Accounts receivable
6,620

(314
)
812

3,092

Prepaid expenses and deposits
127

256

197

345

Accounts payable and accrued liabilities
(501
)
(1,607
)
(1,342
)
(9,281
)
Provisions
—

(4
)
—

(12,730
)
Foreign currency translation adjustment
(20
)
5

44

249

Change in non-cash working capital
6,226

(1,664
)
(289
)
(18,325
)

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

 
Three months ended
Nine months ended
 
September 30
2013

September 30
2012

September 30
2013

September 30
2012

Operating
561

2,461

171

4,011

Investing
5,665

(4,125
)
(460
)
(22,336
)
Change in non-cash working capital
6,226

(1,664
)
(289
)
(18,325
)


 
   Q3 2013 Financial Statements | 15


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.

On November 4, 2013 the Company entered into an Arrangement Agreement with Marquee whereby Marquee would acquire substantially all of the Western Canadian assets of Sonde, including all of its Southern Alberta properties. See note 14 - "Subsequent events (a)" for further discussion regarding the Transaction.

(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 September 30, 2013 and December 31, 2012 are as follows:

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

North
Africa

Total

Western
 Canada

North
Africa

Total

Assets
 
 
 
 
 
 
Current
 
 
 
 
 
 
Cash and cash equivalents
20,632

681

21,313

18,024

1,671

19,695

Accounts receivable
3,871

—

3,871

4,682

1

4,683

Prepaid expenses and deposits
499

38

537

714

19

733

 
25,002

719

25,721

23,420

1,691

25,111

Long term portion of prepaid expenses and deposits
731

—

731

732

—

732

Exploration and evaluation assets
9,379

45,247

54,626

11,799

44,700

56,499

Property, plant and equipment
90,356

—

90,356

104,144



104,144

Total assets
125,468

45,966

171,434

140,095

46,391

186,486

Liabilities
 
 
 
 
 
 
Current
 
 
 
 
 
 
Accounts payable and accrued liabilities
5,070

438

5,508

6,288

562

6,850

Share based compensation liability
814

—

814

1,074

—

1,074

 
5,884

438

6,322

7,362

562

7,924

Decommissioning provision
28,880

—

28,880

29,972

—

29,972

Total liabilities
34,764

438

35,202

37,334

562

37,896



 
   Q3 2013 Financial Statements | 16


13.
Segments and cash generating units (continued)

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

North
Africa

Total

Western
 Canada

North
Africa

Total

Revenue
 

 

 

 

 

 

Revenue, net of royalties
6,718

—

6,718

5,776

—

5,776

Gain on commodity derivatives
—

—

—

21

—

21

 
6,718

—

6,718

5,797

—

5,797

Expenses
 

 

 

 

 

 

Operating
3,269

—

3,269

3,829

—

3,829

Transportation
235

—

235

145

—

145

Exploration and evaluation
232

509

741

196

—

196

General and administrative
2,172

—

2,172

1,301

—

1,301

Depletion and depreciation
2,492

—

2,492

2,604

—

2,604

Share based compensation
348

—

348

(553
)
—

(553
)
Property, plant and equipment impairment
871

—

871

—

—

—

Loss on settlement of decommissioning liabilities
868

—

868

—

—

—

 
10,487

509

10,996

7,522

—

7,522

Operating loss
(3,769
)
(509
)
(4,278
)
(1,725
)
—

(1,725
)
Other
 

 

 

 

 

 

Financing costs
(208
)
—

(208
)
(260
)
—

(260
)
Loss on foreign exchange
(55
)
—

(55
)
(162
)
—

(162
)
Other income
32

—

32

74

—

74

 
(231
)
—

(231
)
(348
)
—

(348
)
(Loss) before income taxes
(4,000
)
(509
)
(4,509
)
(2,073
)
—

(2,073
)
Current income taxes
(110
)
—

(110
)
—

—

—

Net (loss) income
(3,890
)
(509
)
(4,399
)
(2,073
)
—

(2,073
)

The statements of operations for the nine months ended September 30, 2013 and September 30, 2012 by operating segment are as follows:
Nine months ended
September 30, 2013
September 30, 2012
 
Western
 Canada

North
Africa

Total

Western
 Canada

North
Africa

Total

Revenue
 
 
 
 
 
 
Revenue, net of royalties
19,738

—

19,738

18,656

—

18,656

Gain on commodity derivatives
—

—

—

659

—

659

 
19,738

—

19,738

19,315

—

19,315

Expenses
 
 
 
 
 
 
Operating
10,642

—

10,642

12,376

—

12,376

Transportation
577

—

577

460

—

460

Exploration and evaluation
645

3,049

3,694

1,521

20,987

22,508

General and administrative
7,270

—

7,270

6,636

—

6,636

Depletion and depreciation
7,275

—

7,275

8,316

—

8,316

Share based compensation
623

—

623

(392
)
—

(392
)
Property, plant and equipment impairment
871

—

871

16,241

—

16,241

Loss on settlement of decommissioning liabilities
646

—

646

84

—

84

 
28,549

3,049

31,598

45,242

20,987

66,229

Operating loss
(8,811
)
(3,049
)
(11,860
)
(25,927
)
(20,987
)
(46,914
)
Other
 
 
 
 
 
 
Financing costs
(633
)
—

(633
)
(759
)
—

(759
)
Loss on foreign exchange
(13
)
—

(13
)
(446
)
—

(446
)
Other income
88

—

88

146

—

146

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

(2,360
)
73,361

—

73,361

 
(2,918
)
—

(2,918
)
72,302

—

72,302

(Loss) income before income taxes
(11,729
)
(3,049
)
(14,778
)
46,375

(20,987
)
25,388

Current income taxes
(110
)
—

(110
)
35

—

35

Net (loss) income
(11,619
)
(3,049
)
(14,668
)
46,340

(20,987
)
25,353



 
   Q3 2013 Financial Statements | 17


14.
Subsequent events

(a) Arrangement Agreement with Marquee Energy Ltd.
On November 4, 2013 the Company entered into an Arrangement Agreement with Marquee whereby Marquee would acquire substantially all of the Western Canadian assets of Sonde, including all of its Southern Alberta properties. As consideration, Sonde will either receive:

•
0.72 of a Marquee common share (a “Marquee Share”) for each Sonde common share (a “Sonde Share”) outstanding, or in aggregate, 44,857,041 Marquee Shares; or
•
alternatively, Sonde has an option until November 20, 2013 to elect to receive 0.34 of a Marquee Share for each Sonde Share outstanding, or in aggregate 21,182,492 Marquee Shares, in addition to Sonde receiving $15 million in cash (the “Cash Election”).

Sonde will distribute all Marquee Shares received to its shareholders, and retain the cash received if so elected.

The Transaction is subject to the certain regulatory and stock exchange approvals, the approval from 2/3 of the Sonde shareholders and satisfaction of certain other closing conditions that are customary for a transaction of this nature. Assuming approval of the Transaction by Sonde shareholders, closing is expected to occur in late December, 2013.

Management estimates that the Transaction may result in a potential loss on the disposition of assets, net of liabilities relinquished ("the loss"), of between approximately $20 million and $34 million, depending on whether Sonde executes the Cash Election. The loss is expected to be recorded during the three months ended December 31, 2013. The approximate range of the loss was calculated using Marquee's closing share price as at November 4, 2013 of $0.77, plus or minus 20%. Actual results may materially differ from these estimates due to the choice in the Cash Election as well as potential changes in Marquee’s share price between the announcement date and the closing date.

(b) North Africa exploration and evaluation assets

Sonde and Viking signed the Assignment Agreement in the form approved by Joint Oil on October 4, 2013, and on October 25, 2013, the deadline to fund the Bank Guarantee and to close the Assignment Agreement and the Viking farm-out was extended to November 15, 2013.
  


    


 
   Q3 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 November 7, 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”) as issued by the International Accounting Standards Board. This MD&A should be read in conjunction with the unaudited condensed consolidated financial statements for the period ended September 30, 2013 and 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 potential impact, including a potential loss on the disposition of assets, net of liabilities relinquished, of the Arrangement Agreement with Marquee Energy Ltd. ("Marquee") whereby Marquee would acquire substantially all of the Western Canadian assets of Sonde, including all of its Southern Alberta properties ("the Assets"), ("the Transaction");
•
the transfer of the Assets and related tax pools to a newly formed subsidiary of Sonde and the amalgamation thereof with a subsidiary of or direct acquisition by Marquee pursuant to a plan of arrangement (the "Plan of Arrangement");
•
the election for Sonde to receive 0.72 of a Marquee common share (a “Marquee Share”) for each Sonde common share (a “Sonde Share”) currently issued and outstanding, or in aggregate, 44,857,041 Marquee Shares, or until November 20, 2013 to elect to receive 0.34 of a Marquee Share for each Sonde Share currently issued and outstanding, or in aggregate 21,182,492 Marquee Shares, in addition to Sonde receiving $15 million in cash;
•
the expected distribution of all Marquee Shares received as a result of the Transaction to Sonde's shareholders, and Sonde's expected retention of any cash received, if so elected;
•
the expectation that a Sonde shareholder meeting will be held in late December, 2013 following the mailing of an information circular regarding the Transaction in early December, 2013;
•
the expectation that the Transaction will close shortly after receiving approval of the Transaction by Sonde shareholders;
•
the impact of the potential 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 requirements and the Viking farm-out bank guarantee equivalent to US$50.995 million as a guarantee for the 2013 through 2015 work obligations the (“Bank Guarantee”);
•
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;
•
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.

 
Q3 2013 MD&A | 1


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

•
the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas, market demand and unpredictable facilities outages;
•
risks and uncertainties involving geology of oil and gas deposits;
•
uncertainty related to production, marketing and transportation;
•
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 and the ability of Viking and Sonde to fund the Bank Guarantee;
•
the negotiation of the proposed unitization of the Zarat field;
•
the ability of the Company to satisfy all conditions required for the completion of the proposed arrangement with Marquee;
•
risks associated with the potential volatility and price of Marquee Shares prior to and upon closing of the Transaction;
•
risks associated with the severance of employees as a result of the Transaction; 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 and in the Company's press release dated November 5, 2013. 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”). 

 
Q3 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.

(a)
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 assisted in the process of analyzing and evaluating prospects and options available to the Company. As of November 7, 2013, the following transactions and potential transactions were undertaken by the Company.

During the nine months ended September 30, 2013 the Company sold 45,671 net acres of undeveloped land in the Montney play and 44,094 acres of undeveloped land in the Duvernay play, both in Central Alberta, to an unrelated third party. This land was classified as exploration and evaluation assets and had a net book 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 $5.9 million, to the same unrelated third party. These assets were sold for total proceeds of $6.1 million, resulting in a loss of $2.4 million.

The Company has exited the Montney play and divested certain licenses which contain Duvernay rights. Sonde retains undeveloped acreage in the Duvernay (44,341 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.

On November 4, 2013 the Company entered into an Arrangement Agreement with Marquee whereby Marquee would acquire substantially all of the Western Canadian assets of Sonde, including all of its Southern Alberta properties. See "Capital expenditures and dispositions, (b) Arrangement Agreement with Marquee Energy Ltd." for further discussion regarding the Transaction.
  
The previously disclosed Special Committee established to oversee the strategic alternatives process determined, with respect to the Marquee transaction, that the Board as a whole would be responsible for evaluating the transaction and the Special Committee would be engaged only if a potential conflict of interest or another potential transaction were to arise.

(b)
2013 Western Canada drilling program

No wells were drilled during the three and nine months ended September 30, 2013 due to the strategic alternatives process discussed above. During the three and nine months ended September 30, 2013, Sonde continued its well re-activation program. Sonde performed 21 and 35 net workovers and recompletions during the three and nine months ended September 30, 2013.

North Africa

On July 31, 2013, the definitive form of the farm-out agreement was executed by Sonde and Viking.
On September 25, 2013, Joint Oil approved the assignment to Viking and the definitive form of Assignment Agreement. The Assignment Agreement is subject to a condition that the previously disclosed Bank Guarantee, of which Viking will contribute US$40 million and Sonde will contribute US$10.995 million, must be fully funded prior to closing. Sonde and Viking signed the Assignment Agreement in the form approved by Joint Oil on October 4, 2013, and on October 25, 2013, the deadline to fund the Bank Guarantee and to close the Assignment Agreement and the Viking farm-out was extended to November 15, 2013. As of September 30, 2013, the Bank Guarantee had not been funded and no assurance can be provided that such funding will occur or that the farm-out will close.



 
Q3 2013 MD&A | 3


Operating netback and funds from (used for) operations

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

2012

% change

2013

2012

% change

Petroleum and natural gas sales
7,278

6,436

13

39.00

32.46

20

Transportation
(235
)
(145
)
62

(1.26
)
(0.73
)
73

Royalties
(560
)
(660
)
(15
)
(2.99
)
(3.33
)
(10
)
 
6,483

5,631

15

34.75

28.40

22

Operating expense
(3,188
)
(3,212
)
(1
)
(17.08
)
(16.20
)
5

Well workover expense
(81
)
(617
)
(87
)
(0.43
)
(3.11
)
(86
)
Operating netback(1)
3,214

1,802

78

17.24

9.09

90

General and administrative
(2,172
)
(1,301
)
67

(11.64
)
(6.56
)
77

Foreign exchange loss
20

23

(13
)
0.11

0.12

(8
)
Interest and other income
32

74

(57
)
0.17

0.37

(54
)
Interest expense
(13
)
(104
)
(88
)
(0.07
)
(0.52
)
(87
)
Income taxes
110

—

100

0.59

—

100

Funds from operations(1)
1,191

494

141

6.40

2.50

156

Decommissioning expenditures
(1,186
)
—

100

(6.36
)
—

100

Changes in non-cash working capital
561

2,461

(77
)
3.01

12.41

(76
)
Cash provided by operating activities
566

2,955

(81
)
3.05

14.91

(80
)
(1)
Non-IFRS measure.

For the three months ended September 30, 2013, funds from operations was $1.2 million compared to funds from operations of $0.5 million for the same period in 2012. This was primarily the result of a 13% increase in petroleum and natural gas revenue and an 87% decrease in well workover expense, partially offset by a 67% increase in general and administrative expense.
 
(CDN$ thousands)
 
($ per boe)
 
Nine months ended September 30
2013

2012

% change

2013

2012

% change

Petroleum and natural gas sales
21,394

21,179

1

39.54

31.97

24

Realized loss on financial instruments
—

(92
)
(100
)
—

(0.14
)
(100
)
Transportation
(577
)
(460
)
25

(1.07
)
(0.69
)
55

Royalties
(1,656
)
(2,523
)
(34
)
(3.06
)
(3.81
)
(20
)
 
19,161

18,104

6

35.41

27.33

30

Operating expense
(9,847
)
(10,506
)
(6
)
(18.20
)
(15.86
)
15

Well workover expense
(795
)
(1,870
)
(57
)
(1.47
)
(2.82
)
(48
)
Operating netback(1)
8,519

5,728

49

15.74

8.65

82

General and administrative
(7,270
)
(6,636
)
10

(13.44
)
(10.02
)
34

Foreign exchange loss
(50
)
(372
)
(87
)
(0.09
)
(0.56
)
(84
)
Interest and other income
88

146

(40
)
0.16

0.22

(27
)
Interest expense
(85
)
(271
)
(69
)
(0.16
)
(0.41
)
(61
)
Income taxes
110

(35
)
(414
)
0.20

(0.05
)
(500
)
Funds from (used for) operations(1)
1,312

(1,440
)
191

2.41

(2.17
)
211

Farm-in penalty (exploration expense)
—

(200
)
(100
)
—

(0.30
)
(100
)
Decommissioning expenditures
(1,284
)
(151
)
750

(2.37
)
(0.23
)
930

Changes in non-cash working capital
171

4,011

(96
)
0.32

6.05

(95
)
Cash provided by operating activities
199

2,220

(91
)
0.36

3.35

(89
)
(1)
Non-IFRS measure.

For the nine months ended September 30, 2013, funds from operations was $1.3 million compared to funds used for operations of $1.4 million for the same period in 2012. This was primarily the result of a 34% decrease in royalty expense, a 6% decrease in operating expense and a 57% decrease in well workover expense. These changes were partially offset by a 10% increase in general and administrative expense.

 
Q3 2013 MD&A | 4


Production

 
Q3

Q2

Q3

Nine months ended
September 30
Commodity
2013

2013

2012

2013

2012

Natural gas (mcf/d)
8,244

7,423

8,757

7,868

9,989

Crude oil (bbls/d)
494

461

523

501

547

Natural gas liquids (bbls/d)
160

161

172

170

206

Total production (boe/d) (6:1)
2,028

1,858

2,155

1,982

2,418


 
Q3

Q2

Q3

Nine months ended
September 30
Region
2013

2013

2012

2013

2012

Southern Alberta (boe/d)
1,747

1,578

1,813

1,688

1,968

Central Alberta (boe/d)
177

163

194

177

277

Other Western Canada (boe/d)
104

117

148

117

173

Total production (boe/d) (6:1)
2,028

1,858

2,155

1,982

2,418


For the three and nine months ended September 30, 2013, production was weighted 32% and 34% respectively to crude oil and natural gas liquids, compared to 33% during the three months ended June 30, 2013 and 32% and 31% respectively during the three and nine months ended September 30, 2012.

For the three months ended September 30, 2013, production averaged 2,028 boe/d, compared to 1,858 boe/d for the three months ended June 30, 2013 and 2,155 boe/d for the three months ended September 30, 2012. The increase in production during the three months ended September 30, 2013 compared to the three months ended June 30, 2013 is due to the resolution of prior quarter third-party natural gas processing plant outages and weather related access issues. The decrease in production compared to the three months ended September 30, 2012 is due to natural decline and constrained capital expenditures due to the Western Canada strategic alternatives process.

Petroleum and natural gas sales

 
Q3

Q2

Q3

Nine months ended
September 30
(CDN$ thousands, except where otherwise noted)
2013

2013

2012

2013

2012

Petroleum and natural gas sales
 

 

 

 
 
Natural gas
1,914

2,633

1,901

6,901

6,059

Crude oil
4,443

3,507

3,708

11,879

11,787

Natural gas liquids
921

727

827

2,614

3,333

Transportation
(235
)
(165
)
(145
)
(577
)
(460
)
Royalties
(560
)
(631
)
(660
)
(1,656
)
(2,523
)
Realized (loss) on commodity derivatives
—

—

—

—

(92
)
Total
6,483

6,071

5,631

19,161

18,104

Average sales price (including commodity derivatives)
 

 

 

  



Natural gas ($/mcf)
2.52

3.90

2.36

3.21

2.21

Crude oil ($/bbl)
97.77

83.58

77.09

86.85

78.00

Natural gas liquids ($/bbl)
62.43

49.72

52.24

56.44

59.01

Average sales price ($/boe)
39.00

40.59

32.46

39.54

31.83

AECO 5a ($/mcf)
2.88

3.60

2.34

2.98

2.07

Edmonton Light ($/bbl)
100.52

92.47

86.08

95.90

87.73



 
Q3 2013 MD&A | 5


For the three months ended September 30, 2013, petroleum and natural gas sales, net of transportation and royalties, was $6.5 million, compared to $6.1 million for the three months ended June 30, 2013 and $5.6 million for the three months ended September 30, 2012. The increase in sales during the three months ended September 30, 2013 compared to the three months ended June 30, 2013 was due to increased production. The increase in sales during the three months ended September 30, 2013 compared to the three months ended September 30, 2012 is due to higher commodity prices, partially offset by lower production.

For the nine months ended September 30, 2013, petroleum and natural gas sales, net of transportation and royalties, was $19.2 million, compared to $18.1 million for the nine months ended September 30, 2012. The increase in sales is due to higher commodity prices, partially offset by lower production.

The Company realized an average sales price of $39.00 per boe during the three months ended September 30, 2013 compared to $40.59 per boe during the three months ended June 30, 2013 and $32.46 per boe during the three months ended September 30, 2012, exclusive of royalties and transportation, representing a decrease of 3.9%, due to lower gas prices, and an increase of 20.2% due to higher oil prices, respectively.

Royalties
 
Q3

Q2

Q3

Nine months ended
September 30
(CDN$ thousands, except where otherwise noted)
2013

2013

2012

2013

2012

Royalties
 

 

 

 
 
Crown
347

425

485

1,023

1,842

Freehold and overriding
213

206

175

633

681

Total
560

631

660

1,656

2,523

Royalties per boe ($)
2.99

3.72

3.33

3.06

3.81

Average royalty rate (%)
8.0

9.4

10.5

8.0

12.2


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 September 30, 2013, natural gas and liquids royalties were $0.6 million, or 8.0% of total petroleum and natural gas sales, compared to $0.6 million or 9% of total petroleum and natural gas sales during the three months ended June 30, 2013 and $0.7 million or 10.5% of total petroleum and natural gas sales during the three months ended September 30, 2012. The decrease in natural gas and liquids royalties during the three months ended September 30, 2013 compared to the three months ended June 30, 2013 and September 30, 2012 is due to an increase in the Gas Cost Allowance received by the Company.

For the nine months ended September 30, 2013, natural gas and liquids royalties were $1.7 million, or 8% of total petroleum and natural gas sales, compared to $2.5 million or 12% of total petroleum and natural gas sales during the nine months ended September 30, 2012. The decrease in natural gas and liquids royalties during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 is attributable to a decrease in the Company's production, primarily in the Eaglesham and Puskwa fields located in the Northern CGU, where the royalty rate is higher than in the Southern CGU.

Operating and well workover expense

Combined operating and well workover expenses during the three months ended September 30, 2013 were $3.3 million or $17.51 per boe, compared to $3.2 million or $18.65 per boe during the three months ended June 30, 2013 and $3.8 million or $19.31 per boe during the three months ended September 30, 2012. Combined operating and well workover expenses during the nine months ended September 30, 2013 were $10.6 million or $19.67 per boe, compared to $12.4 million or $18.68 per boe during the nine months ended September 30, 2012. The decrease in operating and well workover expenses was due to decreased production and fewer workovers being performed.

 
Q3 2013 MD&A | 6


Capital expenditures and dispositions

 
Q3

Q2

Q3

Nine months ended
September 30
(CDN$ thousands)
2013

2013

2012

2013

2012

Exploration and evaluation
25

336

555

440

4,489

Drilling and completions
464

(59
)
9,179

531

15,385

Plants, facilities and pipelines
582

162

802

1,263

3,649

Land and lease
260

294

2,903

790

5,049

Capital well workovers
68

(232
)
109

95

1,166

Capitalized general and administrative expenses
864

589

1,168

2,259

3,411

Capital expenditures
2,263

1,090

14,716

5,378

33,149

Western Canada dispositions
—

(5,837
)
—

(6,133
)
(74,979
)
Exploration and evaluation impairment, charged to exploration expense
(232
)
(246
)
(196
)
(645
)
(1,321
)
Net capital expenditures
2,031

(4,993
)
14,520

(1,400
)
(43,151
)

 
Q3

Q2

Q3

Nine months ended
September 30
(CDN$ thousands)
2013

2013

2012

2013

2012

Continuing operations
 

 

 

 
 
Canada
1,521

(5,729
)
13,306

(3,361
)
(50,068
)
North Africa
503

744

1,196

2,016

6,612

Corporate Assets
7

(8
)
18

(55
)
305

Net capital expenditures
2,031

(4,993
)
14,520

(1,400
)
(43,151
)

Western Canada

In 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 nine months ended September 30, 2013 the Company sold 45,671 net acres of undeveloped land in the Montney play and 44,094 acres of undeveloped land in the Duvernay play, both in Central Alberta, to an unrelated third party. This land was classified as exploration and evaluation assets and had a net book 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 $5.9 million, to the same unrelated third party. These assets were sold for total proceeds of $6.1 million, resulting in a loss of $2.4 million.

The Company has exited the Montney play and divested certain licenses which contain Duvernay rights. Sonde retains undeveloped acreage in the Duvernay (44,341 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.

(a) 2013 Western Canada Drilling Program

Sonde did not drill any wells during the three and nine months ended September 30, 2013 due to the strategic alternatives process discussed previously. Sonde performed 21 and 35 net workovers and recompletions during the three and nine months ended September 30, 2013 (three and nine months ended September 30, 2012 - nil and 43 net workovers and recompletions).


 
Q3 2013 MD&A | 7


(b) Arrangement Agreement with Marquee Energy Ltd.
On November 4, 2013 the Company entered into an Arrangement Agreement with Marquee whereby Marquee would acquire substantially all of the Western Canadian assets of Sonde, including all of its Southern Alberta properties. As consideration, Sonde will either receive:

•
0.72 of a Marquee Share for each Sonde Share outstanding, or in aggregate, 44,857,041 Marquee Shares; or
•
alternatively, Sonde has an option until November 20, 2013 to elect to receive 0.34 of a Marquee Share for each Sonde Share outstanding, or in aggregate 21,182,492 Marquee Shares, in addition to Sonde receiving $15 million in cash (the “Cash Election”).

Sonde will transfer the Assets and related tax pools to a newly formed subsidiary of Sonde, which will either amalgamate with a wholly-owned subsidiary of Marquee or be directly acquired by Marquee pursuant to the Plan of Arrangement. Sonde will distribute all Marquee Shares received to its shareholders, and retain the cash received if so elected.

The Transaction is subject to the approval of the Alberta Court of Queen's Bench under the Business Corporations Act (Alberta), the receipt of all necessary regulatory and stock exchange approvals, the requisite approval from 2/3 of the Sonde shareholders, and satisfaction of certain other closing conditions that are customary for a transaction of this nature. It is anticipated that a Sonde shareholder meeting will be held in late December, 2013 following the mailing of an information circular regarding the Transaction in early December, 2013. Assuming approval of the Transaction by Sonde shareholders, closing is expected to occur shortly thereafter.

The Board of Directors of Sonde unanimously supports the Transaction, has unanimously determined that the Transaction is fair to Sonde shareholders and in the best interest of Sonde and has agreed to unanimously recommend that the shareholders of Sonde vote in favor of the Transaction. Certain Sonde shareholders, including all officers and directors, who collectively hold over 12% of the issued and outstanding Sonde Shares, have entered into agreements with Marquee pursuant to which they have agreed to vote their shares in favour of the Transaction at the Sonde shareholder meeting.

Sonde will retain its current cash and working capital balances of approximately $19.4 million as at September 30, 2013, in addition to cash received in the Transaction should Sonde make the Cash Election. In addition, Sonde will retain ownership of approximately 100,000 net acres of Western Canada exploration assets, split approximately equally between its Eaglesham area Wabamun play and west central Alberta Duvernay play. Sonde will continue to seek strategic alternatives for the Western Canada exploration acreage, which could include cash sales, farm-outs, other forms of merger, or other options.
Management estimates that the Transaction may result in a potential loss on the disposition of assets, net of liabilities relinquished ("the loss"), of between approximately $20 million and $34 million, depending on whether Sonde executes the Cash Election. The loss is expected to be recorded during the three months ended December 31, 2013. The approximate range of the loss was calculated using Marquee's closing share price as at November 4, 2013 of $0.77, plus or minus 20%. Actual results may materially differ from these estimates due to the choice in the Cash Election as well as potential changes in Marquee’s share price between the announcement date and the closing date.

Depletion, depreciation and impairment
 
For the three months ended September 30, 2013, depletion and depreciation was $2.5 million or $13.35 per boe compared to $2.2 million or $13.28 per boe during the three months ended June 30, 2013 and $2.6 million or $13.13 per boe during the three months ended September 30, 2012. The calculation of depletion and depreciation excluded $54.6 million (June 30, 2013 – $56.5 million, September 30, 2012 - $55.4 million) related to exploration and evaluation assets, primarily comprised of the Company’s North Africa asset. The increase in depletion and depreciation during the three months ended September 30, 2013 compared to the three months ended June 30, 2013 is due to increased production. The decrease in depletion and depreciation during the three months ended September 30, 2013 compared to the three months ended September 30, 2012 is due to a smaller depletion base resulting from production decline.

For the nine months ended September 30, 2013, depletion and depreciation was $7.3 million or $13.45 per boe compared to $8.3 million or $12.55 per boe during the nine months ended September 30, 2012. The decrease in depletion and depreciation during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 is due to a smaller depletion base resulting from production decline and impairments incurred during the twelve months ended December 31, 2012.


 
Q3 2013 MD&A | 8


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. During the nine months ended September 30, 2013, Sonde recorded an impairment of $0.9 million ($0.6 million in the Northern Alberta CGU and $0.3 in the BC CGU) to reflect low natural gas prices. During the nine months ended September 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 nine months ended September 30, 2013 were calculated using a 14% discount rate. Using a discount rate of 13% would have reduced the impairment by $0.1 million. Using a discount rate of 15% would have increased the impairment by $0.1 million. Impairments recognized during the nine months ended September 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
 
Q3

Q2

Q3

Nine months ended
September 30
(CDN$ thousands, except where otherwise noted)
2013

2013

2012

2013

2012

Gross general and administrative expense
3,036

2,863

2,469

9,529

10,047

Capitalized general and administrative expense
(864
)
(589
)
(1,168
)
(2,259
)
(3,411
)
 
2,172

2,274

1,301

7,270

6,636

General and administrative expense ($/boe)
(11.64
)
(13.44
)
(6.56
)
(13.44
)
(10.02
)

For the three months ended September 30, 2013, gross general and administrative (“G&A”) expenses increased to $3.0 million from $2.9 million during the three months ended June 30, 2013 and from $2.5 million during the three months ended September 30, 2012 due to increased professional fees, primarily related to the Western Canadian strategic alternatives process.

Gross G&A for the three months ended September 30, 2013 consists of $0.5 million related to North Africa and $2.5 million related to Western Canada administration and the corporate head office. Gross G&A for the three months ended June 30, 2013 consists of $0.4 million related to North Africa and $2.5 million related to Western Canada administration and the corporate head office. Gross G&A for the three months ended September 30, 2012 consists of $0.7 million relating to North Africa and $1.8 million related to Western Canada administration and the corporate head office.

For the nine months ended September 30, 2013, gross G&A expenses decreased to $9.5 million from $10.0 million during the nine months ended September 30, 2012. Gross G&A consists of $1.6 million related to North Africa and $7.9 million related to Western Canada administration and the corporate head office. Gross G&A for the nine months ended September 30, 2012 consists of $2.4 million related to North Africa and $7.6 million related to Western Canada administration and the corporate head office.

Share based compensation
 
Q3

Q2

Q3

Nine months ended
September 30
(CDN$ thousands)
2013

2013

2012

2013

2012

Stock option expense
168

210

134

685

507

Stock unit award expense
169

(201
)
(572
)
(6
)
(590
)
Restricted share unit expense
11

(44
)
(115
)
(56
)
(309
)
Share based compensation
348

(35
)
(553
)
623

(392
)

Stock based compensation expense for the year nine months ended September 30, 2013 was $0.6 million compared to a gain of $0.4 million for the nine months ended September 30, 2012. The increase in stock based compensation during the nine months ended September 30, 2013 was due to higher stock option expense and a decrease in the gain recorded on stock units and restricted share units.

The decrease in the gain recorded on stock units and restricted share units is attributable to the Company's share price being consistent during the nine months ended September 30, 2013 compared to a large decrease in the Company's share price during the nine months ended September 30, 2012.


 
Q3 2013 MD&A | 9


Liquidity and capital resources

(CDN$ thousands)
September 30
2013

December 31
2012

Cash and cash equivalents
21,313

19,695

Accounts receivable
3,871

4,683

Current portion of prepaid expenses and deposits
537

733

Accounts payable and accrued liabilities
(5,508
)
(6,850
)
Stock based compensation liability
(814
)
(1,074
)
Working capital surplus
19,399

17,187


At September 30, 2013, the Company had $21.3 million in cash and cash equivalents (December 31, 2012 – $19.7 million). In 2012 cash flow was augmented by the February 8, 2012 sale of 24,383 net acres of undeveloped land in the Kaybob Duvernary play in Central Alberta for cash proceeds of $75 million, resulting in a gain of $73.4 million.

As at September 30, 2013, the Company had working capital of $19.4 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 September 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 for Western Canada operations and continues to pay standby fees on the undrawn facility. As at September 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 December 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 may make 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.


 
Q3 2013 MD&A | 10


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, as amended in June 2013, the minimum remaining work program for Phase II of the seven year exploration period (2013-2015) consists of three exploration wells and 200 square kilometers of 3D seismic.  Sonde has previously fulfilled its Phase I (2008-2012) commitments to drill the Zarat North-1 appraisal well and shoot 500 square kilometers of seismic. See "Contingencies and commitments, (b)" for details regarding the revised minimum work program.

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. The 2012 impairment was a result of the information discussed in the "Contingencies and commitments" section of the Company's 2012 annual MD&A, which has been updated below:

•
Inert and Acid Gas Initiative – In June, 2012, the 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 first phase of the study has been completed and work on the second phase has commenced. 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 latest assessment of drilling rig availability for operations offshore Tunisia indicate that the global demand for offshore drilling units was higher in other parts of the world than North Africa, making it very difficult to attract a suitable drilling rig for a short duration drilling program.
•
Unitization and Plan of Development – The DGE requested that the parties involved in the Zarat development submit to the DGE, for review and approval, the final draft of the Unitization Agreement by the first week of October 2013 and the Unit Plan of Development no later than December 31, 2013. Working with Joint Oil and ETAP, the Company finalized the draft Unitization Agreement and submitted it to the DGE the first week of October. The Company has proposed a new plan of development for Zarat that 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. The new plan of development is being finalized for submittal to Joint Oil for review and approval. With the final draft of the Unitization Agreement being agreed upon by Joint Oil, the Company expects Joint Oil to approve the Unit Plan of Development.
•
Exploratory Well Obligations – As discussed below, on December 24, 2012 the Company received an extension on its exploratory well obligations until December 23, 2015.
(b)
North Africa exploratory well extension and farm-out

On December 24, 2012, Joint Oil approved the 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 fourth quarter of 2013.

On December 27, 2012, the Company entered into an agreement with Viking providing for the farm-out of the Joint Oil Block. 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, subject to approval of the definitive form of Assignment Agreement and format of the Bank Guarantee (discussed below). The farm-out agreement contains the following terms:


 
Q3 2013 MD&A | 11


•
Viking will pay Sonde a US$3.0 million non-refundable signature bonus. As at September 30, 2013, 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;
•
Sonde will remain the operator of the Joint Oil Block. Viking will fund 100% of the Joint Oil Block share of the Unit Plan of Development for the Zarat Field.
•
Viking will acquire a 66.67% participating interest and Sonde will retain a 33.33% participating interest in the Zarat Field Unit Area;
•
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;
•
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.

On July 31, 2013, the definitive form of the farm-out agreement was executed by Sonde and Viking.

On September 25, 2013, Joint Oil approved the assignment to Viking and the definitive form of Assignment Agreement. The Assignment Agreement is subject to a condition that the previously disclosed Bank Guarantee must be fully funded prior to closing. Sonde and Viking signed the Assignment Agreement in the form approved by Joint Oil on October 4, 2013, and on October 25, 2013, the deadline to fund the Bank Guarantee and to close the Assignment Agreement and the Viking farm-out was extended to November 15, 2013. As of September 30, 2013, the Bank Guarantee had not been funded and no assurance can be provided that such funding will occur or that the farm-out will close.

(c)
Commitments and financial liabilities

At September 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
5,508

—

—

—

—

—

5,508

Stock based compensation liability
814

—

—

—

—

—

814

North Africa exploration commitments
19,061

15,455

15,455

—

—

—

49,971

Office rent payable
303

1,212

1,217

1,233

1,233

5,925

11,123

Office rent receivable
—

(404
)
(1,014
)
(1,233
)
(1,233
)
(5,925
)
(9,809
)
 
25,686

16,263

15,658

—

—

—

57,607


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. See "Arrangement Agreement with Marquee Energy" for an update regarding the Company's future cash flow from operating activities.

(d)
Litigation and claims

The Company is not involved in any claims or litigation arising in the ordinary course of business. The Company maintains insurance, which in the opinion of the Company, is sufficient to address any future claims as to matters insured.


 
Q3 2013 MD&A | 12


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 September 30, 2013, the Company has estimated $276.5 million in tax pools (December 31, 2012 - $281.3 million) including $153.4 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)
September 30
2013

December 31
2012

Canadian exploration expense
49,825

56,802

Canadian oil and gas property expense
390

—

Canadian development expense
15,552

21,791

Undepreciated capital costs
21,158

29,041

Foreign exploration expense
5,463

4,354

Non-capital losses
153,417

137,414

Capital losses
30,094

30,094

Share issue costs and other
567

1,767

 
276,466

281,263


Share capital
 
As at November 7, 2013, the Company had 62,301,446 common shares and 4.6 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 nine months ended September 30, 2013, and is based on the balances disclosed in this MD&A and the condensed consolidated financial statements for the nine months ended September 30, 2013:
(CDN$ thousands)
Petroleum and Natural Gas Sales

Change in average sales price for natural gas by $1.00/mcf
2,148

Change in the average sales price for oil and gas liquids by $1.00/bbl
183

Change in natural gas production by 1 mmcf/d
877

Change in crude oil and natural gas liquids production by 100 bbls/d
3,912


Interest rate risk

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

Credit risk

As at September 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 September 30, 2013, $0.7 million of accounts receivable are past due, all of which are considered to be collectible (December 31, 2012 - $0.9 million). The Company’s credit risk exposure is as follows:


 
Q3 2013 MD&A | 13


(CDN$ thousands)
September 30
2013

December 31
2012

Western Canada joint interest billings
1,849

2,310

Revenue accruals and other receivables
2,022

2,373

Accounts receivable
3,871

4,683

Cash and cash equivalents
21,313

19,695

Maximum credit exposure
25,184

24,378


Commodity price risk

The Company may enter 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 September 30, 2013. The gains and losses associated with this instrument are as follows:

Nine months ended



September 30, 2013
September 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)
$751

Foreign exchange risk

The Company’s foreign exchange risk denominated in U.S. dollars is as follows:

(US$ thousands)
September 30
2013

December 31
2012

Cash and cash equivalents
12,233

2,184

North Africa receivables
—

1

Foreign denominated financial assets
12,233

2,185

 
 
 
North Africa payables
425

566

Foreign denominated financial liabilities
425

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.

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. See "Arrangement Agreement with Marquee Energy" for an update regarding the Company's future cash flow from operating activities.

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.


 
Q3 2013 MD&A | 14


In addition, during the period beginning July 1, 2013 and ending September 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.

Quarterly financial summary

 
2013

2013

2013

2012

2012

2012

2012

2011

($ thousands except per share and production amounts)
Q3

Q2

Q1

Q4

Q3

Q2

Q1

Q4

Production
 

 

 

 

 

 

 

 

Natural gas (mcf/d)
8,244

7,423

7,934

8,940

8,757

9,665

11,553

12,186

Crude oil and natural gas liquids (bbl/d)
654

622

737

761

695

745

820

880

Total (boe/d)
2,028

1,858

2,059

2,251

2,155

2,356

2,746

2,911

 
















Petroleum & natural gas sales (2)
6,483

6,071

6,607

6,792

5,631

5,487

6,986

9,445

Net (loss) income from continuing operations
(4,399
)
(4,857
)
(5,412
)
(3,870
)
(2,073
)
(28,030
)
55,456

(36,483
)
Net (loss) income from continuing operations per share – basic and diluted
(0.07
)
(0.08
)
(0.09
)
(0.06
)
(0.03
)
(0.45
)
0.89

(0.58
)
Net (loss) income (1)
(4,399
)
(4,857
)
(5,412
)
(3,870
)
(2,073
)
(28,030
)
55,456

(36,500
)
Net (loss) income per share – basic and diluted (1)
(0.07
)
(0.08
)
(0.09
)
(0.06
)
(0.03
)
(0.45
)
0.89

(0.58
)
Funds from (used for) operations (3)
1,191

593

(472
)
123

494

(1,267
)
(667
)
3,155

Funds from (used for) operations per share – basic and diluted (3)
0.02

0.01

(0.01
)
0.01

0.01

(0.02
)
(0.01
)
0.05

(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; and
•
Fluctuations in the Company’s petroleum and natural gas sales and net (loss) income 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 September 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.

 
Q3 2013 MD&A | 15


Document 3

 
 
 
 
 


For Immediate Release
November 7, 2013


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


CALGARY, ALBERTA - (Marketwire – November 7, 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 third quarter ended September 30, 2013. The Management's Discussion and Analysis and Financial Statements for the quarter ended September 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 third quarter financial statements free of charge upon request.

Sonde will be hosting a conference call on Friday, November 8, 2013 at 1:30 p.m. MDT to provide a report on the third quarter 2013 results. Mr. Rene P. Beaumier, Chief Financial Officer, will host the call. All interested parties may join the call by dialing 416-340-2216 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 September 25, 2013, Joint Oil approved the assignment to Viking and the definitive form of Assignment Agreement. The Assignment Agreement is subject to a condition that the previously disclosed Bank Guarantee, of which Viking will contribute US$40 million and Sonde will contribute US$10.995 million, must be fully funded prior to closing.

Sonde and Viking signed the Assignment Agreement in the form approved by Joint Oil on October 4, 2013, and on October 25, 2013, the deadline to fund the Bank Guarantee and to close the Assignment Agreement and the Viking farm-out was extended to November 15, 2013. No assurance can be provided that such funding will occur or that the farm-out will close.

Western Canada

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 assisted in the process of analyzing and evaluating prospects and options available to the Company. As of November 7, 2013, the following transactions and potential transactions were undertaken by the Company.

(a) Dispositions

During the nine months ended September 30, 2013 the Company sold 45,671 net acres of undeveloped land in the Montney play and 44,094 acres of undeveloped land in the Duvernay play, both in Central Alberta, to an unrelated third party. This land was classified as exploration and evaluation assets and had a net book value of $2.6 million.

 
Q3 2013 Earnings Release | 1


In addition, the Company sold related property, plant and equipment associated with the Montney play, with a net book value of $5.9 million, to the same unrelated third party. These assets were sold for total proceeds of $6.1 million, resulting in a loss of $2.4 million.

The Company has exited the Montney play and divested certain licenses which contain Duvernay rights. Sonde retains undeveloped acreage in the Duvernay (44,341 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.

(b) Arrangement Agreement with Marquee Energy Ltd.
As previously announced, on November 4, 2013 the Company entered into an Arrangement Agreement with Marquee Energy Ltd. ("Marquee") whereby Marquee would acquire substantially all of the Western Canadian assets of Sonde, including all of its Southern Alberta properties ("the Assets"), ("the Transaction"). As consideration, Sonde will either receive:

•
0.72 of a Marquee Share for each Sonde Share outstanding, or in aggregate, 44,857,041 Marquee Shares; or
•
alternatively, Sonde has an option until November 20, 2013 to elect to receive 0.34 of a Marquee Share for each Sonde Share outstanding, or in aggregate 21,182,492 Marquee Shares, in addition to Sonde receiving $15 million in cash ("the Cash Election").

Sonde will transfer the Assets and related tax pools to a newly formed subsidiary of Sonde, which will either amalgamate with a wholly-owned subsidiary of Marquee or be directly acquired by Marquee pursuant to the a plan of arrangement. Sonde will distribute all Marquee Shares received to its shareholders, and retain the cash received if so elected.

The Transaction is subject to the approval of the Alberta Court of Queen's Bench under the Business Corporations Act (Alberta), the receipt of all necessary regulatory and stock exchange approvals, the requisite approval from 2/3 of the Sonde shareholders, and satisfaction of certain other closing conditions that are customary for a transaction of this nature. It is anticipated that a Sonde shareholder meeting will be held in late December, 2013 following the mailing of an information circular regarding the Transaction in early December, 2013. Assuming approval of the Transaction by Sonde shareholders, closing is expected to occur shortly thereafter.

The Board of Directors of Sonde unanimously supports the Transaction, has unanimously determined that the Transaction is fair to Sonde shareholders and in the best interest of Sonde and has agreed to unanimously recommend that the shareholders of Sonde vote in favor of the Transaction. Certain Sonde shareholders, including all officers and directors, who collectively hold over 12% of the issued and outstanding Sonde Shares, have entered into agreements with Marquee pursuant to which they have agreed to vote their shares in favour of the Transaction at the Sonde shareholder meeting.

Sonde will retain its current cash and working capital balances of approximately $19.4 million as at September 30, 2013, in addition to cash received in the Transaction should Sonde make the Cash Election. In addition, Sonde will retain ownership of approximately 100,000 net acres of Western Canada exploration assets, split approximately equally between its Eaglesham area Wabamun play and west central Alberta Duvernay play. Sonde will continue to seek strategic alternatives for the Western Canada exploration acreage, which could include cash sales, farm-outs, other forms of merger, or other options.
See the Company's news release dated November 5, 2013 and the Company's Management's Discussion and Analysis and Financial Statements for the quarter ended September 30, 2013 for further discussion regarding the Transaction.

2013 Western Canada drilling program

No wells were drilled during the three and nine months ended September 30, 2013 due to the strategic alternatives process discussed above. During the three and nine months ended September 30, 2013, Sonde continued its well re-activation program. Sonde performed 21 and 35 net workovers and recompletions during the three and nine months ended September 30, 2013.


 
Q3 2013 Earnings Release | 2


Third quarter financial and operational review
 
Q3

Q2

%

Q3

%

(CDN$ thousands, except where otherwise noted)
2013

2013

Change

2012

Change

Financial
 
 
 
 
 
Petroleum & natural gas sales(1)
6,483

6,071

7

5,631

15

Net loss
(4,399
)
(4,857
)
(9
)
(2,073
)
112

Net loss per share – basic and diluted
(0.07
)
(0.08
)
(13
)
(0.03
)
133

Funds from operations (2)
1,191

593

101

494

141

Funds from operations per share(2)
0.02

0.01

100

0.01

(90
)
Capital expenditures
2,263

1,090

108

14,716

(85
)
Working capital surplus
19,399

17,187

13

34,865

(44
)
Average shares outstanding
62,301

62,301

—

62,301

—

Production
 
 
 
 
 
Natural gas (mcf/d)
8,244

7,423

11

8,757

(6
)
Crude oil (bbl/d)
494

461

7

523

(6
)
Natural gas liquids (bbl/d)
160

161

(1
)
172

(7
)
Total (boe/d)
2,028

1,858

9

2,155

(6
)
Pricing
 
 
 
 
 
Natural gas ($/mcf)
2.52

3.90

(35
)
2.36

7

Crude oil ($/bbl)
97.77

83.58

17

77.09

27

Natural gas liquids ($/bbl)
62.43

49.72

26

52.24

20

Average sales price ($/boe)
39.00

40.59

(4
)
32.46

20

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 September 30, 2013, funds from operations was $1.2 million compared to funds from operations of $0.5 million for the same period in 2012. This was primarily the result of a 7% increase in net petroleum and natural gas revenue and an 87% decrease in well workover expense.

For the three months ended September 30, 2013, production averaged 2,028 boe/d, compared to 1,858 boe/d for the three months ended June 30, 2013 and 2,155 boe/d for the three months ended September 30, 2012. The increase in production during the three months ended September 30, 2013 compared to the three months ended June 30, 2013 is due to significant third-party natural gas processing plant outages in Central Alberta and weather related access issues experienced during the three months ended June 30, 2013. The decrease in production compared to the three months ended September 30, 2012 is due to natural decline 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 completion of the proposed arrangement with Marquee Energy Ltd., 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 operations and funds from 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 operations and funds from operations per share are relevant indicators of the Company’s financial performance, and ability to fund future capital expenditures. Funds from 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 Sonde's MD&A, a reconciliation has been prepared of funds from (used for) operations to cash provided by operating activities, the most comparable measure calculated in accordance with IFRS.

 
Q3 2013 Earnings Release | 3


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 potential closing of the Viking farm-out agreement, the potential completion and closing of the Transaction with Marquee, the mailing of an information circular related to the Transaction with Marquee, the receipt of all of the requisite approvals associated with the Transaction with Marquee, the the potential distribution of all Marquee Shares received by Sonde as a result of the Transaction to Sonde's shareholders, Sonde's expected retention of the cash received from Marquee if so elected, 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.

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

Rene P. Beaumier, Chief Financial Officer
Phone: (403) 503-7931
Fax:      (403) 216-2374
www.sonderesources.com

 
Q3 2013 Earnings Release | 4


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 September 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 July 1, 2013 and ended on September 30, 2013 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.
Date: November 7, 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, Rene P. Beaumier, the Chief Financial Officer of Sonde Resources Corp., certify the following:
 
1.
Review: I have reviewed the interim financial report and interim MD&A (together, the “interim filings”) of Sonde Resources Corp. (the “issuer”) for the interim period ended September 30, 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 July 1, 2013 and ended on September 30, 2013 that has materially affected, or reasonably likely to materially affect, the issuer’s ICFR.
Date: November 7, 2013


/s/ Rene P. Beaumier     
Rene P. Beaumier
Chief Financial Officer
Sonde Resources Corp.



SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
 
 
SONDE RESOURCES CORP.
 
 
 
 
(Registrant)
Date:
November 7, 2013
By:
/s/ Cheryl Clark
 
 
 
Name:
Title: 
Cheryl Clark
Corporate Controller/Assistant Corporate Secretary