Exhibit 1.2
  MANAGEMENT’S REPORT TO THE SHAREHOLDERS
 
 Management’s Responsibility for Financial Statements
  The preparation of the accompanying consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, is the responsibility of management. Management is responsible for the integrity and objectivity of the consolidated financial statements. Where necessary, the consolidated financial statements include estimates, which are based on management’s informed judgments. Management has established systems of internal controls, which are designed to provide reasonable assurance that transactions are authorized, assets are safeguarded and financial records are properly maintained to provide reliable information for the preparation of financial information.
  The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. It exercises its responsibilities primarily through the Audit Committee, whose members are independent directors. The Audit Committee has reviewed the consolidated financial statements with management and the external auditors and has reported to the Board of Directors who have approved the consolidated financial statements. The external auditors have full access to the Audit Committee with or without the presence of management.
  The consolidated financial statements have been audited by Deloitte LLP, Independent Registered Chartered Accountants, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) on behalf of the Board of Directors and Shareholders.
  Management’s Report on Internal Control Over Financial Reporting
  Management is responsible for establishing and maintaining adequate internal controls over financial reporting. Management has assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2012 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Company’s internal control over financial reporting. Based on this assessment, Management has assessed the effectiveness of the Company’s internal controls over financial reporting as at December 31, 2012 and has concluded that such controls were effective as at that date.
  It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. In reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
  The effectiveness of the Company’s internal control over financial reporting as of December 31, 2012 has been audited by Deloitte LLP, Independent Registered Chartered Accountants, as stated in their report, which is included herein.
   (Signed) “Jack W. Schanck”

(Signed) “Kurt A. Nelson”Jack W. Schanck

Kurt A. NelsonPresident and Chief Executive Officer

Chief Financial OfficerCalgary, Canada

Calgary, CanadaMarch 21, 2013

March 21, 2013
  2012 Annual Financial Statements|1
  REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
 
 To the Board of Directors and the Shareholders of Sonde Resources Corp.:
  We have audited the accompanying consolidated financial statements of Sonde Resources Corp. and its subsidiaries (the “Company”), which comprise the consolidated statements of financial position as at December 31, 2012 and 2011 and the consolidated statements of operations and comprehensive income (loss), consolidated statements of changes in shareholders’ equity and consolidated statements of cash flows for the years then ended, and the notes to the consolidated financial statements.
  Management’s Responsibility for the Consolidated Financial Statements
  Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
  Auditor’s Responsibility
  Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
  An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error.
  In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
  We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
  Opinion
  In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Sonde Resources Corp. and its subsidiaries as at December 31, 2012 and 2011 and its financial performance and its cash flows for the years then ended, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.
  Emphasis of Matter
  Without qualifying our opinion, we draw attention to Note 2(b) in the consolidated financial statements which indicates that the Company incurred an operating loss of $50.9 million during the year ended December 31, 2012 (2011 – $46.7 million) and had an accumulated deficit of $255.6 million as at December 31, 2012. These conditions, along with other matters as set forth in Note 12 indicate the existence of material uncertainties that cast substantial doubt about the Company’s ability to continue as a going concern.
 2012 Annual Financial Statements|2
  Other Matter
  We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established in InternalControl–IntegratedFrameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 21, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
  
 
 (Signed) “Deloitte LLP”
 
 Independent Registered Chartered Accountants
 Calgary, Canada
 March 21, 2013
  2012 Annual Financial Statements|3
  REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS
 
 To the Board of Directors and the Shareholders of Sonde Resources Corp.:
  We have audited the internal control over financial reporting of Sonde Resources Corp. and its subsidiaries (the “Company”) as of December 31, 2012, based on the criteria established in InternalControl – IntegratedFrameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
  We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
  A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles.
  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the consolidated financial statements.
  Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
  In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in InternalControl–Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
 We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Company and our report dated March 21, 2013 expressed an unqualified opinion on those consolidated financial statements.
  
 (Signed) “Deloitte LLP”
 
 Independent Registered Chartered Accountants
 Calgary, Canada
 March 21, 2013
 2012 Annual Financial Statements|4
  CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
Note
December 31

2012
December 31

2011(CDN$ thousands)AssetsCurrentCash and cash equivalents
9
19,695
3,743Accounts receivable
10
4,683
7,436Prepaid expenses and deposits

733
1,52825,111
12,707Long term portion of prepaid expenses and deposits

732
420Exploration and evaluation assets
5
56,499
69,015Property, plant and equipment
5
104,144
104,745186,486
186,887LiabilitiesCurrentAccounts payable and accrued liabilities

6,850
17,655Share based compensation liability
7
1,074
2,448Derivative financial liabilities
9
--
781Provisions
11
--
12,7307,924
33,614Decommissioning provision
11
29,972
26,34437,896
59,958Contingencies and commitments
12Shareholders’ EquityShare capital
16
369,892
369,892Contributed surplus

34,290
33,528Foreign currency translation reserve

(34)
550Deficit

(255,558)
(277,041)148,590
126,929Going concern
2(b)Segments
19Subsequent event
21186,486
186,887See accompanying notes to the consolidated financial statements
 
 On behalf of the Board,
 
 (Signed) “Jack W. Schanck”

(Signed) “W. Gordon Lancaster”Jack W. Schanck

W. Gordon LancasterDirector and Chief Executive Officer

Director and Chair of the Audit Committee
 2012 Annual Financial Statements|5
  CONSOLIDATED STATEMENTS OF

OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
Note
Year ended

December 31, 2012
Year ended

December 31, 2011(CDN$ thousands, except per share amounts)RevenueRevenue, net of royalties
14
25,587
35,006Gain on commodity derivatives
9
689
20726,276
35,213ExpensesOperating
15
17,169
15,527Transportation

599
1,042Exploration and evaluation
5
22,735
1,270General and administrative

8,505
9,124Depletion and depreciation

11,031
14,906Share based compensation
7
656
4,728Property, plant and equipment impairment
5
16,241
34,270Loss on settlement of decommissioning liabilities

199
1,02777,135
81,894Operating loss

(50,859)
(46,681)OtherFinancing costs
13
(930)
(2,422)Loss on foreign exchange

(466)
(183)Gain on financial derivatives
13
--
5,129Other income

192
428Gain on disposition of exploration and evaluation assets
5
73,581
39072,377
3,342Income (loss) from continuing operations before taxes

21,518
(43,339)Current income taxes
20
35
136Income (loss) from continuing operations

21,483
(43,475)Income from discontinued operations, net tax
18
--
2,904Net income (loss)

21,483
(40,571)Other comprehensive (loss) incomeForeign currency translation adjustment

(584)
1,102Foreign currency translation adjustment relating to assets and liabilities of discontinued operations
18
--
(1,128)Foreign currency translation reclassified to net earnings
18
--
6,365Other comprehensive (loss) income

(584)
6,339Total comprehensive income (loss)

20,899
(34,232)Net loss per common shareBasic and diluted income (loss) per common share from continuing operations
16
$0.34
($0.70)Basic and diluted income per common share from discontinued operations
16
--
0.05$0.34
($0.65)
 2012 Annual Financial Statements|6
 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
Note
Year ended

December 31, 2012
Year ended

December 31, 2011(CDN$ thousands)Cash provided by (used in):OperatingNet income (loss)

21,483
(40,571)Items not involving cash:Depletion and depreciation

11,031
14,906Share based compensation
7
656
4,728Exploration and evaluation
5
22,735
1,270Property, plant and equipment impairment
5
16,241
34,270Unrealized (gain) loss on commodity derivatives
9
(781)
781Unrealized gain on financial derivatives

--
(5,129)Unrealized loss on foreign exchange

55
776Financing costs
13
930
2,915Loss on settlement of decommissioning liabilities

199
1,027Gain on disposition of exploration and evaluation assets
5
(73,581)
(390)Gain on disposition of discontinued operations

--
(4,919)Interest paid

(285)
(2,067)Decommissioning expenditures

(379)
(1,221)Changes in non-cash working capital
17
2,776
(1,268)1,080
5,108FinancingExercise of restricted share units
7
(150)
--Exercise of stock unit awards
7
(1,118)
--Revolving credit facility repayments

(23,400)
(44,094)Revolving credit facility advances

23,400
23,843Redemption of preferred shares
13
--
(15,255)Change in non-cash working capital
17
(196)
131(1,464)
(35,375)InvestingProperty, plant and equipment additions

(23,506)
(37,509)Exploration and evaluation additions

(13,696)
(19,405)Asset additions related to discontinued operations

--
(565)Farm-out proceeds
5
995
--Property acquisition
6
--
(6,242)Proceeds on property, plant and equipment disposition
5
75,229
502Proceeds on Trinidad disposition
18
--
87,908Decrease in restricted cash
18
--
19,892Change in non-cash working capital
17
(22,631)
(12,881)16,391
31,700Increase in cash and cash equivalents

16,007
1,433Effect of foreign exchange on cash and cash equivalents

(55)
(339)Cash and cash equivalents, beginning of year

3,743
2,649Cash and cash equivalents, end of year
9
19,695
3,743
 2012 Annual Financial Statements|7
  CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
 
 (CDN$ thousands)
Share capital
Contributed surplus
Foreign currency translation
Deficit
TotalAt December 31, 2010
369,892
30,718
(5,789)
(236,470)
158,351Total comprehensive loss
--
--
(26)
(34,206)
(34,232)Foreign currency translation reserve reclassified to net earnings (note 18)
--
--
6,365
(6,365)
--Stock option expense
--
2,810
--
--
2,810At December 31, 2011
369,892
33,528
550
(277,041)
126,929Total comprehensive income
--
--
(584)
21,483
20,899Stock option expense
--
762
--
--
762At December 31, 2012
369,892
34,290
(34)
(255,558)
148,590
  See accompanying notes to the consolidated financial statements
 
 2012 Annual Financial Statements|8
  NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
 For the years ended December 31, 2012 and 2011
 (All tabular amounts in CDN$ thousands, except where otherwise noted)
 
 1.
Reporting entity
  Sonde Resources Corp. (“Sonde” or the “Company”) is a Canadian based energy company with its head office located at Suite 3200, 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. All of the Company’s revenues are generated from its operations in Western Canada.
  On February 22, 2011, the Company completed the sale of its wholly owned subsidiary Liberty Natural Gas LLC (the “LNG Project”). On June 22, 2011, the Company completed the sale of its offshore operations in the Republic of Trinidad and Tobago (“Trinidad and Tobago”). These dispositions are discussed in more detail in Note 18. The 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 Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board and present the Company’s results of operations and financial position under IFRS as at and for the years ended December 31, 2012 and 2011.
  The Financial Statements were approved and authorized for issue by the Board on March 21, 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 year ended December 31, 2012, the Company had an operating loss of $50.9 million and an accumulated deficit of $255.6 million. Management believes that the going concern assumption is appropriate for the Financial Statements; however, items discussed in Note 12 – “Commitments and Contingencies”, describe significant uncertainties that cast substantial doubt over the Company’s ability to continue as a going concern. If this assumption was 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 Note 3. The accounting policies have been applied consistently to all periods presented in the Financial Statements.
  (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.  See Note 4.
 
 2012 Annual Financial Statements|9
  3.
Significant accounting policies
  The accounting policies set out below have been applied consistently to all years presented in the Financial Statements.
  (a)   Principles of consolidation
  The Company consolidates its interest in entities in which it controls. Control comprises the power to govern an entity’s financial and operating policies so as to obtain benefits from its activities. The Company recognizes its proportionate share of assets, liabilities, income and expenses, on a line-by-line basis, of its jointly controlled assets. All material intercompany balances, transactions, revenue and expenses have been eliminated.
  (b)   Cash and cash equivalents
  Cash and cash equivalents consist of balances with banks and investments in highly liquid short-term deposits with a maturity date, at date of issue, of less than ninety days.
  (c)   Foreign currency
  Functional currencies of the Company’s foreign operations represent the currency of the primary economic environment in which it operates. Transactions in foreign currencies are translated to the appropriate functional currency at foreign exchange rates that approximate those on the date of transaction. At each reporting date, monetary assets and liabilities denominated in foreign currencies are translated to the appropriate functional currency at foreign exchange rates at the statement of financial position date. Foreign exchange differences arising on translation are recognized in earnings. Non-monetary assets that are measured in a foreign currency at historical cost are translated using the exchange rate at the date of the transaction.
  In preparing the Financial Statements, the financial statements of each entity are translated into Canadian dollars, the Company’s presentation currency. The assets and liabilities of foreign operations are translated into Canadian dollars using foreign exchange rates at the statement of financial position date. Revenues and expenses of foreign operations are translated into Canadian dollars using foreign exchange rates that approximate those on the date of the underlying transaction. Foreign exchange differences are recognized in other comprehensive income.
  If the Company disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign operation are recognized in net income or loss.
  (d)   Exploration and evaluation assets and property, plant and equipment
  (i)
Recognition and measurement
  Costs of exploring for and evaluating oil and natural gas properties are initially capitalized within exploration and evaluation assets. Such exploration and evaluation costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable overhead and administration expenses and the projected costs of retiring the assets (if any), but do not include exploration or evaluation costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to net income or loss as they are incurred.
  Exploration and evaluation assets are not amortized, but are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. These assets are subject to technical, commercial and management review to confirm the continued intent to develop and extract the underlying resources. If an area or exploration well is no longer considered commercially viable, the assets may be transferred to intangible assets when it meets the recognition criteria for intangible assets. Not proceeding with development of the asset is an impairment indicator, and as a result of the decision not to develop the asset impairment testing would be performed.
  2012 Annual Financial Statements|10
 3.
Significant accounting policies (continued)
  When management determines with reasonable certainty that an exploration and evaluation asset will be developed, as evidenced by the classification of proved or probable reserves and the appropriate internal and external approvals, the asset is first tested for impairment and then reclassified to property, plant and equipment.
  Farm-out proceeds received during the exploration and evaluation stage are deducted against the related exploration and evaluation asset until the carrying value of the asset is nil.  Any additional proceeds are recorded in the Consolidated Statements of Operations.
  Items of property, plant and equipment are measured at cost less accumulated depletion and depreciation and accumulated impairment losses.  When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items.
  The costs to acquire developed or producing oil and gas properties and to develop oil and gas properties, including completing geological and geophysical surveys and drilling development wells, and the costs to construct and install dedicated infrastructure such as wellhead equipment and supporting assets, are capitalized as oil and gas properties within property plant and equipment.
  The costs of major inspection, overhaul and work-over activities that maintain property, plant and equipment and benefit future years of operations are capitalized. Maintenance is expensed as incurred. Replacements outside major inspection, overhaul or work-overs are capitalized when it is probable that future economic benefits will flow to the Company and the associated carrying amount of the replaced asset is derecognized.
  Gains and losses on disposal of an item of property, plant and equipment, including oil and natural gas interests, and intangible exploration assets, are determined by comparing the proceeds from disposal with its carrying amount and are recognized within “other income” or “other expenses” in net income or loss.
  Borrowing costs incurred for the construction of qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. All other borrowing costs are recognized in net income or loss as incurred. Capitalization of borrowing costs ceases when the asset is in the location and condition necessary for it to be capable of operating as intended. Capitalization of borrowing costs is suspended when the construction of an asset is ceased for extended periods.
  The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Company’s outstanding annual borrowings.
  (ii)
Depletion and depreciation
  The carrying amount of development or production assets is depleted using the unit of production method by reference to the ratio of production in the year to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves.
  Proved and probable reserves are estimated annually by independent reserve engineers and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a more than 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable. The equivalent statistical probability for the proved component is 90%.
 2012 Annual Financial Statements|11
  3.
Significant accounting policies (continued)
  Such reserves may be considered economically producible if management has the intention of developing and producing them and such intention is based upon:
  ·
a reasonable assessment of the future economics of such production;
  ·
a reasonable expectation that there is a market for all or substantially all the expected oil and natural gas production;
  ·
evidence that necessary production, transmission and transportation facilities are available or can be made available; and
  ·
availability of capital to develop reserves.
  Reserves may only be considered proved and probable if supported by either actual production or a conclusive formation test. The area of reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of oil and natural gas controls the lower proved limit of the reservoir.
  Reserves which can be produced economically through application of unproved recovery techniques (such as fluid injection) are only included in the proved and probable classification when successfully tested by a pilot project, the operation of an installed program in the reservoir or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or program was based.
  For other assets, depreciation is recognized in net income or loss on a declining balance basis over its estimated useful life at rates varying from 20% to 100%. Land is not depreciated.
  Depreciation methods, useful lives and residual values are reviewed annually.
  (e)   Leased assets
  Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases.  Upon initial recognition the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments.  Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to the asset. The Company does not have any finance leases.
  Other leases are operating leases, which are expensed as incurred.
  Payments made under operating leases are recognized in net income or loss on a straight-line basis over the term of the lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the lease.
  (f)    Impairment
  (i)
Non-financial assets
  The carrying amount of the Company’s non-financial assets, other than exploration and evaluation assets and deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. Exploration and evaluation assets are assessed for impairment when they are reclassified to property, plant and equipment and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.
 2012 Annual Financial Statements|12
  3.
Significant accounting policies (continued)
  For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the “cash-generating unit” or “CGU”). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell.
  In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.
  In assessing fair value less cost to sell, the fair value reflects the price a market participant would be willing to pay to acquire the asset or CGU less selling costs to complete the transaction. Fair value is generally determined based on recent transactions, crown land sales and other market metrics.
  Exploration and evaluation assets are allocated to the CGUs on a geographical basis when they are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their eventual reclassification to oil and natural gas interests in property, plant and equipment.
  An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in net income or loss. Impairment losses recognized in respect of CGUs reduce the carrying amount of the other assets in the unit (group of units) on a pro rata basis.
  An impairment loss recognized in prior years is assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.
  (ii)
Financial assets
  A financial asset, other than a financial asset designated as fair value through profit or loss, is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.
  An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.
  All impairment losses are recognized in net income or loss. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized and is recognized in net income or loss.
  (g)   Financial instruments
  Financial assets and liabilities designated as fair value through profit or loss are measured at fair value with changes in those fair values recognized in the statement of operations.
  Financial assets available for sale are measured at fair value, with changes in those fair values recognized in other comprehensive income. Financial assets held to maturity, loans and other receivables and other financial liabilities are measured at amortized cost using the effective interest method. Derivatives are classified as fair value through profit or loss and measured at their fair value. Gains or losses related to periodic revaluation are recorded in income.
 2012 Annual Financial Statements|13
 
 3.
Significant accounting policies (continued)
  Fair value measurements are classified according to the following hierarchy based on the amount of observable inputs used to value the instrument.


Level 1:
Quoted prices are available in active markets. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
 
 Level 2:
Pricing inputs are other than quoted prices in an active market included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the market place.
 
 Level 3:
Valuation at this level are those inputs for the asset or liability that are not based on observable market data.


Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy.
  (h)   Share based compensation
  (i)
Stock option awards
  Share based compensation is recorded in net income or loss for all options granted on a graded basis over the vesting period of the option with a corresponding increase recorded as contributed surplus.  Compensation expense is based on the estimated fair values of the options at the time of the grant as determined using a Black-Scholes option pricing model. The Company incorporates an estimated forfeiture rate when determining compensation expense for stock options that will not vest.
  Upon the exercise of the stock options, consideration paid together with the amount previously recognized in contributed surplus is recorded as an increase in share capital.  In the event that vested options expire, previously recognized compensation expense associated with such stock options is not reversed.
  (ii)
Stock unit awards and restricted share units
  Stock unit awards and restricted share units are only payable in cash. Obligations are accrued based on the vesting period of the units using the market value of the Company’s common shares. The obligations are revalued each reporting period based on the change in the fair value of the Company’s common shares and the number of units outstanding. The Company reduces the liability when the units are surrendered for cash.
  (i)     Provisions
  A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the liability. Provisions are not recognized for future operating losses. Further details on specific provisions are as follows:
  (i)
Decommissioning liabilities
  The Company recognizes the estimated liability associated with decommissioning at the time the asset is acquired and the liability is incurred. The estimated present value of the future payments of the decommissioning liability is recorded as a long term liability, with a corresponding increase in the carrying amount of property, plant and equipment. Amounts are discounted using the risk-free rate. The capitalized amount is depleted on a unit-of-production method over the life of proved and probable reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to net income or loss in the period.


2012 Annual Financial Statements|14




3.
Significant accounting policies (continued)




The liability can also increase or decrease due to changes in the estimates of timing of cash flows, changes to the risk-free rate or changes in the original estimated undiscounted cost. The change in the provision as a result of these changes is capitalized in the carrying amount of the related asset. Actual costs incurred upon settlement of decommissioning liabilities are charged against the decommissioning liability to the extent of the liability recorded.




(ii)
Onerous contracts




A provision for onerous contracts is recognized when the expected benefits to be derived by the Company from a contract are lower than the unavoidable cost of meeting its obligation under the contract. The provision is measured at the present value of the lower of the expected cost of terminating the contract and the expected net costs of continuing with the contract.




(j)
Revenue




Revenue from the sale of natural gas, oil and natural gas liquids is recognized based on volumes delivered to customers at contractual delivery points and rates.  Revenue is measured net of royalties.




Revenue is recognized when persuasive evidence exists that the significant risks and rewards have been transferred to the customer and the amount of revenue can be measured reliably, and when recovery of the consideration is probable. Recognition occurs upon delivery.




Tariffs and tolls charged to other entities for use of pipelines and facilities owned by the Company are recognized as revenue as they accrue in accordance with the terms of the service or tariff and tolling agreement. Royalty income is recognized on operating lease rights as it accrues in accordance with the terms of the overriding royalty agreements. The costs associated with delivery, including operating and maintenance costs, transportation, and production-based royalty expenses are recognized in the same period in which the related revenue is earned and recorded.




(k)
Assets held for sale




Assets and liabilities are classified as held for sale if their carrying values are expected to be recovered through a disposition rather than through continuing use. The assets or disposal groups are measured at the lower of their net book value and fair value less cost to sell. Impairment losses on initial classification as held for sale and subsequent gains or losses on re-measurement are recognized in net income or loss. Assets classified as held for sale are not depreciated, depleted or amortized.




(l)
Income taxes




The Company follows the liability method of accounting for income taxes whereby deferred income taxes are recorded for unused tax losses, tax credits and the effect of differences between the accounting and income tax basis of an asset or liability. Deferred income tax assets and liabilities are measured using enacted or substantively enacted income tax rates at the statement of financial position date that are anticipated to apply to taxable income in the years in which temporary differences are anticipated to be recovered or settled. Changes to these balances are recognized in income in the period which they occur. Investment tax credits are recorded as an offset to the related expenditures.


(m)
Share capital




Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any tax effects.




(n)
Basic and diluted per share amounts




Basic per share amounts are calculated by dividing net income or loss attributable to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted earnings per share amounts are calculated by adjusting the net income or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of all dilutive potential common shares, which comprise convertible preferred shares, warrants, and stock options granted to employees. The Company utilizes the treasury stock method in the determination of diluted per share amounts.





2012 Annual Financial Statements|15




3.
Significant accounting policies (continued)
  Under this method, the diluted weighted average number of shares is calculated assuming that proceeds arising from the exercise of in-the-money options and other dilutive instruments are used to purchase, for cancellation, common shares of the Company at their average market price for the period. The “if converted” method is used for calculating diluted earnings per share for the convertible preferred shares.
  (o)   Future accounting changes
  The Company has reviewed new and revised accounting pronouncements that have been issued but are not yet effective and determined that the following may have an impact on the Company:
  As of January 1, 2015, the Company will be required to adopt IFRS 9 “Financial Instruments”, which is the result of the first phase of the International Accounting Standards Board (“IASB”) project to replace IAS 39 “Financial Instruments: Recognition and Measurement”. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The full impact of the standard on the Company’s Financial Statements is not yet known.
  In May 2011, the IASB released the following new standards: IFRS 10, “Consolidated Financial Statements”, IFRS 11, “Joint Arrangements”, IFRS 12, “Disclosures of interests in other entities” and IFRS 13, “Fair Value Measurement”. Each of these standards is to be adopted for fiscal years beginning January 1, 2013. A brief description of each new standard follows below:
  ·
IFRS 10, “Consolidated Financial Statements” supersedes IAS 27 “Consolidation and Separate Financial Statements” and SIC-12 “Consolidation – Special Purpose Entities”. This standard provides a single model to be applied in control analysis for all investees including special purpose entities.
  ·
IFRS 11, “Joint Arrangements” divides joint arrangements into two types, joint operations and joint ventures, each with their own accounting model. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting.
  ·
IFRS 12, “Disclosure of Interests in Other Entities” combines in a single standard the disclosure requirements for subsidiaries, associates and joint arrangements as well as unconsolidated structured entities.
  ·
IFRS 13, “Fair Value Measurement” defines fair value, establishes a framework for measuring fair value and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
  The adoption of these standards is not expected to have a material impact on the Company’s financial statements.
 4.
Significant accounting estimates and judgments
 Significant estimates used in the preparation of the Financial Statements include, but are not limited to, those areas discussed below.
  (a)   Oil and gas reserves
  Certain depletion, depreciation, impairment and decommissioning and restoration charges are measured based on the Company’s estimate of oil and gas reserves. The estimation of reserves and resources is an inherently complex process and involves the exercise of professional judgment. Reserves and resources have been evaluated at December 31, 2012 and 2011 by independent petroleum consultants in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The reserves and resources estimates are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook.


2012 Annual Financial Statements|16




4.
Significant accounting estimates and judgments (continued)




Oil and gas reserves and resources estimates are based on a range of geological, technical and economic factors, including projected future rates of production, estimated commodity prices, engineering data, and the timing and amount of future expenditures, all of which are subject to uncertainty. Assumptions reflect market and regulatory conditions existing at each annual reporting date, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.




(b)   Exploration and evaluation costs




Certain exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. The Company is required to make estimates and judgments about the future events and circumstances regarding the economic viability of extracting the underlying resources. The costs are subject to technical, commercial and management review to confirm the continued intent to develop and extract the underlying resources. Unsuccessful drilling, or changes to project economics, resource quantities, expected production techniques, production costs and required capital expenditures, are important factors when making this determination. If a judgment is made that the extraction of resources is not viable, the associated exploration and evaluation costs are impaired and charged to net income or loss.




(c)   Decommissioning liabilities and other provisions




The Company recognizes liabilities for the future decommissioning and restoration of property, plant and equipment. These provisions are based on estimated costs, which take into account the anticipated method and extent of restoration, technological advances and the possible future use of the site. Actual costs are uncertain and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience and prices. The expected timing of future decommissioning and restoration may change due to certain factors, including reserve life. Changes to assumptions related to future expected costs, discount rates and timing may have a material impact on the amounts presented. Other provisions are recognized in the period in which it becomes probable that there will be a future cash outflow.




(d)   Deferred income taxes




Deferred tax assets are recognized when it is considered probable that unused tax losses, tax credits and deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of tax laws in each jurisdiction differ significantly from the Company’s estimate, the ability of the Company to realize the deferred tax asset could be impacted.




Deferred tax liabilities are recognized for taxable temporary differences. The Company records a provision for the amount that is expected to be settled, which requires the application of judgment as to the ultimate outcome. Deferred tax liabilities could be impacted by changes in the Company’s estimate of the likelihood of a future outflow, the expected settlement amount, and the tax laws in the jurisdiction which the Company operates.




(e)   Impairment of assets




The allocation of assets into CGUs requires significant judgment and interpretations with respect to the geographical location, similar reservoir characteristics and development plans, integration between assets, the existence of active markets, similar exposure to market risks, discrete processing and gathering facilities versus shared infrastructures, and the way in which management monitors the operations.




The recoverable amounts of CGUs and individual assets have been determined based on value in use. The key assumptions the Company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes and future operating and development costs. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value.




2012 Annual Financial Statements|17




4.
Significant accounting estimates and judgments (continued)




Impairment tests were carried out at December 31, 2012, using the following forward commodity price projections:




Year
AECO Gas

(Cdn/mmbtu)(1)

Edmonton Light

Sweet Crude Oil

(Cdn/bbl)(1)2013
3.38

85.002014
3.83

91.502015
4.28

94.002016
4.72

96.502017
4.95

96.502018
5.22

96.502019
5.32

97.542020
5.43

99.512021
5.54

101.522022
5.64

103.57Remainder(2)
2.0%

2.0%(1)  Source: Independent qualified reserves evaluator’s price forecast, effective January 1, 2013.(2)  Percentage change represents the change in each year after 2022 to the end of the reserve life.





An impairment test is performed on capitalized property and equipment costs at a CGU level when indicators of impairment exist.  During the year ended December 31, 2012, the Company recognized an impairment of $16.2 million (December 31, 2011 – $34.3 million).




The impairments of $16.2 million recorded during the twelve months ended December 31, 2012 and $34.3 million recorded during the twelve months ended December 31, 2011 reflect changes in reserves and an estimated low natural gas price environment for future production. As per Note 5 (c), the impairments recorded during the year ended December 31, 2012 were recorded in the Southern Alberta, Central Alberta and Northern Alberta CGUs (December 31, 2011 – All Canadian CGUs).




The December 31, 2012 impairment was recognized using an 11% discounted cash flow (December 31, 2011 – 12%).  Using a discount rate of 10% would reduce 2012 impairment by $5.8 million (December 31, 2011 – $9.4 million).  Using a discount rate of 12% would increase 2012 impairment by $5.2 million (December 31, 2011 – nil).




(f)    Share based compensation




Expenses recorded for share based compensation are based on the historical volatility of the Company’s share price which may not be indicative of the future volatility. Accordingly, those amounts are subject to measurement uncertainty.




2012 Annual Financial Statements|18


5.
Exploration and evaluation assets and property, plant and equipment
  December 31, 2012

December 31, 2011Cost

Accum.  DD&A

Carrying value

Cost

Accum.  DD&A

Carrying valueExploration and evaluation assetsBeginning of year

69,015

--

69,015

49,361

--

49,361Additions

13,696

--

13,696

19,405

--

19,405Dispositions

(1,647)

--

(1,647)

--

--

--Farm-out proceeds

(995)

--

(995)

--

--

--Transfers to PP&E

--

--

--

(43)

--

(43)Impairments, to exploration expense

--

(22,735)

(22,735)

--

(1,270)

(1,270)Change in decommissioning obligations

--

--

--

41

--

41Foreign exchange

(835)

--

(835)

1,521

--

1,521End of year

79,234

(22,735)

56,499

70,285

(1,270)

69,015Property, plant and equipmentBeginning of year

212,453

(107,708)

104,745

161,165

(58,562)

102,603Additions

23,506

--

23,506

37,509

--

37,509Acquisitions

--

--

--

11,827

--

11,827Dispositions

--

--

--

(151)

30

(121)Transfers from E&E assets

--

--

--

43

--

43Change in decommissioning obligations

3,165

--

3,165

2,060

--

2,060Depreciation and depletion

--

(11,031)

(11,031)

--

(14,906)

(14,906)Impairments

--

(16,241)

(16,241)

--

(34,270)

(34,270)End of year

239,124

(134,980)

104,144

212,453

(107,708)

104,745
 
 (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 year ended December 31, 2012 the Company capitalized $4.6 million (December 31, 2011 – $3.3 million) of general and administrative expenses related to exploration and evaluation activities in North Africa ($3.1 million) and Western Canada ($1.5 million).
 
 On February 8, 2012, the Company completed the sale to an unrelated third party of 24,383 net acres of undeveloped land in the Kaybob Duvernay play in Central Alberta for cash proceeds of $75.0 million. This land was classified as exploration and evaluation assets at December 31, 2011, and had a carrying value of $1.6 million, resulting in a gain of $73.4 million. The Company’s tax pools offset the taxes associated with the gain.
 
 In October 2012 the Company completed the sale to an unrelated third party of 800 net acres of undeveloped land for cash proceeds of $0.3 million.  This land was classified as exploration and evaluation assets at September 30, 2012, and had a carrying value of $0.1 million, resulting in a gain of $0.2 million. The Company’s tax pools offset the taxes associated with the gain.
 
 Land expiries and impairment on Western Canada exploratory wells charged to exploration and evaluation expense during the year ended December 31, 2012 totaled $1.7 million (December 31, 2011 – $1.3 million).  As at December 31, 2012, no indicators of impairment were identified in Western Canada that would imply a further decline in exploration and evaluation asset carrying values.


2012 Annual Financial Statements|19




5.
Exploration and evaluation assets and property, plant and equipment (continued)
  (b)   North Africa exploration and evaluation assets
  Prior to the events that occurred in December, 2012 described below, there was a great deal of uncertainty regarding the future development of the North Africa asset. 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 12 (a).
  Due to this uncertainty, during the six month period ending June 30, 2012, the Company evaluated the fair value of the Joint Oil Block as described below.  The Company utilized a Swanson’s mean probability-weighted discount 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 12(a), each with substantial uncertainties, and the interdependency of factors, the Company was unable to identify the sensitivities associated with individual factors.  A number of the potential scenarios resulted in no value for the North African assets; however as of the date of the valuation management did not believe that they were the most probable outcomes and using the above described methodology and assumptions, the fair value of the North Africa assets was determined by the third party valuation firm to be $44.1 million less costs to sell of $0.4 million (which management determined was the most probable value in a range of possible values). This valuation resulted in the Company booking an impairment loss of $21.0 million during the six months ended June 30, 2012.
  On December 27, 2012, the Company entered into a farm-out agreement with Viking Energy North Africa Limited (“Viking”). The commercial terms of the farm-out agreement are discussed in Note 12 (b). The farm-out and the revised unit plan of development, which is subject to approval from Joint Oil, will, if approved, result in a new development plan that will change the method of development, the costs and the production profile. Based on that fact, the Company evaluated whether the impairment recorded on the Joint Oil Block should be reversed or if further impairment was necessary.
  The commercial terms of the farm-out agreement indicate that the recoverable amount for the North Africa E&E asset may exceed carrying value; however, management does not feel it is appropriate to reverse the previous impairment charges until the farm-out with Viking is approved by Joint Oil and the transaction formally closes. As such, the Company concluded that the methodology employed at June 30, 2012 was the Company’s best estimate of fair value. As at December 31, 2012, no indicators of impairment were identified in North Africa that, since June 30, 2012, would imply a further decline in the exploration and evaluation asset carrying value.
 
 2012 Annual Financial Statements|20
 
 5.
Exploration and evaluation assets and property, plant and equipment (continued)
  (c)   Property, plant and equipment
  An impairment test is performed on capitalized property and equipment costs at a cash-generating unit (“CGU”) level on an annual basis and quarterly when indicators of impairment exist. As per Note 4 (e), during the year ended December 31, 2012 the Company recorded an impairment of $16.2 million (December 31, 2011 – $34.3 million) on property, plant and equipment. This impairment was recorded in the CGUs as follows:
  (CDN$ millions)


December 31

2012

December 31

2011Southern Alberta CGU


4.6

20.1Central Alberta CGU


9.6

13.5Northern Alberta CGU


2.0

0.5British Columbia CGU


--

0.216.2

34.3
 
 6.
Property acquisition
 
 On September 23, 2011, the Company completed a property acquisition consisting of oil and gas assets located in the Drumheller region of Alberta. The consideration paid by Sonde was $6.2 million, consisting of cash.  The acquisition was comprised of $11.8 million of property, plant and equipment and $5.6 million in decommissioning provisions. The property acquisition was accounted for as a business combination using the acquisition method whereby the net assets acquired and the liabilities assumed are recorded at fair value.
 
 The Financial Statements incorporate the results of operations of the acquired properties from September 23, 2011 onward. For the year ended December 31, 2011, the Company recorded revenue from oil, natural gas and natural gas liquids of $0.4 million net of royalties and net income of $0.2 million on the acquired properties.  Had the acquisition occurred on January 1, 2011, for the year ended December 31, 2011, the Company estimates that its total unaudited pro-forma revenues and total unaudited net loss would have been approximately $37.5 million and $39.9 million, respectively.
  7.
Share based compensation
  (a)   Employee stock savings plan
  The Company has an employee stock savings plan (“ESSP”) in which employees are provided with the opportunity to receive a portion of their salary in common shares, which is then matched on a share for share basis by the Company. The Company purchased approximately 333,454 shares with a value of $0.5 million on the open market under the ESSP during the year ended December 31, 2012 (December 31, 2011 – 162,732 shares with a value of $0.6 million). The costs related to this plan are recorded as general and administrative expense as incurred.
  (b)   Stock option plan
  The Company has a stock option plan for its directors, officers and employees. The exercise price for stock options granted is the closing trading price on the Toronto Stock Exchange on the last trading day prior to the grant date.  Options issued prior to May 2011 vest over three years with a maximum term of ten years. Options issued after May 2011 generally vest over four years with a maximum term of five years. The Board of Directors can at its discretion alter the vesting terms at the date of the grant.
  2012 Annual Financial Statements|21
 7.
Share based compensation (continued)
  For the years ended

December 31, 2012

December 31, 2011Number

of options

Weighted average exercise price

Number

of options

Weighted average exercise price($ thousands, except per share price)Balance, beginning of year

2,974

$3.43

1,910

$5.78Granted

2,504

1.37

1,984

3.49Exercised

--

--

--

--Forfeited

(750)

3.03

(920)

8.43Balance, end of year

4,728

2.40

2,974

3.43
  The following table summarizes stock options outstanding under the plan at December 31, 2012:
  Options outstanding

Options exercisableExercise 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

2,360

4.47

1.31

218

1.072.51 – 3.00

568

3.41

2.85

280

2.863.01 – 4.00

1,008

7.62

3.10

998

3.094.01 – 11.80

792

7.81

4.43

697

4.460.88 – 11.80

4,728

5.58

2.40

2,193

3.29
 
 The fair value of options granted during the year was estimated based on the date of grant using a Black-Scholes option pricing model with weighted average assumptions and resulting values as follows:
  For the years ended

December 31, 2012

December 31, 2011Share price ($)

1.37

3.49Exercise price ($)

1.37

3.49Risk free rate (%)

1.2

2.0Expected life (years)

3.3

3.7Expected dividend yield (%)

--

--Expected volatility (%)

69.9

87.6Weighted average fair value of options granted ($)

0.69

2.13
 
 A forfeiture rate of 29.0% (December 31, 2011 – 27.6%) was used when recording stock based compensation. This estimate is based on the historical forfeiture rate adjusted to the actual forfeiture rate. Stock option expense for the year ended December 31, 2012 was $0.8 million (December 31, 2011 – $2.8 million). No stock based compensation expense was capitalized during 2012 or 2011.
  (c)   Stock unit awards
  At December 31, 2012, the Company had 1.2 million (December 31, 2011 – 1.5 million) stock unit awards outstanding, issued to the Company’s executive officers and members of the Board. A stock unit is the right to receive a cash amount equal to the fair market value of one common share of the Company on the applicable vesting date. The stock units have time and/or share based performance vesting terms which vary depending on whether the holder is an executive officer or director. As of December 31, 2012, the Company recorded a liability of $0.9 million to recognize the fair value of the vested stock units (December 31, 2011 - $2.0 million).
 2012 Annual Financial Statements|22
 7.
Share based compensation (continued)
  During the year ended December 31, 2012, the Company paid $1.1 million to settle awards held by current and former directors (December 31, 2011 - nil).  In addition, during the year ended December 31, 2012, an officer forfeited awards valued at $0.2 million (December 31, 2011 - nil).
  (d)   Restricted share units
  The Restricted Share Unit Plan became effective on March 24, 2011, to attract and retain experienced personnel with incentive compensation tied to shareholder return. Under the plan, each grantee will be entitled to, in respect of each Restricted Share Unit (“RSU”), a cash amount equal to the fair market value of one common share in the capital of the Company on such vesting date, with the vesting subject to a minimum floor share price and/or the lapse of time. During the year ended December 31, 2012, 66,666 RSUs were redeemed for a total of $0.1 million (December 31, 2011 – nil). The following table summarizes RSUs outstanding under the plan at December 31, 2012:
  Units outstanding

Units vestedFloor price ($)

Number of units (thousands)

Average remaining contractual life (years)

Weighted average floor price ($)

Number of units (thousands)

Weighted average floor price ($)0.00  – 3.00

229

0.92

2.56

127

2.223.01  – 3.50

28

0.34

3.10

14

3.093.51  – 3.64

9

1.03

3.64

4

3.640.00  – 3.64

266

0.86

2.66

145

2.33
  RSUs issued were initially valued at the grant date and revalued at December 31, 2012, using a binomial lattice model with weighted average assumptions as follows:
  Valuation at

December 31, 2012

Valuation at

grant dateShare price ($)

1.63

2.47Risk free rate (%)

1.0

1.0Expected life (years)

0.8

2.37Expected volatility (%)

70

60Weighted average fair value ($)

0.74

1.99
  The following table summarizes the share based compensation liability:
  December 31

2012

December 31

2011Stock unit award liability


909

1,955Restricted share unit liability


165

493Share based compensation liability


1,074

2,448
  The following table summarizes share based compensation expense:
  For the years ended December 31


2012

2011Stock option expense


762

2,810Stock unit award expense


71

1,425Restricted share unit expense


(177)

493656

4,728


2012 Annual Financial Statements|23




8.
Related party transactions




During the year ended December 31, 2012, in the normal course of business, the Company purchased $0.2 million of processing services (December 31, 2011 – $0.1 million) from a company with a common director. These services were purchased under normal industry terms and have been measured and disclosed at their settlement value. As of December 31, 2012 and December 31, 2011, there were no amounts outstanding in accounts payable to this service provider.




Sonde has determined that the key management personnel of the Company consist of its officers and directors.  In addition to the salaries and directors fees paid to the officers and directors respectively, the Company provides compensation to both groups through grants of Stock Unit Awards and under the RSU plan. Officers and directors also participate in the Company’s stock option plan. During the year ended December 31, 2012 this compensation totaled $3.0 million (2011 – $6.5 million) and was recorded in the Financial Statements as follows:




Year ended December 31
2012

2011General and administrative
2,734

1,864Share based compensation
231

4,6042,965

6,468





9.
Financial instruments




At December 31, 2012, cash and cash equivalents were comprised of $10.0 million in short term investment instruments and $9.7 million of cash held at financial institutions (December 31, 2011 – $3.7 million cash held at financial institutions).




Cash and cash equivalents are financial assets 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. Cash and equivalents are transacted in active markets.




Accounts receivable are classified as loans and receivables and are initially measured at their fair value.




Accounts payable and accrued liabilities, provisions, the liability component of the convertible preferred shares, demand loan and revolving credit facility are classified as other liabilities and are initially measured at fair value. Subsequently, they are recorded at their amortized cost using the effective interest method.




Stock unit awards, restricted share units, and derivatives, which include commodity contracts, warrants and the conversion feature on preferred shares, 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.




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. The following tables provide fair value measurement information for financial assets and liabilities as of December 31, 2012 and December 31, 2011.




Fair value measurements using:Carrying value

Fair value

Level 1

Level 2

Level 3(1)Financial liabilitiesCommodity contracts – as at December 31, 2012

--

--

--

--

--Commodity contracts – as at December 31, 2011(1)

781

781

--

781

--


(1)  The convertible preferred shares were redeemed on December 30, 2011 and the warrants expired on December 31, 2011.




The Company uses a fair value hierarchy, discussed in Note 3 (g), to categorize the inputs used to measure the fair value of its financial instruments.


2012 Annual Financial Statements|24
  10.
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 entered into a commodity swap contract from March to December 2011 on a portion of the Company’s natural gas production. In return for this fixed price the Company sold a call option on a portion of the Company’s oil production from March 2011 through December 2012.
 
 Year ended







December 31, 2012

December 31, 2011Term

Contract

Volume

Fixed Price

Realized gain (loss)

Unrealized gain (loss)

Realized gain (loss)

Unrealized gain (loss)March 1, 2011 – December 31, 2011

Swap

5,000(GJ/d)

$4.11($/GJ)

--

--

$1,093

--March 1, 2011 – December 31, 2012

Call

250(Bbls/d)

$100($US/bbl)

($92)

$781

($105)

($781)
 
 (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 December 31, 2012 or December 31, 2011. 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 repurchasing 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:
  December 31

2012

December 31

2011Share capital

369,892

369,892Contributed surplus

34,290

33,528Foreign currency translation reserve

(34)

550Deficit

(255,558)

(277,041)Total capital

148,590

126,929
 
 (d)   Foreign exchange risk
  The Company is exposed to foreign currency fluctuations as oil and gas prices received are referenced to U.S. dollar denominated prices. The Company’s foreign exchange risk denominated in U.S. dollars is as follows:
  2012 Annual Financial Statements|25
  10.
Risk Management (continued)
  December 31

December 312012

2011(US$ thousands)

Cash and cash equivalents

2,184

1,020North Africa receivables

1

111Foreign denominated financial assets

2,185

1,131North Africa payables

566

1,720Mariner swap provision

--

12,500Foreign denominated financial liabilities

566

14,220
  These balances are exposed to fluctuations in the Canadian and U.S. dollar exchange rate. At this time, the Company has chosen not to enter into any risk management agreements to mitigate foreign exchange risk. The Company’s exposure to foreign currency exchange risk, assuming reasonably possible changes in the U.S. dollar to Canadian dollar foreign currency exchange rate of +/- one cent is insignificant. This analysis assumes all other variables remain constant.
  (e)   Liquidity risk
  The Company generally relies on a combination of cash flow from operating activities, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for domestic and international operations.
 
 (f)    Credit risk
  The Company’s allowance for doubtful accounts is currently $1.7 million (December 31, 2011 – $2.0 million). This amount offsets $1.8 million in value added tax receivable from the Government of the Republic of Trinidad and Tobago (December 31, 2011 – $1.8 million) and nil of Western Canada joint interest and miscellaneous receivables (December 31, 2011 – $0.2 million).
  The Company considers all amounts greater than 90 days to be past due. As at December 31, 2012, $0.9 million of accounts receivable are past due, all of which are considered to be collectible (December 31, 2011 - $0.5 million).
  The Company’s credit risk exposure is as follows:
  December 31

December 312012

2011(CDN$ thousands)

Western Canada joint interest billings

2,310

2,830Goods and Services Tax receivable

--

740North Africa recoverable expenses

--

113Revenue accruals and other receivables

2,373

3,753Accounts receivable

4,683

7,436Cash and cash equivalents

19,695

3,743Maximum credit exposure

24,378

11,179


2012 Annual Financial Statements|26
  11.
Provisions
  (a)   Decommissioning provision
  The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the provision associated with the decommissioning of oil and natural gas assets:
  December 31

2012

December 31

2011(1)Decommissioning provision, beginning of year

26,344

18,197Liabilities incurred relating to acquisitions (note 6)

--

5,585Liabilities incurred relating to development activities

275

647Liabilities settled during the year

(180)

(204)Accretion expense

645

666Revision of estimates(2)

2,888

1,453Decommissioning provision, end of year

29,972

26,344(1)Amounts disclosed do not include Trinidad and Tobago discontinued operations, reclassified to liabilities of discontinued operations.

(2)Revision of estimates is due to changes in interest rates and changes in the future expected abandonment costs per well.December 31

2012

December 31

2011(1)Undiscounted cash flows

34,986

30,405Discount rate (%)

2.4

2.5Inflation rate (%)

1.5

1.5Weighted average expected timing of cash flows (years)

5.90

6.59
 (1)  Amounts disclosed do not include Trinidad and Tobago discontinued operations, reclassified to liabilities of discontinued operations.
  (b)   Other provisions
  December 31

2012

December 31

2011Mariner swap (note (12d))

--

12,713Onerous contracts

--

17Provisions

--

12,730
 
 12.
Contingencies and commitments
  (a)   North Africa Exploration and Production Sharing Agreement (“EPSA”)
  On August 27, 2008, the Company entered into an Exploration and Production Sharing Agreement (“EPSA”) with a Tunisian company, Joint Oil. Joint Oil is owned equally by the governments of Tunisia and Libya. The EPSA contract area straddles the offshore border between Tunisia and Libya. Under terms of the EPSA, the Company is the operator. Under the EPSA, the minimum work program for the first phase (four years) of the seven year exploration period includes the Zarat North – 1 appraisal well, three exploration wells and 500 square kilometres of 3D seismic.
  The EPSA provides for penalties for non-fulfillment of the minimum work program of US$15.0 million per exploration well, and the Company has provided a corporate guarantee to a maximum of US$45.0 million to secure its minimum work program obligations. The potential cost of drilling the three wells could exceed US$100.0 million.
  In January 2011, the Company announced the successful drilling and production testing of its 100% working interest in the Zarat North – 1 well. In December 2011, the Company commenced the acquisition of 513 square kilometres of 3D seismic in accordance with the requirements of the EPSA and completed the acquisition in January 2012.
  2012 Annual Financial Statements|27




12.
Contingencies and commitments (continued)




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




·
Inert and Acid Gas Initiative –On June 12, 2012, DGE (Tunisian Direction Generale de L’Energie) announced an initiative for the Gulf of Gabes operators offshore Tunisia to study options for sequestration of carbon dioxide and other inert and acid gases (which comprise a high percentage of all known oil and gas accumulations in the Gulf of Gabes, including the Joint Oil Block) to allow the currently stranded high inert content gas to be developed commercially and brought to the Tunisian market.




This initiative is focused on early development of the Sonde Zarat Discovery, which contains approximately 60% inert and acid gases. This initiative will ensure that the Zarat Plan of Development and other developments in the Gulf of Gabes are in accordance with Tunisian regulations and with agreements and commitments vis-à-vis international organizations like the Kyoto Accord on greenhouse gas emissions. This study is anticipated to take eighteen months.




·
Drilling Rig Availability –The initial results indicated that the global demand for offshore drilling units was higher in other parts of the world than North Africa. During the period ended September 30, 2012, one contractor submitted a bid for a technically acceptable jack up drilling rig that would have been available in the second quarter of 2013. The commercial terms of their offer were unacceptable to the Company. See note 12 (c).




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




·
Exploratory Well Obligations –The Company planned to discuss with Joint Oil the timing of the three well exploratory commitment due to lack of availability of a suitable drilling rig and pending resolution of the inert and acid gases sequestration issue. Neither the Company nor interested parties could find merit in an additional discovery of high inert and acid gases at this time without a clear commercialization path that includes a solution to this issue. As discussed in Note 12 (b), on December 24, 2012 the Company received an extension on its exploratory well obligations until December 23, 2015. See note 12 (c).







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


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


2012 Annual Financial Statements|28


12.
Contingencies and commitments (continued)




On December 27, 2012, the Company entered into a farm-out agreement with Viking Energy North Africa Limited (“Viking”) covering the Joint Oil Block. The farm-out agreement contains the following terms:




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




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




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




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




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




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




This pending farm out is subject to the following conditions:




·
Viking (or one of its affiliates) provides Sonde with a corporate guarantee sufficient to offset the current US$45.0 million guarantee for the potential penalties in respect of the three well drilling commitment and 3D seismic; and




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




Whether the transaction with Viking closes or not is uncertain. This uncertainty casts substantial doubt about the Company’s ability to continue as a going concern. The Company has submitted the farm-out to Joint Oil for approval. The Company and Viking have met with Joint Oil on numerous occasions and Joint Oil has raised a number of conditions to approval that the Company and Viking are attempting to resolve. While the Company believes the farm-out should be approved on its merits alone, no assurance can be made that Joint Oil will approve it or that the farm-out will close. The farm-out can be terminated after March 31, 2013 unless agreed by mutual consent to extend.




The public and private debt and equity markets remain inaccessible for exploratory or development projects on the Joint Oil Block and the Company’s Western Canadian operations will not provide sufficient cash flows to meet the exploratory commitments. Without access to the funding this transaction provides or third party funding, the Company may not be able to continue as a going concern.


(c)   Commitments and financial liabilities


The Company generally relies on a combination of cash flow from operating activities, credit facility availability and equity financings to fund its capital requirements and to provide liquidity for domestic and international operations. At December 31, 2012, the Company has committed to future payments over the next five years and thereafter, as follows:


2012 Annual Financial Statements|29
  12.
Contingencies and commitments (continued)
  2013

2014

2015

2016

Thereafter

TotalAccounts payable and accrued liabilities

6,850

--

--

--

--

6,850Share based compensation liability

1,074

--

--

--

--

1,074North Africa exploration commitments (note12 (a), (b) & (c))

16,514

14,924

14,924

--

--

46,362Office rent (note21)

1,212

1,212

1,217

1,233

7,159

12,03325,650

16,136

16,141

1,233

7,159

66,319
 
 (d)   Swap agreement
  At the time it entered into the North Africa EPSA, the Company also signed a swap agreement awarding an overriding royalty interest and optional participating interest to Joint Oil in the Company's Mariner Block, offshore Nova Scotia, Canada. No well was drilled on the Mariner Block and Joint Oil had the right to put back the overriding royalty to the Company for US$12.5 million. Joint Oil exercised its put rights and the Company made a payment of US$12.5 million on January 15, 2012.
 
 (e)   Litigation and claims
  The Company is involved in various claims and litigation arising in the ordinary course of business. In the opinion of the Company such claims and litigation are not expected to have a material effect on the Company’s financial position or its results of operations. The Company maintains insurance, which in the opinion of the Company, is sufficient to address any future claims as to matters insured.
  13.
Short term debt and financing costs
  (a)   Credit facilities
  As at December 31, 2012, the Company had issued three letters of credit for $0.2 million (December 31, 2011 – two letters of credit for $0.1 million) against the $30.0 million (December 31, 2011 - $40.0 million) demand revolving credit facility (“Credit Facility A”) at a variable interest rate of prime plus 0.75%.
  Credit Facility A is secured by a $100.0 million debenture with a floating charge on the assets of the Company and a general security agreement covering all the assets of the Company.
  Credit Facility A has covenants, as defined in the Company’s credit agreement, that require the Company to maintain an adjusted working capital ratio 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 December 31, 2012, the Company was in compliance with all of its debt covenants. The Company is subject to a semi-annual review of its credit facilities on or before May 1, 2013.
  Financing costs for the Company were as follows:
  For the years ended December 31


2012

2011Accretion of decommissioning provision(1)


645

666Interest on credit facilities(1)


285

731Interest on preferred shares


--

1,025930

2,422
 (1) Amounts disclosed do not include Trinidad and Tobago operations, which are classified as discontinued operations.
  (b)   Preferred shares
  On December 27, 2011, all conversion features associated with the Series B preferred shares expired without being exercised. On December 30, 2011, the Company redeemed the 150,000 outstanding Series B shares for $15.3 million. On December 31, 2011, the 500,000 outstanding common share purchase warrants expired. The expiries and redemption resulted in a 2011 gain on financial derivatives of $5.1 million.
  2012 Annual Financial Statements|30


14.
Revenue




The following summarizes the Company’s revenue:


For the years ended December 31


2012

2011Petroleum and natural gas sales


28,873

39,495Royalties


(3,286)

(4,489)25,587

35,006




15.
Operating expense




Operating costs for the Company are as follows:




For the years ended December 31


2012

2011Operating


14,209

13,473Well workovers


2,960

2,05417,169

15,527




16.
Share capital




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




The basic weighted average common shares outstanding was 62,301,446 for all periods. For the year ended December 31, 2012, the diluted weighted average common shares outstanding was 62,395,472 (December 31, 2011 – 62,301,446). The Company excluded 3.0 million options that are anti-dilutive for the year ended December 31, 2012 (December 31, 2011 – 1.7 million) in the calculation of diluted earnings per share.




17.
Supplemental cash flow information




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




For the years ended December 31


2012

2011Accounts receivable


2,753

(289)Prepaid expenses and deposits


483

349Accounts payable and accrued liabilities


(10,805)

(14,179)Provisions


(12,730)

38Foreign currency translation adjustment


248

63Change in non-cash working capital


(20,051)

(14,018)





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




For the years ended December 31


2012

2011Operating


2,776

(1,268)Financing


(196)

131Investing


(22,631)

(12,881)Change in non-cash working capital


(20,051)

(14,018)




18.
Discontinued operations




(a)   Trinidad and Tobago




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


2012 Annual Financial Statements|31




18.
Discontinued operations (continued)




The debenture accrued interest at 6.0% per annum and was secured against the Company’s Block 5(c) interests. Upon closing of the agreement, the US$20.0 million was applied against the proceeds of US$78.1 million. Upon closing of the agreement the Company was eligible to reclaim US$20.0 million ($19.3 million in Canadian dollars) held as restricted cash with BG International Limited (“BG”). On August 4, 2011, the Company received payment of the US$20.0 million.




Proceeds from disposition

(CDN$ thousands)Cash received

56,877Debenture retired

19,898MG Block performance guarantee assumed by purchaser

11,716Transaction costs

(583)Proceeds net of transaction costs

87,908Net assets disposed at carrying valueExploration and evaluation assets

79,664Decommissioning provisions

(3,040)Net assets

76,624Gain before understated

11,284Realized foreign currency translation reserve, reclassified from shareholders’ equity

(5,975)Net gain on disposition

5,309





(b)   LNG Project




On February 22, 2011, the Company completed the sale of its wholly owned subsidiary Liberty Natural Gas LLC which owned a 100% working interest in the LNG Project and received US$1.0 million for reimbursable costs incurred between January 1, 2011, and February 22, 2011. The Company is entitled to receive deferred cash consideration of US$12.5 million payable upon the project’s first successful gas delivery. No amounts have been recorded in the Financial Statements related to this contingent consideration.  At the time of the sale the LNG Project had a carrying value of nil and accumulated losses of $0.4 million in the foreign currency translation reserve, resulting in the realization of this loss in income from discontinued operations upon disposition.




(c)   Financial information from discontinued operations




Loss from discontinued operations reported in the 2011 consolidated statement of operations, comprehensive loss and deficit is as follows (2012 - nil):




For the year ended December 31, 2011

Trinidad and Tobago

LNG Project

Total(CDN$ thousands)ExpensesGeneral and administrative

(643)

(880)

(1,523)Finance costs

(493)

--

(493)Gain (loss) on disposition of foreign operations, net of realized foreign currency translation reserve

5,309

(389)

4,920Income (loss) from discontinued operations

4,173

(1,269)

2,904Foreign currency translation (loss) gain relating to assets and liabilities held for sale

(1,148)

20

(1,128)Reclassified from foreign currency translation reserve to net earnings

5,976

389

6,365Total comprehensive income (loss) from discontinued operations

9,001

(860)

8,141


2012 Annual Financial Statements|32
  19.
Segments and cash generating units
  The Company has identified two reporting segments based on geographical location, nature of operations, and regulatory regime applicable to oil and gas activities. The Company’s continuing operating and reportable segments are as follows:
  (a)   Western Canada
  This segment is comprised of the Company’s producing properties and undeveloped land located in Alberta, British Columbia, and Saskatchewan. All property, plant and equipment are included in this segment. Corporate assets, liabilities, revenues, and expenses are also included in this segment.
  (b)   North Africa
  This segment is comprised of the Company’s interest in the Joint Oil Block offshore North Africa. All costs incurred are directly attributable costs associated with the exploration and evaluation of this block and have been capitalized as exploration and evaluation assets. Working capital associated with the Block is included in this segment.
  The Company has five cash-generating units (“CGUs”), including the North Africa CGU, which is classified as exploration and evaluation assets. The four remaining CGUs are included in the Western Canada reportable segment and include Northern Alberta, Central Alberta, Southern Alberta and British Columbia.
  The CGUs have been chosen primarily based on their geographical location, similar reservoir characteristics, similar development plans, shared infrastructure, discrete processing and gathering facilities, regulatory regimes (e.g. Alberta vs. British Columbia) and management’s basis for internal reporting and monitoring.
  The statements of operations for the years ended December 31, 2012 and December 31, 2011 by operating segment are as follows:
 
 For the years ended December 31

Western

Canada

North

Africa

Total

2012

Western

Canada

North

Africa

Total

2011RevenueRevenue, net of royalties

25,587

--

25,587

35,006

--

35,006Gain on commodity derivatives

689

--

689

207

--

20726,276

--

26,276

35,213

--

35,213ExpensesOperating

17,169

--

17,169

15,527

--

15,527Transportation

599

--

599

1,042

--

1,042Exploration and evaluation

1,748

20,987

22,735

1,270

--

1,270General and administrative

8,505

--

8,505

9,124

--

9,124Depletion and depreciation

11,031

--

11,031

14,906

--

14,906Share based compensation

656

--

656

4,728

--

4,728Property, plant and equipment impairment

16,241

--

16,241

34,270

--

34,270Loss on settlement of decommissioning liabilities

199

--

199

1,027

--

1,02756,148

20,987

77,135

81,894

--

81,894Operating loss

(29,872)

(20,987)

(50,859)

(46,681)

--

(46,681)OtherFinancing costs

(930)

--

(930)

(2,422)

--

(2,422)Loss on foreign exchange

(466)

--

(466)

(183)

--

(183)Gain on financial derivatives

--

--

--

5,129

--

5,129Other income

192

--

192

428

--

428Gain on disposition of exploration and evaluation assets

73,581

--

73,581

390

--

39072,377

--

72,377

3,342

--

3,342Income (loss) from continuing operations before income taxes

42,505

(20,987)

21,518

(43,339)

--

(43,339)Current income taxes

35

--

35

136

--

136Income (loss) from continuing operations

42,470

(20,897)

21,483

(43,475)

--

(43,475)




2012 Annual Financial Statements|33




19.
Segments and cash generating units (continued)






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




Western

Canada

North

Africa

Total – As at

Dec. 31, 2012

Western

Canada

North

Africa

Total – As at

Dec. 31, 2011(CDN$ thousands)AssetsCurrentCash and cash equivalents

18,024

1,671

19,695

3,012

731

3,743Accounts receivable

4,682

1

4,683

7,323

113

7,436Prepaid expenses and deposits

714

19

733

1,488

40

1,52823,420

1,691

25,111

11,823

884

12,707Long term portion of prepaid expenses and deposits

732

--

732

420

--

420Exploration and evaluation assets

11,799

44,700

56,499

8,907

60,108

69,015Property, plant and equipment

104,144

--

104,144

104,745

--

104,745Total assets

140,095

46,391

186,486

125,895

60,992

186,887LiabilitiesCurrentAccounts payable and accrued liabilities

6,288

562

6,850

15,906

1,749

17,655Share based compensation liability

1,074

--

1,074

2,448

--

2,448Provisions

--

--

--

17

12,713

12,730Derivative financial liabilities

--

--

--

781

--

7817,362

562

7,924

19,152

14,462

33,614Decommissioning provision

29,972

--

29,972

26,344

--

26,344Total liabilities

37,334

562

37,896

45,496

14,462

59,958







20.
Income taxes




2012

2011Income (loss) from continuing operations before income taxes

21,518

(43,339)Combined federal and provincial income tax rate

25.0%

26.5%Computed income tax expense (recovery)

5,380

(11,485)Effect on income tax of:Effect of change in corporate tax rate

--

641Tax pool amendments

--

5,015Other non-deductible items

168

154Losses and deferred tax assets not recognized for tax

(5,548)

5,675Part VI.I tax on preferred shares

35

136Current income taxes

35

136





Current income taxes comprise $0.1 million of Part VI.I tax on preferred shares (2011 – $0.1 million). During the years ended December 31, 2012 and 2011 no deferred tax expenses were recognized in net loss, other comprehensive income (loss) or equity.


2012 Annual Financial Statements|34




20.
Income taxes (continued)




The Company has not recorded deferred income tax assets (liabilities) in respect of the following deductible temporary differences and unused tax losses:


2012

2011Property, plant and equipment


(4,628)

43,568Deductible stock unit awards


1,074

2,448Provisions


--

12,730Derivative financial liabilities


--

781Decommissioning provision


29,972

26,344Unrecognized non-capital losses


137,414

98,090Capital losses


30,094

30,234Cumulative Eligible Capital, deductible share issue costs and other


1,767

3,726195,693

217,921




The unrecognized non-capital losses expire in the years 2026 – 2032. There is no expiry on the capital losses and other temporary differences. The following is a summary of the Company’s tax pools:




2012

2011Canadian exploration expense


56,802

57,861Canadian oil and gas property expense


--

49,230Canadian development expense


21,791

45,579Undepreciated capital costs


29,041

29,945Foreign exploration expense


4,354

34,163Non-capital losses


137,414

98,429Capital losses


30,094

30,234Share issue costs and other


1,767

3,726281,263

349,167





21.
Subsequent events




Subsequent to the year ended December 31, 2012, the Company entered into an office sublease with a third party. The sublease is intended to reduce the future obligations of the Company. The terms of the arrangement dictate that the Company will retain half of its office space until 2015, at which time the entire lease will become the responsibility of the third party. The sublease reduces the future obligations of the company by $9.2 million from 2015 onward.




2012 Annual Financial Statements|34