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EX-10.1 - EXHIBIT 10.1 - IVANHOE ENERGY INCc16291exv10w1.htm
EX-32.2 - EXHIBIT 32.2 - IVANHOE ENERGY INCc16291exv32w2.htm
EX-32.1 - EXHIBIT 32.1 - IVANHOE ENERGY INCc16291exv32w1.htm
EX-31.1 - EXHIBIT 31.1 - IVANHOE ENERGY INCc16291exv31w1.htm
EX-10.2 - EXHIBIT 10.2 - IVANHOE ENERGY INCc16291exv10w2.htm
EX-31.2 - EXHIBIT 31.2 - IVANHOE ENERGY INCc16291exv31w2.htm
Table of Contents

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
Form 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2011
Commission file number: 000-30586
 
(IVANHOE ENERGY INC LOGO)
Ivanhoe Energy Inc.
(Exact name of registrant as specified in its charter)
     
Yukon, Canada   98-0372413
(State or other jurisdiction of   (IRS Employer
incorporation or organization)   Identification No.)
654-999 Canada Place
Vancouver, BC, Canada V6C 3E1
(604) 688-8323

(Address and telephone number of the registrant’s principal executive offices)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer o   Accelerated filer þ   Non-accelerated filer o   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ No
As at April 29, 2011, Ivanhoe Energy Inc. had 343,970,158 Common Shares outstanding with no par value.
 
 

 

 


 

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 Exhibit 10.1
 Exhibit 10.2
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2

 

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PART I FINANCIAL INFORMATION
ITEM 1.  
FINANCIAL STATEMENTS
IVANHOE ENERGY INC.
Condensed Consolidated Statements of Financial Position
(Unaudited)
                             
        March 31,     December 31,     January 1,  
(US$000s)   Notes   2011     2010     2010  
 
                           
Assets
                           
Current Assets
                           
Cash and cash equivalents
  5     80,798       68,317       24,362  
Accounts receivable
        6,508       6,359       5,021  
Note receivable
        234       264       225  
Prepaid and other
        2,061       2,859       771  
 
                     
 
        89,601       77,799       30,379  
 
                           
Intangible
  6     284,149       273,568       207,750  
Property, plant and equipment
  7     42,731       40,618       41,983  
Long term receivables
        2,584       2,433       839  
 
                     
 
        419,065       394,418       280,951  
 
                     
 
                           
Liabilities and Shareholders’ Equity
                           
Current Liabilities
                           
Accounts payable and accrued liabilities
        24,702       21,482       10,779  
Debt
  8     40,985       39,832        
Derivative financial instruments
  9, 10     4,211       8,447       13,023  
Income taxes
        351             530  
Decommissioning costs
  11                 753  
 
                     
 
        70,249       69,761       25,085  
 
                           
Long term debt
  8                 36,934  
Long term provisions
  11     3,031       3,008       2,187  
Deferred income taxes
        21,730       21,165       22,336  
 
                     
 
        95,010       93,934       86,542  
 
                     
 
                           
Shareholders’ Equity
                           
Share capital
  13     585,664       550,562       422,322  
Contributed surplus
  14     22,736       23,141       18,724  
Accumulated deficit
        (284,345 )     (273,219 )     (246,637 )
 
                     
 
        324,055       300,484       194,409  
 
                     
 
        419,065       394,418       280,951  
 
                     
 
                           
Nature of operations and going concern
  1                        
(See accompanying Notes to the Unaudited Condensed Consolidated Financial Statements)

 

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IVANHOE ENERGY INC.
Condensed Consolidated Statements of Loss and Comprehensive Loss
(Unaudited)
                     
        Three Months Ended March 31,  
(US$000s, except share and per share amounts)   Note   2011     2010  
 
                   
Revenue
                   
Oil
        8,119       5,330  
Interest
        67       19  
 
               
 
        8,186       5,349  
 
               
 
                   
Expenses
                   
Operating
  18     4,523       3,454  
Exploration and evaluation
  6           606  
General and administrative
        13,417       8,432  
Depletion and depreciation
  7     1,831       1,537  
Foreign currency exchange gain
        (225 )     (4,187 )
Derivative instruments (gain) loss
  9, 10     (1,129 )     2,057  
Interest
        8       4  
 
               
 
        18,425       11,903  
 
               
 
                   
Loss before income taxes
        (10,239 )     (6,554 )
 
                   
Provision for income taxes
                   
Current
        (322 )     (79 )
Deferred
        (565 )     (172 )
 
               
 
        (887 )     (251 )
 
               
 
                   
Net loss and comprehensive loss
        (11,126 )     (6,805 )
 
               
 
                   
Net loss per common share, basic and diluted
        (0.03 )     (0.02 )
 
               
 
                   
Weighted average number of common shares
                   
Basic and diluted (000s)
        338,403       307,233  
 
               
(See accompanying Notes to the Unaudited Condensed Consolidated Financial Statements)

 

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IVANHOE ENERGY INC.
Condensed Consolidated Statements of Changes in Equity
(Unaudited)
                                             
        Share Capital                    
        Shares             Contributed     Accumulated        
(US$000s, except share amounts)   Note   (000s)     Amount     Surplus     Deficit     Total  
 
                                           
Balance January 1, 2010
        282,559       422,322       18,724       (246,637 )     194,409  
Net loss and comprehensive loss
                          (6,805 )     (6,805 )
Shares issued for cash, net of share issue costs
        50,000       122,322                   122,322  
Shares issued for services
        280       799                   799  
Exercise of stock options
  14     912       3,518       (1,887 )           1,631  
Exercise of purchase warrants
        2       9                   9  
Share-based compensation expense
  14                 1,223             1,223  
 
                                 
Balance March 31, 2010
        333,753       548,970       18,060       (253,442 )     313,588  
 
                                 
                                             
        Share Capital                    
        Shares             Contributed     Accumulated        
(US$000s, except share amounts)   Note   (000s)     Amount     Surplus     Deficit     Total  
 
                                           
Balance January 1, 2011
        334,365       550,562       23,141       (273,219 )     300,484  
Net loss and comprehensive loss
                          (11,126 )     (11,126 )
Exercise of stock options
  14     947       4,055       (2,181 )           1,874  
Exercise of purchase warrants
        8,621       31,047                   31,047  
Share-based compensation expense
  14                 1,776             1,776  
 
                                 
Balance March 31, 2011
        343,933       585,664       22,736       (284,345 )     324,055  
 
                                 
(See accompanying Notes to the Unaudited Condensed Consolidated Financial Statements)

 

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IVANHOE ENERGY INC.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
                     
        Three Months Ended March 31,  
(US$000s)   Note   2011     2010  
 
                   
Operating Activities
                   
Net loss
        (11,126 )     (6,805 )
Items not requiring use of cash
                   
Depletion and depreciation
  7     1,831       1,537  
Share-based compensation expense
  14     1,776       1,223  
Unrealized (gain) loss on derivative instruments
  9, 10     (1,129 )     2,057  
Unrealized foreign currency exchange gain
        (227 )     (4,373 )
Deferred income tax expense
        565       172  
Exploration and evaluation expense
  6           606  
Other
        6       192  
Decommissioning costs settled
              (58 )
Changes in non-cash working capital items
  19     1,796       18  
 
               
Net cash used in operating activities
        (6,508 )     (5,431 )
 
               
 
                   
Investing Activities
                   
Intangible expenditures
        (10,364 )     (23,082 )
Property, plant and equipment expenditures
        (3,949 )     (818 )
Long term receivables
        (147 )     (348 )
Changes in non-cash working capital items
  19     2,475       880  
 
               
Net cash used in investing activities
        (11,985 )     (23,368 )
 
               
 
                   
Financing Activities
                   
Shares and warrants issued on private placements, net of share issue costs
              136,321  
Proceeds from exercise of options and warrants
  10, 14     29,814       1,636  
Changes in non-cash working capital items
  19     (19 )      
 
               
Net cash provided by financing activities
        29,795       137,957  
 
               
 
                   
Foreign exchange gain on cash and cash equivalents held in a foreign currency
        1,179       5,715  
 
               
Increase in cash and cash equivalents, for the period
        12,481       114,873  
Cash and cash equivalents, beginning of period
        68,317       24,362  
 
               
Cash and cash equivalents, end of period
        80,798       139,235  
 
               
(See accompanying Notes to the Unaudited Condensed Consolidated Financial Statements)

 

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IVANHOE ENERGY INC.
Notes to the Unaudited Condensed Consolidated Financial Statements
(tabular amounts in US$000s, except share and per share amounts)
1. NATURE OF OPERATIONS AND GOING CONCERN
Ivanhoe Energy Inc. (the “Company” or “Ivanhoe”) is a publicly listed company incorporated in Canada, with limited liability under the legislation of the Yukon. Ivanhoe’s common shares are listed on the Toronto Stock Exchange (“TSX”) and the NASDAQ Stock Market (“NASDAQ”). The head office, principal address and registered and records office of the Company are located at 999 Canada Place, Suite 654, Vancouver, British Columbia, V6C 3E1.
Ivanhoe is an independent international heavy oil development and production company focused on pursuing long term growth in its reserves and production. Ivanhoe plans to utilize advanced technologies, such as its HTLTM technology, that are designed to significantly improve recovery of heavy oil resources. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production of oil and gas.
The March 31, 2011 unaudited condensed consolidated interim financial statements (“Financial Statements”) have been prepared using International Financial Reporting Standards (“IFRS”) applicable to a going concern, which contemplates the realization of assets and settlement of liabilities in the normal course of business as they become due and assumes that Ivanhoe will be able to meet its obligations and continue operations for at least its next fiscal year. Realization values may be substantially different from carrying values as shown and these Financial Statements do not give effect to adjustments that may be necessary to the carrying values and classification of assets and liabilities should the Company be unable to continue as a going concern. Such adjustments could be material.
At March 31, 2011, Ivanhoe had an accumulated deficit of $284.3 million and working capital of $23.6 million excluding derivative financial liabilities. In the first three months of 2011, cash used in operating activities was $6.5 million and the Company expects to incur further losses in the development of its business. Continuing as a going concern is dependent upon attaining future profitable operations to repay liabilities arising in the normal course of operations and accessing additional capital to develop the Company’s properties. Ivanhoe intends to finance its future funding requirements through a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level. There is no assurance that Ivanhoe will be able to obtain such financing on favorable terms, if at all. Without access to additional financing or other cash generating activities in 2012, there is significant doubt that the Company will be able to continue as a going concern.
The March 31, 2011 Financial Statements were approved by the Board of Directors and authorized for issue on April 28, 2011.
The Financial Statements are presented in US dollars and all values are rounded to the nearest thousand dollars except where otherwise indicated.
2. BASIS OF PRESENTATION
2.1 Statement of Compliance
The Financial Statements have been prepared in accordance with IAS 34, “Interim Financial Reporting” (“IAS 34”), using accounting policies consistent with IFRS as issued by the International Accounting Standards Board (“IASB”) that the Company expects to adopt in its consolidated financial statements for the year ending December 31, 2011. The Financial Statements are not subject to qualification relating to the application of IFRS as issued by the IASB.
As these are the Company’s first set of Financial Statements in accordance with IFRS, the Company’s disclosures exceed the minimum requirements under IAS 34. The Company elected to exceed the minimum requirements in order to present the Company’s accounting policies in accordance with IFRS and the additional disclosures required under IFRS, which also highlight the changes from the Company’s 2010 annual consolidated financial statements prepared in accordance with Canadian generally accepted accounting principles (“GAAP”).
2.2 Basis of Presentation
The Company adopted IFRS on January 1, 2011, with a transition date of January 1, 2010. Comparative financial information has been restated to comply with IFRS as detailed in Note 23.
The Financial Statements have been prepared on an historical cost basis, except financial instruments, which are measured at fair value as explained in accounting policies set out in Note 3.

 

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3. SIGNIFICANT ACCOUNTING POLICIES
3.1 Basis of Consolidation
The Financial Statements incorporate the financial statements of the Company, its subsidiaries, all of which are wholly owned, and special purpose entities that are controlled by the Company. All intercompany balances, transactions, income and expenses are eliminated on consolidation. The consolidated accounts are prepared using uniform accounting policies.
Certain of the Company’s exploration and development activities are conducted jointly with others. The Financial Statements reflect only the Company’s proportionate interest in such activities.
3.2 Foreign Currency Translation
The Company’s reporting currency and the functional currency of its operations is the US dollar, as this is the principal currency of the economic environments in which it operates.
Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate in effect on the date of the statement of financial position. Non-monetary assets and liabilities, as well as operating transactions, are translated at the exchange rate prevailing at the time of the transaction. Translation gains and losses are reflected in earnings.
3.3 Cash and Cash Equivalents
Cash and cash equivalents includes cash on hand, deposits at banks, short term highly liquid investments with original maturities of three months or less and restricted cash balances that are of a short term nature.
3.4 Intangible Assets
i. Technology Assets
The Company’s HTLTM technology license (“Technology Assets”) is measured at cost and classified as an intangible asset. Amortization of the Technology Assets will commence when the technology is available for use in field operations.
ii. Exploration and Evaluation Assets
Costs of exploring for, and evaluating, oil and gas properties are initially capitalized as intangible exploration and evaluation assets (“E&E assets”). Costs may include license fees, technical studies, seismic programs, exploratory drilling and directly attributable general and administrative costs.
If E&E assets result in sufficient proved reserves to justify commercial production and technical feasibility can be established, the assets will be tested for impairment and reclassified as property, plant and equipment. If E&E assets result in sufficient reserves to justify commercial production, but those reserves cannot be classified as proved, the assets will be tested for impairment and continue to be capitalized as intangible assets as long as progress is being made to assess the reserves and economic viability of the well and/or related project. If sufficient reserves cannot be established, the corresponding E&E assets are charged to exploration and evaluation expense (“E&E expense”).
E&E assets which may be attributable to a broad exploration area, such as license fees, technical studies or seismic programs, will be reclassified to PP&E or charged to E&E expense to best reflect the nature of the assets. Costs incurred prior to establishing the legal right to explore an area are charged to E&E expense as incurred.

 

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3.5 Property, Plant and Equipment
i. Oil and Gas Property and Equipment
Property, plant and equipment (“PP&E”) are reported at cost less accumulated depletion, depreciation and accumulated impairment losses. PP&E includes the purchase price, reclassified E&E assets, any costs directly attributable to bringing the asset to the location and condition necessary for its intended use and decommissioning costs. Interest on borrowings incurred to finance qualifying PP&E is capitalized until the asset is capable of fulfilling its intended use.
PP&E is depleted using the unit-of-production method based on proved plus probable reserves, taking into account associated future development costs. For purposes of these calculations, production and reserves of natural gas are converted to barrels on an energy equivalent basis at a ratio of six thousand cubic feet of natural gas for one barrel of oil. Depletion rates are updated annually unless there is a material change in circumstances, in which case they would be updated more frequently.
ii. Other Assets
Furniture and equipment are depreciated on a straight-line basis over the estimated useful life of the respective assets, at rates ranging from three to five years. The Feedstock Testing Facility (“FTF”) is depreciated over its expected economic life of 20 years.
3.6 Impairment
The Company periodically assesses tangible and intangible assets or groups of assets for impairment whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. Individual assets are grouped into cash generating units for impairment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
If indicators of impairment exist, the recoverable amount of the asset group is estimated. An asset group’s recoverable amount is the higher of its fair value less costs to sell and its value in use. 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. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount.
Previously recognized impairment losses are reversed if there has been a change in the estimates used to determine the asset group’s recoverable amount. If that is the case, the carrying amount of the asset group is increased to its revised recoverable amount which cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized in prior periods. Such a reversal is recognized in earnings. Subsequent to a reversal of impairment, the depletion or depreciation expense is adjusted in future periods to allocate the asset group’s revised carrying amount, less any residual value, over its remaining useful life.
3.7 Decommissioning Provision
The Company recognizes a provision for decommissioning costs when it has an obligation to dismantle and remove its PP&E or restore the site on which it is located. The provision is estimated as the present value of the expected future expenditures, determined in accordance with local conditions and requirements, discounted at a risk free rate. A corresponding amount is added to the carrying value of the related asset and is amortized as an expense over the economic life of the asset. The carrying amount of the provision is increased for the passage of time and adjusted for changes to the current market-based discount rate, amount and/or timing of the underlying cash flows needed to settle the obligation. Actual decommissioning costs incurred reduce the obligation. Any difference between the recorded decommissioning provision and the actual costs incurred is recorded as a gain or loss in the settlement period.
3.8 Provisions and Contingencies
Provisions are recognized when the Company has a present obligation (legal or constructive) that has arisen as a result of a past event and it is probable that a future outflow of resources will be required to settle the obligation, provided that a reliable estimate can be made of the amount of the obligation.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. When it is appropriate to discount a provision, the increase in the provision due to passage of time is recognized as interest expense.

 

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3.9 Financial Assets
Financial assets are classified as i) loans and receivables, ii) available-for-sale, iii) financial assets at fair value through profit or loss or iv) as held-to-maturity. Ivanhoe determines the classification of its financial assets at initial recognition. Financial assets are recognized initially at fair value and subsequent measurement depends upon their classification.
i. Loans and Receivables
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are carried at amortized cost using the effective interest rate method if the time value of money is significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process. The Company’s cash and cash equivalents, accounts receivable, note receivable and long term receivables are classified as loans and receivables.
ii. Available-for-Sale
Available-for-sale financial assets are non-derivative financial assets that are not classified as loans and receivables. After initial recognition, available-for-sale financial assets are measured at fair value, with gains or losses recognized within other comprehensive income. Accumulated changes in fair value are recorded as a separate component of equity until the investment is derecognized or impaired. The Company does not currently have any financial assets classified as available-for-sale.
iii. Financial Assets at Fair Value through Profit or Loss
Financial assets are classified as fair value through profit or loss (“FVTPL”) when the financial asset is held for trading or it is designated as FVTPL. Financial assets classified as FVTPL are measured at fair value with unrealized gains and losses recognized through earnings. The Company does not currently have any financial assets classified at fair value through earnings.
iv. Held-to-Maturity
Investments are recognized on a trade date basis and are initially measured at fair value, including transaction costs. The Company does not currently have any financial assets classified as held-to-maturity.
v. Impairment
Financial assets, other than those at FVTPL, are assessed for indicators of impairment at each period end. Financial assets are impaired when there is evidence that the estimated future cash flows of the investment have been impacted. For financial assets carried at amortized cost, the amount of the impairment is the difference between the asset’s carrying amount and the present value of the estimated future cash flows, discounted at the financial asset’s original effective interest rate.
The carrying amount of all financial assets, excluding accounts receivables, is directly reduced by the impairment loss. The carrying amount of accounts receivable is reduced through the use of an allowance account. Subsequent recoveries of amounts previously written off are recorded against the allowance account. Changes in the carrying amount of the allowance account are recognized in the results of operations.
With the exception of available-for-sale equity instruments, which are revalued through other comprehensive income, if, in a subsequent period, the amount of the impairment loss decreases and the decrease relates to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed through the earnings. On the date of impairment reversal, the carrying amount of the financial asset cannot exceed its amortized cost had impairment not been recognized.

 

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vi. Derecognition
Financial assets are derecognized when the rights to receive cash flows from the investments have expired or have been transferred and the Company has transferred substantially all risks and rewards of ownership.
3.10 Financial Liabilities
Financial liabilities are classified as i) financial liabilities at FVTPL or ii) as other financial liabilities measured at amortized cost. Ivanhoe determines the classification of its financial liabilities at initial recognition. The measurement of financial liabilities depends on their classification.
i. Financial Liabilities at Fair Value through Profit or Loss
Financial liabilities classified as FVTPL include financial liabilities held for trading and financial liabilities designated upon initial recognition as FVTPL. Derivatives, including separated embedded derivatives, are also classified as FVTPL. Fair value changes on financial liabilities classified as FVTPL are recognized through earnings. The Company’s derivative financial instruments are classified as financial liabilities at FVTPL.
ii. Other Financial Liabilities
Financial liabilities classified as other financial liabilities are initially recognized at fair value less directly attributable transaction costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest rate method. The Company’s accounts payable and accrued liabilities, debt and long term obligation are classified as other financial liabilities.
3.11 Oil and Gas Revenue
Sales of oil and gas are recognized when the risks and rewards of ownership pass to the buyer, collection is reasonably assured and the price is reasonably determinable. Oil and gas revenue represents the Company’s share and is recorded net of royalty payments to governments and other mineral interest owners.
3.12 Income Tax
Income tax expense represents the sum of tax currently payable and deferred tax.
i. Current income tax
Income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid to, the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the date of the statement of financial position.
ii. Deferred income tax
Deferred income tax is provided, using the liability method, on temporary differences at the date of the statement of financial position between the tax basis of assets and liabilities and their carrying amounts for financial reporting purposes.
Deferred income tax liabilities are recognized for all taxable temporary differences, except:
   
where the deferred income tax liability arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss; and
   
in respect of taxable temporary differences associated with investments in subsidiaries, associates and interests in joint ventures, where the timing of the reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future.

 

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Deferred tax assets are recognized for all deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilized except:
   
where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; and
   
in respect of deductible temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized.
The carrying amount of deferred tax assets is reviewed at each date of the statement of financial position and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized. Unrecognized deferred income tax assets are reassessed at each date of the statement of financial position and are recognized to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is expected to be realized or the liability is expected to be settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the date of the statement of financial position.
Deferred income tax relating to items recognized directly in equity is recognized in equity and not in earnings.
Deferred income tax assets and deferred income tax liabilities are offset if, and only if, a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities which intend to either settle current tax liabilities and assets on a net basis, or to realize the assets and settle the liabilities simultaneously, in each future period in which significant amounts of deferred tax assets or liabilities are expected to be settled or recovered.
3.13 Borrowing Costs
For qualifying assets, interest on borrowings incurred to finance E&E assets and PP&E is capitalized until the asset is capable of fulfilling its intended use. Capitalized borrowing costs cannot exceed the actual interest and financing costs incurred. All other interest and financing costs are recognized in earnings in the period in which they are incurred.
3.14 Share-Based Payments
Equity settled share-based payments in the form of stock options granted to directors, employees and those providing similar services to Ivanhoe and its subsidiaries are measured at fair value on the grant date and expensed on a graded basis over the vesting period of each annual installment. The cumulative expense for equity settled transactions incorporates a forfeiture rate to reflect the Company’s best estimate of the number of equity instruments that will ultimately vest.
No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition which are treated as vesting irrespective of whether or not the market condition is satisfied provided that all other performance and/or service conditions are satisfied.
Compensation expenses are recognized at fair value determined at the grant date when shares are issued from the stock bonus plan. The employee share purchase portion of the plan has not yet been activated.

 

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3.15 Income or Loss per Common Share
Basic net income or loss per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per common share amounts are calculated based on net income divided by dilutive common shares. Dilutive common shares are arrived at by adding weighted average common shares to common shares issuable on conversion of options or purchase warrants assuming that proceeds received from the exercise of in-the-money stock options and purchase warrants are used to purchase common shares at the average market price. Dilution from the Company’s convertible debt is considered using the “if converted” method.
3.16 Standards and Interpretations Issued But Not Yet Adopted
i. IFRS 9 Financial Instruments
As part of the IASB’s project to replace IAS 39 “Financial Instruments: Recognition and Measurement” in November 2009, the IASB issued the first phase of IFRS 9 “Financial Instruments” dealing with the classification and measurement of financial assets. In October 2010, the IASB updated IFRS 9 by incorporating requirements for the accounting for financial liabilities. The new standard is effective for annual periods beginning on or after January 1, 2013, with transitional arrangements depending upon the date of initial application. Ivanhoe has not yet decided the date of initial application for the Company and has not yet completed its evaluation of the effect of adoption.
There are no other standards or interpretations in issue but not yet adopted that are anticipated to have a material effect on the reported income or net assets of the Company.
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINITY
The preparation of financial statements in accordance with IFRS requires management to make estimates and assumptions in certain circumstances that affect reported amounts. The most sensitive estimates affecting the Financial Statements are in the areas set out below. Actual results may differ from these estimates.
4.1 Critical Judgments in Applying Accounting Policies
i. E&E Assets
E&E assets are initially capitalized as intangible assets and reclassified as PP&E when sufficient reserves to justify commercial production are established. E&E assets that result in sufficient reserves to justify commercial production, but which cannot be classified as proved, continue to be capitalized as intangible assets as long as progress is being made to assess the reserves and economic viability of the well and/or related project. If sufficient reserves cannot be established, the corresponding E&E assets are charged to E&E expense.
Management must determine if E&E assets, which have not yet resulted in the discovery of proved reserves, should continue to be capitalized or charged to E&E expense. When making this determination, management considers factors such as the Company’s drilling results, planned exploration and development activities, the financial capacity of the Company to further develop the property, the ability to use the Company’s HTL™ technology in certain projects, lease expiries, market conditions and technical recommendations from its exploration staff.
ii. Impairment
a. Property, Plant and Equipment
Ivanhoe annually evaluates its oil and gas assets or groups of assets for impairment or whenever events or changes in circumstances indicate the carrying value may not be recoverable. Among other things, an impairment may be triggered by falling oil and gas prices, a significant negative revision to reserve estimates, the inability to use the Company’s HTL™ technology in certain projects, changes in capital costs or the inability to raise sufficient financial resources to further develop the property. Cash flow estimates for the Company’s impairment assessments require significant assumptions about future prices and costs, production, reserves, discount rates and potential benefits from the application of its HTL™ technology.

 

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b. Technology Assets
The Company’s Technology Assets consist of an exclusive, irrevocable license to deploy its HTL™ technology. Ivanhoe annually reviews the Technology Assets for impairment or if an adverse event or change occurs. Indicators of adverse events could include HTL™ patent expiries, advancements of new technologies or the inability to successfully commercialize the HTL™ technology. The impairment of the Technology Assets requires management to make assumptions about competitive technological developments, the successful commercialization of the Company’s HTL™ technology and future cash flows from the HTL™ technology.
4.2 Key Sources of Estimation Uncertainty
i. Oil and Gas Reserves
The process of estimating quantities of reserves is inherently uncertain and complex. It requires significant judgment and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production becomes available and as economic conditions impacting oil and gas prices and costs change. Such revisions could be upwards or downwards. Reserve estimates have a material impact on depletion and the Company’s impairment evaluations, which in turn have a material impact on earnings.
Total proved and probable reserves estimates are used to determine rates that are used in the unit-of-production depletion calculations. In the first three months of 2011, depletion expense of $1.6 million was recorded. If proved and probable reserves estimates changed by 10%, the Company’s depletion and depreciation expense would have changed by approximately $0.2 million, assuming all other variables remained constant.
The recoverable value of the Company’s oil and gas PP&E is calculated based on future net cash flows from proved plus probable reserves, discounted at a pre-tax rate that includes risks specific to the asset. A 1% increase in the discount rate and a 5% decrease in the forward pricing used in the calculation of cash flows from proved plus probable reserves as at March 31, 2011, would not impair the Company’s development projects.
ii. HTL™ Technology
Future cash flows from HTL™ technology is a key source of estimation uncertainty as it requires management to make assumptions about the successful commercialization of the HTL™ technology and competitive technological developments. Success in commercializing the HTL™ technology in the oil and gas industry depends on the Company’s ability to economically design, construct and operate commercial-scale plants and a variety of other factors. Ivanhoe expects that technological advances in the processes and procedures for upgrading heavy oil and bitumen into lighter, less viscous products will continue to progress. It is possible that those advances could cause the HTL™ technology to become uncompetitive or obsolete.
iii. Decommissioning Provisions
The Company recognizes a provision for decommissioning costs when it has an obligation to dismantle and remove its PP&E or restore the site on which it is located. Decommissioning activities generally occur many years in the future and precise abandonment requirements and techniques are uncertain at the time the decommissioning liability is recorded. Removal technologies and associated costs are constantly changing, as well as political, environmental, legal, safety and public expectations. Consequently, estimated decommissioning provisions are a key source of estimation uncertainty.
iv. Option Pricing Models
The Company uses the Black Scholes option pricing model to calculate the fair value of the convertible portion of the convertible promissory note, stock options granted to directors, officers, employees and service providers and the derivative financial liabilities. Option pricing models require the input of highly subjective assumptions regarding the expected volatility. Changes in assumptions can materially affect the estimated fair value, and therefore, the existing models do not necessarily provide precise measure of fair value.

 

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v. Subsidiary Option
In January 2010, one of the Company’s subsidiaries granted a private investor an option (the “Subsidiary Option”) to acquire an equity interest in the subsidiary representing 20% of the subsidiary’s currently issued share capital (16.67% of the enlarged share capital immediately following the exercise of the Subsidiary Option) for Cdn$25.0 million. If the Subsidiary Option is exercised, Cdn$25 million of existing inter-corporate indebtedness owed by the subsidiary to the Company (through an intermediate subsidiary) will be converted into additional common shares of the subsidiary, thereby diluting the private investor’s equity interest to 14.286%. The fair value of the Subsidiary Option, calculated using the Black Scholes option pricing model, used an estimated share value and assumed the volatility to be similar to Ivanhoe.
vi. Deferred Income Taxes
Ivanhoe operates in a specialized industry in several tax jurisdictions. As a result, income is subject to various rates of taxation. The breadth of the Company’s operations and the global complexity of tax regulations require assessments of uncertainties and judgments in estimating the taxes it will ultimately pay. The final taxes paid are dependent upon many factors, including negotiations with taxing authorities in various jurisdictions, uncertain tax positions and resolution of disputes arising from federal, provincial, state and local tax audits. The resolution of these uncertainties and the associated final taxes may result in adjustments to the Company’s tax assets and tax liabilities.
5. CASH AND CASH EQUIVALENTS
                         
    March 31,     December 31,     January 1,  
    2011     2010     2010  
Cash at banks and on hand
    56,805       10,147       6,797  
Term deposits
    23,470       57,670        
Money market accounts
                14,715  
Restricted cash
    523       500       2,850  
 
                 
 
    80,798       68,317       24,362  
 
                 
Restricted cash includes funds pledged as security for a letter of credit with a short term maturity and cash held in escrow.
6. INTANGIBLE ASSETS
                                                 
    Exploration and Evaluation Assets              
                    Latin             HTLTM     Total Intangible  
    Asia     Canada     America     Total     Technology     Assets  
Cost
                                               
Balance January 1, 2010
    14,411       94,431       6,755       115,597       92,153       207,750  
Additions during the period
    27,261       29,324       17,704       74,289             74,289  
Exploration and evaluation expense
    (3,537 )           (4,934 )     (8,471 )           (8,471 )
 
                                   
Balance December 31, 2010
    38,135       123,755       19,525       181,415       92,153       273,568  
Additions during the period
    6,499       2,756       1,326       10,581             10,581  
 
                                   
Balance March 31, 2011
    44,634       126,511       20,851       191,996       92,153       284,149  
 
                                   
Amortization of the HTLTM technology has not commenced and its carrying value had not been impaired since it was acquired in 2005.
In the three months ended March 31, 2011, $0.7 million (year ended December 31, 2010 — $2.1 million) in employee benefits directly attributable to E&E assets were capitalized.

 

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7. PROPERTY, PLANT AND EQUIPMENT
                                                 
    Oil and Gas Property and Equipment              
                    Latin             Other     Total  
    Asia     Canada     America     Total     Assets     PP&E  
Cost
                                               
Balance January 1, 2010
    31,816                   31,816       11,373       43,189  
Additions during the period
    4,123                   4,123       1,648       5,771  
Disposals
                            (12 )     (12 )
 
                                   
Balance December 31, 2010
    35,939                   35,939       13,009       48,948  
Additions during the period
    3,530                   3,530       419       3,949  
Disposals
                            (5 )     (5 )
 
                                   
Balance March 31, 2011
    39,469                   39,469       13,423       52,892  
 
                                   
 
                                               
Accumulated Depreciation
                                               
Balance January 1, 2010
                            1,206       1,206  
Depletion and depreciation for the period
    6,196                   6,196       934       7,130  
Disposals
                            (6 )     (6 )
 
                                   
Balance December 31, 2010
    6,196                   6,196       2,134       8,330  
Depletion and depreciation for the period
    1,576                   1,576       256       1,832  
Disposals
                            (1 )     (1 )
 
                                   
Balance March 31, 2011
    7,772                   7,772       2,389       10,161  
 
                                   
 
                                               
Net Book Value
                                               
As at January 1, 2010
    31,816                   31,816       10,167       41,983  
As at December 31, 2010
    29,743                   29,743       10,875       40,618  
As at March 31, 2011
    31,697                   31,697       11,034       42,731  
Oil and Gas Property and Equipment
In the three months ended March 31, 2011, nil (year ended December 31, 2010 — $0.1 million) in employee benefits directly attributable to PP&E were capitalized.
Other Assets
Other assets includes the Company’s FTF at the Southwest Research Institute in San Antonio, Texas, and general furniture and fixtures.

 

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8. DEBT
                         
    March 31,     December 31,     January 1,  
    2011     2010     2010  
Convertible note
    41,178       40,217       38,005  
Unamortized discount
    (193 )     (385 )     (1,071 )
 
                 
Carrying amount
    40,985       39,832       36,934  
 
                 
In connection with the acquisition of the Tamarack leases in July 2008 from Talisman Energy Canada (“Talisman”), the Company issued a Cdn$40.0 million convertible promissory note (the “Convertible Note”) which matures in July 2011. Interest at the prime rate plus 2% is calculated daily and is payable semi-annually. The outstanding principal amount is convertible, at Talisman’s option, into a maximum of 12,779,552 Ivanhoe common shares at Cdn$3.13 per common share. The interest rate on the Convertible Note at March 31, 2011 was 5.00% (December 31, 2010 — 5.00%, January 1, 2010 — 4.25%).
Financial instruments with an exercise price denominated in a currency other than the Company’s functional currency are accounted for as derivatives. The Convertible Note is therefore considered to be a hybrid instrument with the embedded convertible component recognized as a derivative financial instrument (refer to Note 9 and 10) and the liability component recorded as debt.
The Company’s obligations under the Convertible Note are secured by a first fixed charge and security interest in favor of Talisman against the acquired Talisman leases and the related assets acquired by the Company pursuant to the Talisman lease acquisition.
In the three months ended March 31, 2011, $0.7 million (three months ended March 31, 2010 — $0.6 million, year ended December 31, 2010 — $2.5 million) of interest from the Convertible Note was capitalized to E&E assets. No interest from the Convertible Note was recorded as interest expense in the three months ended March 31, 2011 (year ended December 31, 2010 — nil).
9. FINANCIAL INSTRUMENTS
9.1 Fair Value of Financial Instruments Measured at Amortized Cost
Except as detailed below, the fair value of the Company’s financial instruments recognized at amortized cost approximates their carrying value due to the demand nature or short term maturity of these instruments.
                         
    March 31,     December 31,     January 1,  
    2011     2010     2010  
Debt
                       
Carrying Amount
    40,985       39,832       36,934  
Fair Value
    40,189       40,193       35,950  
The fair value of the liability component of the Convertible Note was estimated using a discounted cash flow calculation, assuming redemption in July 2011 and an interest rate of 5.0% at March 31, 2011 (December 31, 2010 — 5.0%).
9.2 Financial Instruments Measured at Fair Value Through Profit and Loss
The Company classifies its financial instruments according to the fair value hierarchy outlined in IFRS 7, “Financial Instruments: Disclosures,” as described below:
   
Level 1 — using quoted prices in active markets for identical assets or liabilities.
   
Level 2 — using inputs for the asset or liability, other than quoted prices, that are observable either directly (i.e. as prices) or indirectly (i.e. derived from prices).
   
Level 3 — using inputs for the asset or liability that are not based on observable market data, such as prices based on internal models or other valuation methods.

 

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The following table presents the Company’s derivative financial instruments measured at FVTPL:
                                         
    Level 1     Level 2     Level 3        
    2006     2009 & 2010     Convertible           Total  
    Purchase     Purchase     Component     Subsidiary     Fair  
    Warrants     Warrants     of Debt     Option     Value  
Balance January 1, 2010
    7,582       667       4,774             13,023  
Issuance of purchase warrants
          13,999                   13,999  
Exercise of purchase warrants
    (3 )                       (3 )
Derivative gains through profit and loss
    (1,964 )     (13,050 )     (3,558 )           (18,572 )
 
                             
Balance December 31, 2010
    5,615       1,616       1,216             8,447  
Exercise of purchase warrants
    (2 )     (3,107 )                 (3,109 )
Expiration of purchase warrants through profit and loss
          (1,477 )                 (1,477 )
Derivative (gains) losses through profit and loss
    (3,267 )     2,968       (537 )     1,186       350  
 
                             
Balance March 31, 2011
    2,346             679       1,186       4,211  
 
                             
The gain on derivative instruments of $1.1 million for the three months ended March 31, 2011, (three months ended March 31, 2010 — $2.1 million, year ended December 31, 2010 — $18.6 million) originated from the expiration and revaluation of derivative financial instruments measured at FVTPL.
Where the instrument is quoted in an active market, the movement in fair value due to credit risk is calculated as the change in fair value that is not attributable to changes in market risk. Where the instrument is not quoted in an active market, the fair value is calculated using a valuation technique that incorporates credit risk by discounting the cash flows using a credit-adjusted rate which reflects the level at which the Company could issue similar instruments at the reporting date. The amount of change in the fair value, during the period and cumulatively, of designated financial liabilities through FVTPL that is attributable to changes in credit risk is determined to be nil.
9.3 Risks Arising from Financial Instruments
In the normal course of operations, the Company is exposed to market risks resulting from movements in commodity prices, foreign currency exchange rates and interest rates, which may result in fluctuations in the fair value or future cash flows of its financial instruments.
i. Commodity Price Risks
Commodity price risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market commodity prices. Oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility. However, no hedging contracts were in place in the first three months of 2011.
ii. Foreign Currency Exchange Rate Risk
Ivanhoe is exposed to foreign currency exchange rate risk as a result of incurring capital expenditures and operating costs in currencies other than the US dollar. A substantial portion of the Company’s activities are transacted in, or referenced to, US dollars, including oil sales in Asia, capital spending in Ecuador and ongoing FTF operations. A portion of transactions are in other currencies, such as Dagang operating costs paid in Chinese renminbi, Tamarack exploration activities funded in Canadian dollars and the purchase warrants exercised in 2011. The Company has not entered into any foreign currency derivatives to date in 2011, nor does the Company anticipate using foreign currency derivatives in the remainder of the year. To help reduce the Company’s exposure to foreign currency exchange rate risk, the Company seeks to hold assets and liabilities denominated in the same currency when appropriate.

 

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The following table shows the Company’s exposure to foreign currency exchange rate risk on its net loss and comprehensive loss for March 31, 2011, assuming reasonably possible changes in the relevant foreign currency. This analysis assumes all other variables remain constant.
                 
    Change From a 10%     Change From a 10%  
(Increase) Decrease in Net Loss and Comprehensive Loss   Increase or Weakening     Decrease or Strengthening  
Chinese renminbi
    605       (740 )
Canadian dollar
    (1,715 )     2,040  
iii. Interest Rate Risk
Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in market interest rates. Interest rate risk arises from interest-bearing borrowings which have a variable interest rate. The Company’s net loss and accumulated deficit would not have been impacted by an interest rate change in the first quarter of 2011 as interest on the Company’s debt related to the Convertible Note is capitalized.
iv. Credit Risk
Ivanhoe is exposed to credit risk with respect to its cash and cash equivalents, accounts receivable, note receivable and long term receivables. The Company’s maximum exposure to credit risk at March 31, 2011, is represented by the carrying amount of these non-derivative financial assets.
The Company believes its exposure to credit risk related to cash and cash equivalents is minimal due to the quality of the financial institutions where the funds are held and the nature of the deposit instruments. Most of the Company’s credit exposures are with counterparties in the energy industry and are therefore exposed to normal industry credit risks. Ivanhoe manages its credit risk by entering into sales contracts only with established entities.
Currently, all of the Company’s oil production is sold to one national oil corporation. As a result, 92% of the outstanding accounts receivable balance at March 31, 2011 (December 31, 2010 — 85%, January 1, 2010 — 94%) is due from a national oil corporation. Long term receivables are composed of value-added tax receivable amounts from Ecuador and will be recoverable upon commencement of commercial operations. Ivanhoe considers the risk of default on these items to be low due to the Company’s ongoing operations in China and Ecuador.
                         
    March 31,     December 31,     January 1,  
    2011     2010     2010  
Accounts receivable — current
    6,508       6,329       5,004  
Accounts receivable — over 90 days
          30       17  
 
                 
 
    6,508       6,359       5,021  
 
                 
v. Liquidity Risk
Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available. Since cash flows from existing operations are insufficient to fund future capital expenditures, Ivanhoe intends to finance future capital projects with a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level or from the sale of existing assets. There is no assurance that the Company will be able to obtain such financing on favorable terms, if at all.

 

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The contractual maturity of the fixed and floating rate derivative and non-derivative financial liabilities are shown in the table below. The amounts presented represent the future undiscounted principal and interest cash flows and therefore may not equate to the values presented in the statement of financial position.
         
    Less than  
As at March 31, 2011   1 year  
Derivative financial liabilities
       
Purchase warrants
    2,346  
Convertible component of note
    679  
Subsidiary option
    1,186  
Non-derivative financial liabilities
       
Accounts payable and accrued liabilities
    24,702  
Debt and interest
    42,285  
10. DERIVATIVE FINANCIAL INSTRUMENTS
The Company’s derivative financial instruments are comprised of common share purchase warrants and the convertible component of the Convertible Note.
10.1 Purchase Warrants
The following table reflects the changes in the Company’s purchase warrants outstanding:
                 
    Purchase     Shares  
(000s)   Warrants     Issuable  
Balance January 1, 2010
    12,135       12,135  
Private placements
    12,500       12,500  
Exercised
    (2 )     (2 )
 
           
Balance December 31, 2010
    24,633       24,633  
Exercised
    (8,620 )     (8,620 )
Expired
    (4,619 )     (4,619 )
 
           
Balance March 31, 2011
    11,394       11,394  
 
           
At March 31, 2011, the purchase warrants issued in 2006 remained exercisable:
                                                         
    Price Per                             Exercise     Cash Value on        
    Special     Outstanding(1)     Fair Value             Price Per     Exercise     Valuation  
Year of Issue   Warrant     (000s)     ($US000s)     Expiry Date     Share     ($US000s)     Method  
2006
    US$2.23       11,394       2,346     May 2011     Cdn$2.93 (2)     34,365     Quoted Market Price  
     
(1)  
One common share is issuable for each purchase warrant upon exercise.
 
(2)  
Each common share purchase warrant originally entitled the holder to purchase one common share at a price of US$2.63 per share until the fifth anniversary date of the closing. In September 2006, these warrants were listed on the TSX and the exercise price was changed to Cdn$2.93.

 

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At December 31, 2010, the following purchase warrants were exercisable:
                                                         
    Price Per                             Exercise     Cash Value on        
    Special     Outstanding(1)     Fair Value             Price Per     Exercise     Valuation  
Year of Issue   Warrant     (000s)     ($US000s)     Expiry Date     Share     ($US000s)     Method  
2006
    US$2.23       11,398       5,615     May 2011     Cdn$2.93 (2)     33,577     Quoted Market Price  
2009
    N/A       735       11     Feb 2011     Cdn$4.05       2,993     Black-Scholes  
2010
    Cdn$3.00       10,417       1,326     Feb 2011     Cdn$3.16       33,095     Black-Scholes  
2010
    Cdn$3.00       2,083       279     Feb 2011     Cdn$3.16       6,619     Black-Scholes  
 
                                         
 
            24,633       7,231                       76,284          
 
                                         
     
(1)  
One common share is issuable for each purchase warrant upon exercise.
 
(2)  
Each common share purchase warrant originally entitled the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing. In September 2006, these warrants were listed on the Toronto Stock Exchange and the exercise price was changed to Cdn$2.93.
At December 31, 2010, the fair value of the purchase warrants issued in 2009 and 2010 was calculated using a weighted average risk-free interest rate of 1.0%, a dividend yield of 0.0%, a weighted average volatility factor of 66.6% and an expected life of two months. If the volatility used to fair value the purchase warrants decreased by 10%, the fair value would decrease by $0.4 million. Increasing the volatility by 10% would have had the opposite, but approximately equal, impact.
10.2 Convertible Note
The Company issued a Cdn$40.0 million Convertible Note, as described in Note 8. The outstanding principal amount is convertible, at Talisman’s option, into common shares of the Company. The fair value of the convertible component was $0.7 million at March 31, 2011 (December 31, 2010 — $1.2 million), calculated with the Black Scholes valuation method using a weighted average risk-free interest rate of 1.0%, a dividend yield of 0.0%, a weighted average volatility factor of 30% and an expected life of approximately three months.
If the volatility used to fair value the convertible component decreased by 10%, the fair value would decrease by $0.5 million. Increasing the volatility by 10% would increase the fair value by $0.6 million.
10.3 Subsidiary Option
In January 2010, one of the Company’s subsidiaries granted a private investor an option (the “Subsidiary Option”) to acquire an equity interest in the subsidiary representing 20% of the subsidiary’s currently issued share capital (16.67% of the enlarged share capital immediately following the exercise of the Subsidiary Option) for Cdn$25.0 million. If the Subsidiary Option is exercised, Cdn$25 million of existing inter-corporate indebtedness owed by the subsidiary to the Company (through an intermediate subsidiary) will be converted into additional common shares of the subsidiary, thereby diluting the private investor’s equity interest to 14.286%. The Subsidiary Option is valid for one year and did not become exercisable until the first quarter of 2011. The option was determined to have a nominal value on the date of grant.
The fair value of the Subsidiary Option as at March 31, 2011, was calculated using the Black Scholes valuation method using an estimated share value of $19.69, an exercise price of $30.00 per share, a risk-free interest rate of 1.4%, a dividend yield of 0.0%, an expected life of approximately one year and an estimated volatility of 55.8%, which is similar to Ivanhoe.
If the estimated volatility used to fair value the Subsidiary Option increased by 10%, the fair value would increase by $0.5 million. Decreasing the volatility by 10% would have had the opposite, but approximately equal, impact.

 

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11. LONG TERM PROVISIONS
                 
    March 31,     December 31,  
    2011     2010  
Decommissioning provision
               
Balance, beginning of period
    1,108       1,040  
Liabilities incurred
          642  
Liabilities settled
          (179 )
Revisions in cash flow estimates
          (488 )
Unwinding of discount
    8       23  
Change in discount rates
    15       70  
 
           
Balance, end of period
    1,131       1,108  
Long term obligation
    1,900       1,900  
 
           
 
    3,031       3,008  
 
           
11.1 Decommissioning Provision
The decommissioning provision represents the present value of decommissioning costs related to oil and gas properties in Canada, the FTF, and oil and gas properties in Ecuador, which are expected to be incurred in 2013, 2029 and 2038 respectively. The Company records a provision for the estimated future cost of decommissioning oil and gas properties and the FTF on a discounted basis. The provision for the costs of decommissioning these oil and gas properties and the FTF at the end of their economic lives has been estimated, at current prices or long term assumptions, depending on the expected timing of the activity, and discounted using a time value of money rate of 1.7% to 3.6% at March 31, 2011 (December 31, 2010 — 2.0% to 3.7%).
11.2 Long term obligation
As part of a 2005 merger agreement, the Company assumed an obligation to pay $1.9 million in the event, and at such time that, the sale of units incorporating the HTLTM technology for petroleum applications reach a total of $100.0 million.
12. COMMITMENTS AND CONTINGENCIES
12.1 Income Taxes
The Company has an uncertain tax position in China related to when it is entitled to take tax deductions on capitalized development costs that are amortized on a straight-line basis. To the extent that there is a different interpretation in the timing of the deductibility of development costs, this could potentially result in an increase in the current tax expense of $0.9 million.
The Company has an uncertain tax position related to the calculation of a gain on the consideration received from two farm-out transactions. To the extent that the calculation of the gain is interpreted differently and the amounts are subject to withholding tax, there would be an additional current tax expense of approximately $0.7 million.
No amounts have been recorded in the Financial Statements related to the above mentioned uncertain tax positions as management has determined the likelihood of an unfavorable outcome to the Company to be low.
12.2 Operating Lease Arrangements
In the three months ended March 31, 2011, the Company expended $0.5 million (three months ended March 31, 2010 — $0.5 million) on operating leases relating to the rental of office space, which expire between May 2011 and December 2013.
At March 31, 2011, future net minimum payments for operating leases were:
         
Remainder of 2011
    1,372  
2012-2013
    1,153  
 
     
 
    2,525  
 
     

 

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12.3 Other
The Company may be required to make a Cdn$15.0 million cash payment to Talisman upon receiving government and other approvals necessary to develop the northern border of one of the Tamarack leases.
Occasionally, Ivanhoe enters into consulting agreements whereby a success fee may be payable if and when either a definitive agreement is signed or certain other contractual milestones are met. Under these agreements, the consultant may receive cash, common shares, stock options or some combination thereof.
From time to time, Ivanhoe is involved in litigation or has claims brought against it in the normal course of business. Management is currently not aware of any claims that would materially affect the reported financial position or results of operations.
13. SHARE CAPITAL
     
Authorized
  Unlimited common shares with no par value
Unlimited preferred shares with no par value
 
   
Issued and Outstanding
  343,932,658 common shares (December 31, 2010 — 334,365,482)
Nil preferred shares (December 31, 2010 — nil)
See the unaudited Condensed Consolidated Statements of Changes in Equity for the change in common shares issued in the three months ended March 31, 2011 and 2010.
14. SHARE-BASED PAYMENTS
The Company has an equity-settled incentive plan under which it may i) grant stock options to directors and eligible employees to purchase common shares, ii) issue common shares to directors and eligible employees as bonus awards, and iii) issue common shares under a share purchase plan for eligible employees. The total number of common shares that may be issued under this plan cannot exceed 7% of the Company’s issued and outstanding common shares. The share purchase plan has not yet been activated.
Stock options are issued at the weighted-average trading price for the five days immediately preceding the award and are conditional on continuing employment. Expiration and vesting periods are set at the discretion of the Board of Directors, but typically vest over three to four years and expire five to ten years from the date of issue.
The weighted average fair value of stock options granted during the three months ended March 31, 2011 was Cdn$2.28 (three months ended March 31, 2010 — Cdn$2.80) per option at the grant date using the Black Scholes option pricing model. The weighted average assumptions used for the calculation were:
                 
Three months ended March 31,   2011     2010  
Expected life (in years)
    6.3       5.1  
Volatility (1)
    74.4 %     77.5 %
Dividend yield
           
Risk-free rate
    2.9 %     3.0 %
Estimated forfeiture rate
    2.9 %     2.1 %
     
(1)  
Expected volatility factor based on historical volatility of the Company’s publicly traded common shares.
The Company’s stock-based compensation related to option awards were classified as general and administrative or operating expenses in earnings. In the three months ended March 31, 2011, nil (three months ended March 31, 2010 — $0.8 million) of share-based payments was capitalized to intangible exploration and evaluation assets.

 

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Details of transactions under the share options plan are as follows:
                                 
    March 31, 2011     December 31, 2010  
    Number of     Weighted Average     Number of     Weighted Average  
    Stock Options     Exercise Price     Stock Options     Exercise Price  
    (000s)     (Cdn$)     (000s)     (Cdn$)  
Outstanding, beginning of period
    16,927       2.24       15,013       2.27  
Granted
    50       3.44       6,041       2.56  
Exercised
    (1,480 )     2.41       (2,743 )     2.28  
Expired
                (635 )     2.60  
Forfeited
    (1 )     2.30       (749 )     2.64  
 
                       
Outstanding, end of period
    15,496       2.21       16,927       2.24  
 
                       
 
                               
Exercisable, end of period
    6,478       2.06       7,324       2.19  
 
                       
The weighted average share price at the date of exercise for share options exercised during the period was Cdn$3.30.
The following table summarizes information in respect of stock options outstanding and exercisable at March 31, 2011:
                         
            Weighted Average        
            Remaining     Weighted Average  
    Outstanding     Contractual Life     Exercise Price  
Range of Exercise Prices (Cdn$)   (000s)     (years)     (Cdn$)  
1.51 to 2.06
    5,788       2.5       1.71  
2.15 to 2.71
    7,535       4.8       2.33  
2.77 to 3.44
    2,173       4.9       3.16  
 
                 
 
    15,496       3.9       2.21  
 
                 
15. RETIREMENT PLANS
In 2001, the Company adopted a defined contribution retirement or thrift plan (“401(k) Plan”) to assist US employees in providing for retirement or other future financial needs. Employees’ contributions (up to the maximum allowed by US tax laws) are matched 100% by the Company. Payments are also made to a state managed plan for employees in China.
For the three months ended March 31, 2011, the Company paid $0.2 million for retirement plan contributions (three months ended March 31, 2010 — $0.2 million).
16. SEGMENT INFORMATION
Ivanhoe’s organizational structure reflects its various operating activities and the geographic areas in which it operates. Oil and gas operations are divided into three geographic segments: Asia, Canada and Latin America. Asian operations capture the Company’s oil production in Dagang and Daqing and exploration at Zitong in China as well as exploration in Mongolia. The Canadian segment comprises activities from Ivanhoe’s oil sands development project at Tamarack in Alberta, Canada. Latin America consists of exploration and development of Block 20 in Ecuador.
The Technology Development area captures costs incurred to develop, enhance and identify improvements in the application of the Company’s HTL™ technology. The Corporate area consists of costs that are not directly allocable to operating projects, such as executive officers, corporate financings and other general corporate activities.
In prior years, the Company’s business development activities were included in a combined Business and Technology Development segment. The comparative information below has been restated to reclassify business development activities to the Corporate segment.
The accounting policies of the segments are the same as the Company’s accounting policies described in Note 3. Segment results include transactions between business segments. Corporate activities undertaken on behalf of a segment are allocated at cost. Oil revenue is classified according to the geographic location of the production. Segment liabilities include intercompany balances.

 

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The following tables present the Company’s segment information, capital investments and identifiable assets and liabilities.
                                                 
                    Latin     Technology              
Three months ended March 31, 2011   Asia     Canada     America     Development     Corporate     Total  
Revenue
                                               
Oil(1)
    8,119                               8,119  
Interest
    1                         66       67  
 
                                   
 
    8,120                         66       8,186  
 
                                   
 
                                               
Expenses
                                               
Operating
    3,310                   1,213             4,523  
Exploration and evaluation
                                   
General and administrative
    2,772       1,306       1,680       510       7,149       13,417  
Depletion and depreciation
    1,605       2       23       132       69       1,831  
Foreign currency exchange gain
    (10 )     (3 )                 (212 )     (225 )
Derivative instruments (gain) loss
    1,186                         (2,315 )     (1,129 )
Interest
          2       4       2             8  
 
                                   
 
    8,863       1,307       1,707       1,857       4,691       18,425  
 
                                   
 
                                               
Loss before income taxes
    (743 )     (1,307 )     (1,707 )     (1,857 )     (4,625 )     (10,239 )
 
                                               
(Provision for) recovery of income taxes
                                               
Current
    (264 )                       (58 )     (322 )
Deferred
    (1,165 )                 (391 )     991       (565 )
 
                                   
 
    (1,429 )                 (391 )     933       (887 )
 
                                   
 
                                               
Net loss and comprehensive loss
    (2,172 )     (1,307 )     (1,707 )     (2,248 )     (3,692 )     (11,126 )
 
                                   
 
                                               
Capital investments — Intangible
    6,499       2,539       1,326                   10,364  
Capital investments — Property, plant and equipment
    3,546             62       341             3,949  
 
                                   
 
                                               
As at March 31, 2011
                                               
Assets(2)
    91,835       126,708       28,042       102,092       70,388       419,065  
Liabilities(3)
    123,714       135,402       45,434       79,189       (288,729 )     95,010  
As at December 31, 2010
                                               
Assets(2)
    85,273       123,890       24,392       101,899       58,964       394,418  
Liabilities(3)
    114,980       131,277       42,162       76,747       (271,232 )     93,934  
As at January 1, 2010
                                               
Assets(2)
    57,528       94,594       7,778       101,893       19,158       280,951  
Liabilities(3)
    81,047       98,262       13,145       56,909       (162,821 )     86,542  
     
(1)  
All revenues in Asia are generated from the sale of oil production in China to one customer.
 
(2)  
Assets include investments in subsidiaries that are eliminated for consolidation under Corporate.
 
(3)  
Liabilities for Corporate include intercompany receivables of $368.1 million at March 31, 2011 (December 31, 2010 — $352.5 million; January 1, 2010 — $216.7 million) resulting in a negative balance.

 

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                    Latin     Technology              
Three months ended March 31, 2010   Asia     Canada     America     Development     Corporate     Total  
Revenue
                                               
Oil(1)
    5,330                               5,330  
Interest
    2                         17       19  
 
                                   
 
    5,332                         17       5,349  
 
                                   
 
                                               
Expenses
                                               
Operating
    2,236                   1,218             3,454  
Exploration and evaluation
    606                               606  
General and administrative
    1,213       972       1,675       228       4,344       8,432  
Depletion and depreciation
    1,723       2       7       (243 )     48       1,537  
Foreign currency exchange (gain) loss
    9       (8 )                 (4,188 )     (4,187 )
Derivative instruments loss
                            2,057       2,057  
Interest
          1             3             4  
 
                                   
 
    5,787       967       1,682       1,206       2,261       11,903  
 
                                   
 
                                               
Loss before income taxes
    (455 )     (967 )     (1,682 )     (1,206 )     (2,244 )     (6,554 )
 
                                               
Provision for income taxes
                                               
Current
    (78 )                       (1 )     (79 )
Deferred
                      (172 )           (172 )
 
                                   
 
    (78 )                 (172 )     (1 )     (251 )
 
                                   
 
                                               
Net loss and comprehensive loss
    (533 )     (967 )     (1,682 )     (1,378 )     (2,245 )     (6,805 )
 
                                   
 
                                               
Capital investments — Intangible
    1,927       17,428       3,727                   23,082  
Capital investments — Property, plant & equipment
    376       3       11       206       222       818  
     
(1)  
All revenues in Asia are generated from the sale of oil production in China to one customer.

 

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17. CAPITAL MANAGEMENT
The Company defines capital as total shareholders’ equity and debt. At March 31, 2011, the Company is not subject to any financial covenants. The Company’s objectives are to safeguard Ivanhoe’s ability to continue as a going concern, to continue the exploration and development of its projects and to maintain a flexible capital structure which optimizes the costs of capital at an acceptable risk.
The Company’s main source of funds has historically been public and private equity and debt markets. The Company does not anticipate cash flow from operating activities will be sufficient to meet its operating and capital obligations and, as such, the Company intends to finance its operating and capital projects from a combination of strategic investors in its projects and/or public and private debt and equity markets, either at a parent company level or at a project level. To manage its capital requirements, the Company prepares an annual expenditure budget that is updated periodically. The annual and updated budgets are approved by the Board of Directors.
In order to maximize ongoing development efforts, the Company does not pay dividends. The Company’s invests its cash in highly liquid, short term, interest-bearing investments with maturities of 90 days or less to correspond with the expected timing of expenditures.
18. OPERATING EXPENSES
Operating expenses for the Company are comprised of the following:
                 
Three months ended March 31,   2011     2010  
Asia
               
Field operating
    1,623       1,297  
Windfall levy
    1,577       811  
Engineering support
    110       128  
 
           
 
    3,310       2,236  
 
               
Technology Development
               
FTF operating costs
    1,213       1,218  
 
           
Total operating costs
    4,523       3,454  
 
           
The windfall levy is imposed by China’s Ministry of Finance at the progressive rates from 20% to 40% on the portion of the monthly weighted average sales price of the crude oil lifted in China exceeding US$40.00 per barrel.
19. SUPPLEMENTAL CASH FLOW INFORMATION
19.1 Cash Payments For Interest And Taxes
The Company made the following cash payments for interest and income taxes:
                 
Three months ended March 31,   2011     2010  
Income taxes
    57       427  
Interest
    983       805  
 
               
Shares issued for bonuses and services
          799  

 

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19.2 Changes in Non-Cash Activities
The Company incurred the following non-cash transactions:
                 
Three months ended March 31,   2011     2010  
Operating activities
               
Accounts receivable
    (624 )     244  
Note receivable
    31       (36 )
Prepaid and other current assets
    66       123  
Accounts payable and accrued liabilities
    1,972       37  
Income taxes payable
    351       (350 )
 
           
 
    1,796       18  
 
           
 
               
Investing activities
               
Accounts receivable
    476       (25 )
Prepaid and other current assets
    732       83  
Accounts payable and accrued liabilities
    1,267       822  
 
           
 
    2,475       880  
 
           
 
               
Financing activities
               
Accounts payable and accrued liabilities
    (19 )      
 
           
 
    4,252       898  
 
           
20. RELATED PARTY TRANSACTIONS
Ivanhoe is party to cost sharing agreements with other companies which are related or controlled through common directors or shareholders. Through these agreements, we share office space, furnishings, equipment, air travel and communications facilities in various international locations. We also share the costs of employing administrative and non-executive management personnel at these offices. The Company is billed on a cost recovery basis in most cases. These transactions have been measured at their exchange amount.
The breakdown of the related party expenses for the three months ended March 31 is as follows:
                     
Related Party   Nature of Transaction   2011     2010  
Global Mining Management Corp.
  Administration     213       307  
Ivanhoe Capital Aviation Ltd.
  Aircraft     300       300  
I2MS.Net PTE Ltd.
  Information systems     58       32  
Ivanhoe Capital Services Ltd.
  Administration     92       26  
SouthGobi Resources Ltd.
  Administration     51        
GoviEx Gold Inc.
  Business development           25  
1092155 Ontario Inc.
  HTLTM technology     12       13  
Ensyn Technologies Inc.
  HTLTM technology           7  
Ivanhoe Capital PTE Ltd.
  Administration     74       3  
Ivanhoe Mines Ltd.
  Administration           1  
 
               
 
        800       714  
 
               
The liabilities of the Company include the following amounts due to related parties:
                             
        March 31,     December 31,     January 1,  
Related Party   Nature of Transaction   2011     2010     2010  
Global Mining Management Corp.
  Administration     38       86       40  
I2MS.Net PTE Ltd.
  Information systems     16       13       17  
SouthGobi Resources Ltd.
  Administration     13       38        
Ivanhoe Capital Services Ltd.
  Management     15       70       15  
Ensyn Technologies Inc.
  HTLTM technology                  
Ivanhoe Capital PTE Ltd.
  Administration     11              
 
                     
 
        93       207       72  
 
                     

 

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21. REMUNERATION OF KEY MANAGEMENT PERSONNEL
The remuneration of directors and other key members of management was:
                 
Three months ended March 31,   2011     2010  
Base salaries or fees and other cash payments
    780       705  
Employer’s contributions to retirement plan
    16       17  
Share-based compensation expense
    718       396  
 
           
 
    1,514       1,118  
 
           
22. INVESTMENTS IN SUBSIDIARIES
Ivanhoe has investments in the following 100% owned subsidiaries which principally affect the operating results or net assets of the Company. Subsidiaries which are inactive or immaterial have been omitted.
     
Name of Subsidiary   Jurisdiction of Incorporation or Formation
Sunwing Holding Corporation *
  Barbados
Sunwing Energy Ltd.
  Bermuda
Sunwing Zitong Energy Ltd.
  British Virgin Islands
Pan-China Resources Ltd.
  British Virgin Islands
Ivanhoe Energy Mongolia Inc. *
  Alberta
PanAsian Energy Ltd.
  Nevis
Shaman LLC
  Mongolia
Ivanhoe Energy Latin America Inc. *
  British Columbia
Ivanhoe Energy Ecuador Inc.
  British Columbia
Ivanhoe Energy Canada Inc. *
  Alberta
Ivanhoe Energy Holdings Inc. *
  Nevada
Ivanhoe HTL Petroleum Ltd
  Nevada
     
*  
— subsidiary held directly by Ivanhoe Energy Inc. All other companies are held through subsidiary undertakings.
23. FIRST TIME ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS
The Company adopted IFRS on January 1, 2011, with a transition date of January 1, 2010. Under IFRS 1, “First-time Adoption of International Financial Reporting Standards,” the standards are applied retrospectively at the transition date with all adjustments to assets and liabilities taken to retained earnings unless certain exemptions are applied.
23.1 Exemptions from Full Retrospective Application.
IFRS 1 outline specific guidelines that a first-time adopter must adhere to under certain circumstances. None of the mandatory exemptions from retrospective application were applicable to Ivanhoe. The Company has made the following exemptions to its opening statement of financial position dated January 1, 2010:
i. Deemed Cost
The Company elected to report oil and gas properties, recorded in PP&E and E&E assets, at a deemed cost instead of the actual cost as though IFRS had been adopted retroactively. The deemed cost will be the amounts previously reported under Canadian GAAP.
ii. Decommissioning Provisions Included in the Cost of Property, Plant and Equipment
The exemption provided in IFRS 1 from the full retrospective application of International Financial Reporting Committee 1 “Changes in Existing Decommissioning, Restoration and Similar Liabilities” was applied to decommissioning liabilities associated with our oil and gas properties recorded in PP&E and intangible assets. The Company elected to re-measure its FTF decommissioning provision under IFRS.

 

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iii. Share-Based Payment
The Company elected to apply the share-based payment exemption and has applied IFRS 2, “Share-based Payments” only to those stock options that were issued after November 7, 2002, but that had not vested by the January 1, 2010 transition date.
iv. Business Combinations
The Company applied the business combinations exemption in IFRS 1 and has not restated business combinations that took place prior to the January 1, 2010 transition date.
v. Leases
The Company applied the lease exemption in IFRS 1 for contracts and agreements entered into before January 1, 2010. Where Ivanhoe has, under Canadian GAAP, made the same determination of whether an arrangement contains a lease as required by IFRIC 4, “Determining whether an Arrangement contains a Lease,” but that assessment was made at a date other than that required by IFRIC 4, the Company elected not to reassess that determination.
23.2 Reconciliations to IFRS
IFRS employs a conceptual framework that is similar to Canadian GAAP. While the adoption of IFRS has not changed the actual cash flows of the Company, the adoption has resulted in significant changes to the reported financial position and results of operations of the Company. Presented below are reconciliations prepared by the Company to reconcile to IFRS the Consolidated Statement of Financial Position and Consolidated Statement of Loss and Comprehensive Loss of the Company from those reported under Canadian GAAP.
Changes made to the statements of financial position and statements of loss have resulted in reclassifications of various amounts on the statements of cash flows. Due to the reclassification of capitalized overhead under Canadian GAAP to operating costs or general and administrative (“G&A”) expenses under IFRS, cash used in investing activities under Canadian GAAP was reclassified to cash used in operating activities under IFRS. Since there was no change to the total increase in cash and cash equivalents, no reconciliation for the statements of cash flows was presented.
Certain amounts previously reported under Canadian GAAP have been reclassified to conform with IFRS presentation standards. Restricted cash was combined with cash and cash equivalents and asset retirement obligations were combined with other long term provisions. Other name changes have been made to certain financial statement line items to conform with the IFRS format standards.

 

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Reconciliation of Consolidated Statements of Financial Position
                                                                         
    At January 1, 2010     At December 31, 2010     At March 31, 2010  
    Canadian     Effect of     IFRS     Canadian     Effect of     IFRS     Canadian     Effect of     IFRS  
(US$000s)   GAAP     Transition     Balances     GAAP     Transition     Balances     GAAP     Transition     Balances  
 
                                                                       
Assets
                                                                       
Current Assets
                                                                       
Cash and cash equivalents
    24,362             24,362       68,317             68,317       139,235             139,235  
Accounts receivable
    5,021             5,021       6,359             6,359       4,802             4,802  
Note receivable
    225             225       264             264       261             261  
Prepaid and other current assets
    771             771       2,859             2,859       565             565  
 
                                                     
 
    30,379             30,379       77,799             77,799       144,863             144,863  
 
                                                                       
Intangible assets
    92,153       115,597  a     207,750       92,153       197,193  a     273,568       92,153       141,043  a     231,199  
 
                                  (7,482 ) b                     (1,391 ) b        
 
                                  175  c                     (606 ) g        
 
                                  (8,471 ) g                              
Property, plant and equipment, net
    158,392       (115,597 ) a     41,983       237,200       (197,193 ) a     40,618       182,219       (141,043 ) a     40,865  
 
            (904 ) b                     (2,014 ) b                     (949 ) b        
 
            92  c                     189  c                     92  c        
 
                                  2,436  f                     546  f        
Long term receivables
    839             839       2,433             2,433       1,183             1,183  
 
                                                     
 
    281,763       (812 )     280,951       409,585       (15,167 )     394,418       420,418       (2,308 )     418,110  
 
                                                     
 
                                                                       
Liabilities and Shareholders’ Equity
                                                                       
Current Liabilities
                                                                       
Accounts payable and accrued liabilities
    10,779             10,779       21,482             21,482       11,638             11,638  
Debt
                      39,832             39,832                    
Derivative financial instruments
          13,023  d     13,023             8,447  d     8,447             29,076  d     29,076  
Income tax payable
    530             530                         180             180  
Decommissioning costs
    753             753                         330             330  
 
                                                     
 
    12,062       13,023       25,085       61,314       8,447       69,761       12,148       29,076       41,224  
 
                                                                       
Long term debt
    36,934             36,934                         38,449             38,449  
Long term provisions
    2,095       92  c     2,187       2,644       364  c     3,008       2,249       92  c     2,341  
Deferred income tax liability
    22,643       (307 ) b     22,336       21,518       (367 ) b     21,165       22,817       (313 ) b     22,508  
 
                                  14  f                     4  f        
 
                                                     
 
    73,734       12,808       86,542       85,476       8,458       93,934       75,663       28,859       104,522  
 
                                                     
 
                                                                       
Shareholders’ Equity
                                                                       
Share capital
    422,322             422,322       550,562             550,562       549,075       (105 ) e     548,970  
Purchase warrants
    19,427       (19,427 ) d           33,423       (33,423 ) d           33,423       (33,423 ) d      
Contributed surplus
    20,029       (2,947 ) d     18,724       22,983       (2,947 ) d     23,141       18,573       (2,947 ) d     18,059  
 
            1,642  e                     3,105  e                     2,433  e        
Convertible note
    2,086       (2,086 ) d           2,086       (2,086 ) d           2,086       (2,086 ) d      
Accumulated deficit
    (255,835 )     9,198       (246,637 )     (284,945 )     11,726       (273,219 )     (258,402 )     4,961       (253,441 )
 
                                                     
 
    208,029       (13,620 )     194,409       324,109       (23,625 )     300,484       344,755       (31,167 )     313,588  
 
                                                     
 
    281,763       (812 )     280,951       409,585       (15,167 )     394,418       420,418       (2,308 )     418,110  
 
                                                     

 

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Reconciliation of Consolidated Statements of Loss and Comprehensive Loss
                                                 
    Year ended December 31, 2010     Three months ended March 31, 2010  
    Canadian     Effect of             Canadian     Effect of        
(US$000s)   GAAP     Transition     IFRS     GAAP     Transition     IFRS  
 
                                               
Revenue
                                               
Oil
    21,720             21,720       5,330             5,330  
Interest
    208             208       19             19  
 
                                   
 
    21,928             21,928       5,349             5,349  
 
                                   
 
                                               
Expenses
                                               
Operating
    13,514       111  b     13,625       3,423       31  b     3,454  
Exploration and evaluation
          8,471  g     8,471             606  g     606  
General and administrative
    32,864       8,481  b     42,807       6,340       1,406  b     8,432  
 
            1,462  e                     686  e        
Depletion and depreciation
    8,960       (2,436 ) f     6,524       2,083       (546 ) f     1,537  
Foreign exchange
    (3,325 )           (3,325 )     (4,187 )           (4,187 )
(Gain) loss on derivative instruments
          (18,571 ) d     (18,571 )           2,057  d     2,057  
Interest
    24             24       4             4  
 
                                   
 
    52,037       (2,482 )     49,555       7,663       4,240       11,903  
 
                                   
 
                                               
Loss before income taxes
    (30,109 )     2,482       (27,627 )     (2,314 )     (4,240 )     (6,554 )
 
                                               
(Provision for) recovery of income taxes
                                               
Current
    (126 )           (126 )     (79 )           (79 )
Deferred
    1,125       60  b     1,171       (174 )     6  b     (172 )
 
            (14 ) f                     (4 ) f        
 
                                   
 
    999       46       1,045       (253 )     2       (251 )
 
                                   
 
                                               
Net loss and comprehensive loss
    (29,110 )     2,528       (26,582 )     (2,567 )     (4,238 )     (6,805 )
 
                                   
Notes to reconciliation
a.  
Reclassification of Intangible Assets
 
   
Under Canadian GAAP, oil and gas properties in the exploration and evaluation stage were classified as oil and gas properties and development costs. In accordance with IFRS 6, these properties were reclassified as intangible assets.
 
b.  
Adjustment for Capitalized Overhead
 
   
Under Canadian GAAP, the Company capitalized employee benefits and overhead that were directly attributable to E&E assets and PP&E. A portion of the amounts capitalized under Canadian GAAP do not meet the threshold for capitalization under IAS 16, “Property, Plant and Equipment” and therefore have been reclassified as operating costs or general and administrative expenses, as appropriate.
 
c.  
Decommissioning Provisions
 
   
Under Canadian GAAP, the present value of the Company’s estimated future decommissioning costs was calculated using a credit-adjusted risk-free discount rate. The discount rate under IFRS does not permit company specific credit adjustments and therefore the decommissioning provision has been recalculated using a risk-free discount rate.
 
d.  
Derivative Financial Instruments
 
   
Under Canadian GAAP, the equity component of the Company’s Convertible Note and the purchase warrants were classified as shareholders’ equity. In accordance with IAS 32, “Financial Instruments: Presentation,” financial instruments with an exercise price denominated in a currency other than the Company’s functional currency are accounted for as derivatives. As a result, the equity component and purchase warrants have been reclassified as derivative financial instruments.
 
   
This resulted in the reclassification of the convertible portion of the Convertible Note and purchase from shareholders’ equity to liabilities under IFRS. Additionally, IFRS requires these items to be recorded at fair value with changes in their fair value recognized in the income statement.

 

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e.  
Share-Based Payments
 
   
Stock options were accounted for using the fair value method under Canadian GAAP and charged to operations on a straight-line basis. Under IFRS 2, “Share-Based Payment,” share-based payments are charged to operations on a graded vesting basis thereby accelerating the compensation expense recognized in earnings. Additional compensation expense was recorded for unvested stock options at January 1, 2010.
 
f.  
Depletion
 
   
Under Canadian GAAP, the Company depleted its oil and gas assets using the unit-of-production method, based on proved reserves. For IFRS purposes, the Company is depleting its oil and gas assets using the unit-of-production method, based on proved plus probable reserves. This has resulted in a deferral of depletion expense.
 
g.  
Exploration and Evaluation Expense
 
   
Under Canadian GAAP, capitalization of unsuccessful exploration activities was permitted if the carrying value of the Company’s total capitalized oil and gas properties and development was not impaired. Under IFRS, unsuccessful exploration and evaluation wells will be charged to earnings as E&E expense, including $4.9 million in Ecuador and $3.5 million in Asia in the year ended December 31, 2010.

 

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ITEM 2.  
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
With the exception of historical information, certain matters discussed in this Quarterly Report on Form 10-Q (“Form 10-Q”), including those within this Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”), are forward-looking statements that involve risks and uncertainties. Certain statements contained in this Form 10-Q, including statements which may contain words such as “anticipate,” “could,” “propose,” “should,” “intend,” “seeks to,” “is pursuing,” “expect,” “believe,” “will” and similar expressions may be indicative of forward-looking statements. Although the Company believes that its expectations are based on reasonable assumptions, forward-looking statements involve known and unknown risks and uncertainties that may cause the actual future results, performances or achievements to be materially different from management’s current expectations. These known and unknown risks and uncertainties may include, but are not limited to, the ability to raise capital as and when required, the timing and extent of changes in prices for oil and gas, competition, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and the potential success of the Company’s heavy-to-light technology, the prices of goods and services, the availability of drilling rigs and other support services, legislative and government regulations, political and economic factors in countries in which the Company operates and implementation of its capital investment program. Except as required by law, the Company undertakes no obligation to update publicly or revise any forward-looking statements contained in this report. All subsequent forward-looking statements, whether written or oral, attributable to the Company, or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.
The above items and their possible impact are discussed more fully in the sections entitled “Risk Factors” in Item 1A and “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of the Company’s 2010 Annual Report on Form 10-K (“2010 Form 10-K”).
Special Note to Canadian Investors
The Company is a registrant under the Securities Exchange Act of 1934 and voluntarily files reports with the United States Securities and Exchange Commission (“SEC”) on Form 10-K, Form 10-Q and other forms used by registrants that are US domestic issuers. Therefore, the Company’s reserves estimates and securities regulatory disclosures generally follow SEC requirements. National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), adopted by the Canadian Securities Administrators (“CSA”), prescribes certain standards for the preparation, and disclosure of reserves and related information by Canadian issuers. The Company has been granted certain exemptions from NI 51-101. Please refer to the Special Note to Canadian Investors in the 2010 Form 10-K.
Advisories
The Form 10-Q report should be read in conjunction with the Company’s March 31, 2011 unaudited condensed consolidated financial statements (the “Financial Statements”) contained herein, and the audited consolidated financial statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the 2010 Form 10-K. The Financial Statements have been prepared using accounting policies consistent with IFRS and in accordance with International Accounting Standard 34, Interim Financial Reporting (“IAS 34”). A reconciliation of the previously disclosed comparative periods’ financial statements, prepared in accordance with Canadian GAAP, to IFRS is set out in Note 23 to the Financial Statements.
As a foreign private issuer in the US, Ivanhoe is permitted to file with the SEC financial statements prepared under IFRS without a reconciliation to US GAAP. The Company will no longer prepare a reconciliation of its results to US GAAP. It is possible that some of the Company’s accounting policies under IFRS could be different from US GAAP.
Non-IFRS Financial Measures
Oil revenue per barrel is calculated by dividing oil revenue by the Company’s total production for the respective periods presented. Net operating revenue per barrel is calculated by dividing oil revenue less related operating costs by total production for the respective periods presented. Net revenue (loss) from operations per barrel is calculated by subtracting depletion from net operating revenue and dividing by total production for the respective periods presented. The Company believes oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel are important to investors to evaluate operating results and the Company’s ability to generate cash. Each of the components used in these calculations can be reconciled directly to the unaudited interim condensed consolidated statements of loss. The calculations of oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel may differ from similar calculations of other companies in the oil and gas industry, thereby limiting its usefulness as a comparative measure.

 

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THE DISCUSSION AND ANALYSIS OF THE COMPANY’S OIL AND GAS ACTIVITIES, WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES, PRESENT THE COMPANY’S NET WORKING INTEREST AFTER ROYALTIES. ALL TABULAR AMOUNTS ARE EXPRESSED IN THOUSANDS OF US DOLLARS, EXCEPT PER SHARE AND PRODUCTION DATA INCLUDING REVENUES AND COSTS PER BOE.
As generally used in the oil and gas business and throughout this Form 10-Q, the following terms have the following meanings:
                     
bbl
  =   barrel   mcf   =   thousand cubic feet
bbls/d
  =   barrels per day   mcf/d   =   thousand cubic feet per day
boe
  =   barrel of oil equivalent   mmcf   =   million cubic feet
boe/d
  =   barrels of oil equivalent per day   mmcf/d   =   million cubic feet per day
mbbls
  =   thousand barrels   mmbbls   =   million barrels
mbbls/d
  =   thousand barrels per day   mmbls/d   =   million barrels per day
mboe
  =   thousands of barrels of oil equivalent   mmbtu   =   million British thermal units
mboe/d
  =   thousands of barrels of oil equivalent per day   tcf   =   trillion cubic feet
Oil equivalents compare quantities of oil with quantities of gas or express these different commodities in a common unit. In calculating barrel of oil equivalents (boe), the generally recognized industry standard is one bbl is equal to six mcf. Boes may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Electronic copies of the Company’s filings with the SEC and the CSA are available, free of charge, through the Company’s website (www.ivanhoeenergy.com) or, upon request, by contacting its investor relations department at (403) 261-1700. Alternatively, the SEC and the CSA each maintains a website (www.sec.gov and www.sedar.com) from which the Company’s periodic reports and other public filings with the SEC and the CSA can be obtained.

 

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INTERNATIONAL FINANCIAL REPORTING STANDARDS
Transition to IFRS from Canadian GAAP
The Company adopted International Financial Reporting Standards (“IFRS”) on January 1, 2011, with a transition date of January 1, 2010. The 2010 comparative periods have been restated under IFRS. IFRS employs a conceptual framework that is similar to Canadian generally accepted accounting principles (“GAAP”), however, significant differences exist in certain matters of recognition, measurement and disclosure. The adoption of IFRS resulted in changes to the reported financial position and earnings of the Company. Reconciliations of the statements of financial position and statements of loss presented under Canadian GAAP to IFRS is included in Note 23 to the Financial Statements.
Changes made to the statements of financial position and statements of loss have resulted in reclassifications of various amounts on the statements of cash flows. Due to the reclassification of capitalized overhead under Canadian GAAP to operating costs or general and administrative (“G&A”) expenses under IFRS, cash used in investing activities under Canadian GAAP was reclassified to cash used in operating activities under IFRS. Since there was no change to the total increase in cash and cash equivalents, no reconciliation for the statements of cash flows was presented.
Initial Adoption of IFRS
i. IFRS 1 Exemptions
IFRS 1, “First-Time Adoption of International Financial Reporting Standards,” (“IFRS 1”) provides companies adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions to the general requirement for full retrospective application of IFRS where retrospective restatement would either be onerous or would not provide more useful information. As a result of relying upon the exemptions described below, there was no material change in these areas at the date of transition to IFRS in comparison to amounts previously reported under Canadian GAAP.
a) Deemed Cost
The Company elected to report oil and gas properties recorded in property, plant and equipment (“PP&E”) and exploration and evaluation (“E&E”) assets at deemed cost, instead of the actual cost as though IFRS had been adopted retroactively. The deemed cost will be the amounts previously reported under Canadian GAAP.
b) Decommissioning Provisions Included in the Cost of Property, Plant and Equipment
The exemption provided in IFRS 1 from the full retrospective application of IFRIC 1 “Changes in Existing Decommissioning, Restoration and Similar Liabilities” was applied to decommissioning liabilities associated with our oil and gas properties recorded in PP&E and intangible assets. The Company elected to re-measure its feedstock test facility (“FTF”) decommissioning provision under IFRS.
c) Share-Based Payment
The Company elected to apply the share-based payment exemption and has applied IFRS 2, “Share-based Payment” only to those stock options that were issued after November 7, 2002, but that had not vested by the January 1, 2010 transition date.
d) Business Combinations
The Company applied the business combinations exemption in IFRS 1 and has not restated business combinations that took place prior to the January 1, 2010 transition date.
e) Leases
The Company applied the lease exemption in IFRS 1 for contracts and agreements entered into before January 1, 2010. Where Ivanhoe has, under Canadian GAAP, made the same determination of whether an arrangement contains a lease as required by IFRIC 4, “Determining whether an Arrangement contains a Lease,” but that assessment was made at a date other than that required by IFRIC 4, the Company elected not to reassess that determination.

 

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ii. Impact on Adoption of IFRS on Financial Reporting
The conversion to IFRS will result in differences in recognition, measurement and disclosure of balances and transactions in the Financial Statements. Certain amounts previously reported under Canadian GAAP have been reclassified to conform with IFRS presentation standards. Restricted cash was combined with cash and cash equivalents and the Company’s asset retirement obligations was combined with other long term provisions. Other name changes have been made to certain financial statement line items to conform with the IFRS format standards.
The accounting policies and financial statement accounts of the Company that are materially affected by the adoption of IFRS are discussed below.
a) Reclassification of Intangible Assets
Under Canadian GAAP, oil and gas properties in the exploration and evaluation stage were classified as oil and gas properties and development costs. In accordance with IFRS 6, these properties were reclassified as intangible assets. As a result, $197.2 million of assets at December 31, 2010, were moved from PP&E to intangible assets.
b) Adjustment for Capitalized Overhead
Under Canadian GAAP, the Company capitalized employee benefits and overhead that were directly attributable to E&E assets and PP&E. A portion of the amounts capitalized under Canadian GAAP does not meet the threshold for capitalization under IAS 16, “Property, Plant and Equipment.” Therefore, for the year ending December 31, 2010, $2.0 million and $7.5 million of costs previously classified as PP&E and intangible assets, respectively, under Canadian GAAP were reclassified as operating costs or G&A expenses under IFRS.
c) Decommissioning Provisions
Under Canadian GAAP, the present value of the Company’s estimated future decommissioning costs was calculated using a credit-adjusted risk-free discount rate. The discount rate under IFRS does not permit company specific credit adjustments and therefore the decommissioning provision is now calculated using a risk-free discount rate. This has resulted in an increase of $0.4 million to PP&E and intangible assets with a corresponding increase to long term provisions at December 31, 2010.
d) Derivative Financial Instruments
Under Canadian GAAP, the equity component of the Company’s Cdn$40.0 million convertible promissory note (the “Convertible Note”) and the purchase warrants were classified as shareholders’ equity. In accordance with IAS 32, “Financial Instruments: Presentation,” financial instruments with an exercise price denominated in a currency other than the Company’s functional currency are accounted for as derivatives. Consequently, the equity component of the Convertible Note and the purchase warrants have been reclassified as derivative financial instruments.
At December 31, 2010, this resulted in the reclassification of the $2.1 million equity component of the Convertible Note and the $33.4 million value of the purchase warrants from shareholders’ equity under Canadian GAAP to liabilities under IFRS. Additionally, IFRS requires these items to be recorded at fair value with changes in their fair value recognized in earnings, creating a $18.6 million gain under IFRS in 2010.
e) Share-Based Payments
Stock options were accounted for using the fair value method under Canadian GAAP and charged to operations on a straight-line basis. Under IFRS 2, “Share-Based Payment,” share-based payments will be charged to operations on a graded vesting basis thereby accelerating the compensation expense recognized in earnings. Additional compensation expense of $1.5 million was recorded for unvested stock options in 2010 under IFRS.
f) Depletion
Under Canadian GAAP, the Company depleted its oil and gas assets using the unit-of-production method, based on proved reserves. For IFRS purposes, the Company is depleting its oil and gas assets using the unit-of-production method, based on proved plus probable reserves. This resulted in a $2.4 million reduction in depletion expense in 2010 and a $2.4 million increase in PP&E at December 31, 2010.
g) Exploration and Evaluation Expense
Under Canadian GAAP, capitalization of unsuccessful exploration activities was permitted if the carrying value of the Company’s total capitalized oil and gas properties and development costs was not impaired. Under IFRS, unsuccessful exploration and evaluation wells are charged to earnings as E&E expense, including $4.9 million in Ecuador and $3.5 million in Asia in the year ended December 31, 2010.

 

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iii. Impact of IFRS on Financial Reporting in the Future
While the adoption of IFRS will not change the actual cash flows of the Company, the adoption will continue to impact the reported financial position and earnings of the Company in the future, such as those outlined below.
a) Intangible Assets
Future expenditures of a capital nature will be recorded as additions to PP&E or intangible assets, depending upon the project. When sufficient reserves to justify commercial production are established, the project will be reclassified from intangible assets to PP&E on the statement of financial position.
b) Adjustment for Capitalized Overhead
The higher threshold for capitalization of directly attributable costs under IFRS will result in less capitalization of G&A costs under IFRS than under Canadian GAAP and operating or G&A costs will increase as a result.
c) Derivative Financial Instruments
IFRS requires changes in the fair value of derivative financial instruments to be recognized in operations. If the Company continues to hold derivative financial instruments, this will create non-cash volatility in future earnings.
e) Share-Based Payments
Since share-based payments are recorded on a graded vesting basis under IFRS, the compensation expense for any future stock option grants will be recognized in earnings earlier than under Canadian GAAP.
f) Depletion
Depleting oil and gas assets on a unit-of-production basis using proved plus probable reserves under IFRS, rather than proved reserves under Canadian GAAP, will reduce the depletion expense recorded in a particular period. However, the total associated PP&E to be depleted over the life of a project will remain the same.
g) Exploration and Evaluation Expense
Under IFRS, any unsuccessful exploration activities in the future will be recorded as an E&E expense, impacting the Company’s earnings.
HIGHLIGHTS
                 
Three months ended March 31, ($000, except as stated)   2011     2010  
Average daily production (bbls/d)
    1,007       804  
Realized oil prices ($/bbl)
    89.62       73.63  
Oil revenue
    8,119       5,330  
Capital expenditures
    14,311       23,900  
 
             
Cash flow used in operating activities
    (6,508 )     (5,431 )
Net loss
    (11,126 )     (6,805 )
Net loss per share, basic and diluted
    (0.03 )     (0.02 )
Oil production increased in the first quarter of 2011 as Ivanhoe received additional volumes to offset capital expenditures incurred at Dagang. Additional production in combination with stronger realized prices, resulted in higher oil revenue for the Company in the current quarter. The net loss in the first quarter of 2011 was $11.1 million, compared to a loss of $6.8 million in the prior period, due to higher operating and general administrative expenses, which were partially offset by non-cash foreign currency exchange and derivative instrument gains.
Capital expenditures totaled $14.3 million in the three months ended March 31, 2011. At the Company’s Zitong Block in China’s Sichuan Province, testing operations were performed on the Xu-4 and Xu-5 formations of the Zitong-1 gas well. The Yixin-2 gas well was tested in the Xu-4 formation and the well was prepared for fracture stimulation. At Dagang, one well was drilled and completed and a well spudded in 2010 was completed. The fracture stimulation program at Dagang also continued during the quarter.
In Canada, discussions with the provincial regulatory authorities continued, as well as consultations with key stakeholders, in connection with the Company’s Environmental Impact Assessment for the Tamarack Project. In Ecuador, preparations were undertaken for a seismic program designed to increase our understanding of the geological faulting in the area and to help determine locations for our next appraisal wells.

 

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RESULTS OF OPERATIONS
                 
Three Months Ended March 31,   2011     2010  
Asia (net bbls)
               
Dagang
    86,865       67,794  
Daqing
    3,734       4,602  
 
           
Total production
    90,599       72,396  
 
           
Average daily production (bbls/d)
    1,007       804  
 
               
Pricing
               
Average realized oil price ($/bbl)
    89.62       73.63  
West Texas Intermediate (WTI) ($/bbl)
    93.92       78.71  
Oil Revenue
Ivanhoe’s oil revenue in the three months ended March 31, 2011, increased from the prior period due to a combination of higher production volumes and stronger realized prices. Oil production from the Dagang field in China was relatively constant. However, the terms of the Company’s production sharing contract at Dagang with China National Petroleum Corporation (“CNPC”) stipulate that capital expenditures are to be funded 100% by Ivanhoe and CNPC’s portion of the costs are reimbursed through the receipt of additional oil sales. Due to increased capital activity at Dagang in the first quarter of 2011, additional oil production was allocated to Ivanhoe.
Net Revenue from Operations
                 
Three Months Ended March 31, ($/bbl)   2011     2010  
Oil revenue(1)
    89.62       73.63  
Less operating costs
               
Field operating
    (17.92 )     (18.45 )
Windfall Levy
    (17.39 )     (11.20 )
Engineering and support costs
    (1.21 )     (1.77 )
 
           
Net operating revenue(1)
    53.10       42.21  
Depletion
    (17.42 )     (23.70 )
 
           
Net revenue (loss) from operations(1)
    35.68       18.51  
 
           
     
(1)  
Oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel do not have standardized meanings prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-IFRS Financial Measures under the Advisories section in the MD&A for more details.
Operating Costs
                 
Three months ended March 31,   2011     2010  
Asia
               
Field operating
    1,623       1,297  
Windfall levy
    1,577       811  
Engineering support
    110       128  
 
           
 
    3,310       2,236  
 
               
Technology Development
               
FTF operating costs
    1,213       1,218  
 
           
Total operating costs
    4,523       3,454  
 
           
Operating costs in China rose $1.0 million in the three months ended March 31, 2011 over the comparable period primarily due to an increase in the Windfall Levy administered by the People’s Republic of China. Field operating costs in total increased over the prior period due to additional production volumes. However, on a per barrel basis, field operating costs decreased slightly due to a reduction in maintenance and power expenses as a result of installing variable frequency drives at Dagang in the fourth quarter of 2010.

 

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Operating costs in the Technology Development segment are incurred at the Company’s FTF at the Southwest Research Institute in San Antonio, Texas. Costs in the three months ended March 31, 2011, were consistent with the first quarter of 2010.
Exploration and Evaluation
E&E expenses were nil in the three months ended March 31, 2011. Following the drilling of the Zitong-1 and Yixin-2 wells, areas excluding those identified for development and future production were to be relinquished at the end of 2010. As a result, $0.6 million of geological costs incurred in prior periods were expensed as E&E costs in the first quarter of 2010.
General and Administrative
G&A expenses were higher in the three months ended March 31, 2011, in comparison to the prior year as a result of higher staff and office costs incurred with the Company’s growing commitments to its projects around the world.
Depletion and Depreciation
Depletion and depreciation in the three months ended March 31, 2011 increased compared to 2010. Depreciation of the FTF was higher in the current quarter compared to 2010, as revisions to FTF salvage values lowered depreciation in the first quarter of 2010. This was partially offset by lower depletion in Asia in the current quarter as a result of additional Dagang proved and probable reserves at January 1, 2011.
Foreign Exchange
Ivanhoe incurred a smaller foreign exchange gain in the first three months of 2011 compared to the prior period. At March 31, 2010, a foreign exchange gain was created primarily by the translation of the Company’s Canadian dollar cash balance into US dollars. Although the Canadian dollar has continued to strengthen in comparison to the US dollar, Ivanhoe’s cash balance was lower at March 31, 2011, and the foreign exchange gain in the current quarter was largely offset by foreign exchange losses on the Company’s Canadian dollar debt and accounts payable balances.
Derivative Instruments
In the first three months of 2011, the Company incurred a gain of $1.1 million on its derivative liabilities. The revaluation of the Company’s purchase warrants resulted in a net gain of $0.3 million and the expiry of purchase warrants during the quarter created a gain of $1.5 million.
Due to the impending maturity of the Convertible Note, a gain of $0.5 was recognized on the revaluation of the convertible portion at March 31, 2011.
In January 2010, one of the Company’s subsidiaries granted a private investor an option (the “Subsidiary Option”) to acquire an equity interest in the subsidiary representing 20% of the subsidiary’s currently issued share capital (16.67% of the enlarged share capital immediately following the exercise of the Subsidiary Option) for Cdn$25.0 million. If the Subsidiary Option is exercised, Cdn$25 million of existing inter-corporate indebtedness owed by the subsidiary to the Company (through an intermediate subsidiary) will be converted into additional common shares of the subsidiary, thereby diluting the private investor’s equity interest to 14.286%. The fair value of the Subsidiary Option, calculated using the Black Scholes option pricing model, used an estimated share value and assumed the volatility to be similar to Ivanhoe. The revaluation of the Subsidiary Option created a non-realized loss of $1.2 million in the first quarter of 2011.
Provision for Income Taxes
During the first quarter of 2011, current taxes of $0.3 million were incurred in China. Ivanhoe incurred a future tax expense of $0.6 million due to increases in the deferred tax liability in China, net of operating loss carryforwards, which was partially offset by continuing operating loss carryforwards in the US.

 

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LIQUIDITY AND CAPITAL RESOURCES
Contractual Obligations
The following information about our contractual obligations and other commitments summarizes certain liquidity and capital resource requirements. The information presented in the table below does not include planned, but not legally committed, capital expenditures or obligations that are discretionary and/or being performed under contracts which can be terminated on 30 days notice. Previous exploration commitments in Zitong and Nyalga have been fulfilled and therefore are not included below.
                                                 
    Total     2011     2012     2013     2014     After 2014  
Debt
    41,256       41,256                            
Interest
    1,029       1,029                          
Decommissioning provisions(1)
    2,007                   342             1,665  
Long term obligation
    1,900                               1,900  
Lease commitments
    2,525       1,372       886       267              
 
                                   
 
    48,717       43,657       886       609             3,565  
 
                                   
     
(1)  
Represents undiscounted asset retirement obligations after inflation. The discounted value of these estimated obligations is provided for in the Financial Statements.
Debt
As described in Note 8 to the Financial Statements, the Company issued a Cdn$40.0 million Convertible Note maturing in July 2011. The outstanding principal amount is convertible, at Talisman’s option, into a maximum of 12,779,552 Ivanhoe common shares at Cdn$3.13 per common share. Interest at the prime rate plus 2% is calculated daily and payable semi-annually. The estimated interest payments on the Convertible Note are included in the above table.
Decommissioning Provisions
The Company is required to remedy the effect of our activities on the environment at our operating sites by dismantling and removing production facilities and remediating any damage caused. At March 31, 2011, we estimated the total undiscounted, inflated cost to settle our asset retirement obligations in Canada, for the FTF and in Ecuador was $2.0 million. These costs are expected to be incurred in 2013, 2029 and 2038 respectively. Ivanhoe does not make such a provision for decommissioning costs in connection with its oil and gas operations in China as dry holes are abandoned as they occur and the Company is under no obligation to contribute to the future costs to restore well sites or abandon the field.
Long Term Obligation
As part of its 2005 merger with Ensyn, the Company assumed an obligation to pay $1.9 million in the event that proceeds from the sale of units incorporating the HTL™ technology for petroleum applications reach a total of $100.0 million.
Operating Leases
We have long term operating leases for office space, which expire between 2011 and 2013.
Other
The Company may be required to make a payment of up to Cdn$15 million if, and when, the requisite governmental and other approvals are received to develop the northern border of one of of the Tamarack leases.
From time to time, Ivanhoe enters into consulting agreements whereby a success fee may be payable if and when either a definitive agreement is signed or certain other contractual milestones are met. Under the agreements, the consultant may receive cash, common shares, stock options or some combination thereof. These fees are not considered to be material.
The Company may provide indemnities to third parties, in the ordinary course of business, that are customary in certain commercial transactions, such as purchase and sale agreements. The terms of these indemnities will vary based upon the contract, the nature of which prevents Ivanhoe from making a reasonable estimate of the maximum potential amounts that may be required to be paid. The Company’s management is of the opinion that any resulting settlements relating to indemnities are not likely to be material.

 

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In the normal course of business, we are subject to legal proceedings being brought against us. While the final outcome of these proceedings is uncertain, we believe that these proceedings, in the aggregate, are not reasonably likely to have a material effect on our financial position or earnings.
Sources and Uses of Cash
The Company’s cash flows from operating, investing and financing activities, as reflected in the unaudited condensed consolidated statements of cash flow, are summarized in the following table:
                 
Three Months Ended March 31,   2011     2010  
Cash used in operating activities
    (6,508 )     (5,431 )
Cash used in investing activities
    (11,985 )     (23,368 )
Cash provided by financing activities
    29,795       137,957  
Ivanhoe’s cash flow from operating activities is not sufficient to meet its operating and capital obligations over the next twelve months. The Company intends to use its working capital to meet its commitments. However, additional sources of funding will be required to grow the Company’s major projects and fully develop its oil and gas properties, either at a parent company level or at a project level. Historically, Ivanhoe has used external sources of funding such as public and private equity and debt markets. However, there is no assurance that these sources of funding will be available to the Company in the future on acceptable terms, or at all.
Operating Activities
In the three months ended March 31, 2011, cash used in operating activities was higher than in 2010 as additional operating costs and G&A expenses were only partially offset by higher revenue in the current quarter.
Investing Activities
E&E Expenditures
E&E expenditures in the first quarter of 2011 totaled $10.4 million. At the Company’s Zitong Block in China’s Sichuan Province, testing operations were performed on the Xu-4 and Xu-5 formations of the Zitong-1 gas well. The Yixin-2 gas well was tested in the Xu-4 formation and the well has been prepared for fracture stimulation. In the Nyalga basin of Mongolia, preparations for a seismic acquisition program are underway.
In Canada, discussions with the provincial regulatory authorities are ongoing as well as consultation with key stakeholders in connection with the Company’s Environmental Impact Assessment for the Tamarack Project.
In Ecuador, preparations began for the seismic survey of Block 20. The seismic program is essential to defining the location and orientation of fault blocks that exist due to the close proximity of the Andes Mountains, directly west of Block 20.
PP&E Expenditures
In the first three months of 2011, PP&E additions totaled $3.9 million. At Dagang, one well was drilled and completed and a well spudded in 2010 was completed. The fracture stimulation program at Dagang also continued during the quarter.
Financing Activities
Cash provided by financing activities was lower in the three months ended March 31, 2011 than in the prior period. In the first quarter of 2011, cash proceeds of $29.8 million were raised through the exercise of purchase warrants and stock options. In the first quarter of 2010, the Company raised $136.3 million, net of issuance costs, through a private placement of 50 million special warrants at a price of Cdn$3.00 per special warrant.

 

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Capital Structure
                 
    March 31,     December 31,  
As at   2011     2010  
Debt
    40,985       39,832  
Shareholders’ equity
    324,055       300,484  
Ivanhoe intends to use its cash and cash equivalent balance to fulfill its commitments and partially fund operations in 2011. Cash flow may be insufficient to meet operating requirements in the next twelve months and additional sources of funding, either at a parent company level or at a project level, will be required to grow the Company’s major projects and fully develop its oil and gas properties. Historically, Ivanhoe has used external sources of funding, such as public and private equity and debt markets. There is no assurance that we will be able to obtain additional financing on favorable terms, if at all, and any future equity issuances may be dilutive to our current investors. If we cannot secure additional financing, we may have to delay our capital programs and forfeit or dilute our rights in existing oil and gas property interests.
Outlook for 2011
In the upcoming months, Ivanhoe anticipates completing a fracture stimulation program at the Zitong-1 and Yixin-2 gas wells in China. Following initial testing, the wells will be available to be tied-in to the local gas gathering system. The Company is currently drafting a provisional overall development plan for the Zitong Block and will submit this plan to PetroChina by the end of June 2011. The plan will provide PetroChina with a conceptual overview of activities proposed to develop the natural gas opportunities across the Zitong Block.
In Mongolia, activities will continue in preparation for a 2D seismic program and the drilling of two exploration wells. The Company also plans to commence a seismic program in Ecuador, starting in the southern portion of Block 20 to increase our understanding of the geological faulting and to determine locations for future appraisal wells.
Minor expenditures may be necessary for development costs relating to the enhancement of the Company’s HTLTM upgrading process. The Company is continuing to pursue ongoing discussions related to other HTLTM heavy oil and selected conventional oil opportunities in North and South America, the Middle East and North Africa.
Management’s plans for financing future expenditures include traditional project financing, debt and mezzanine financing or the sale of equity securities as well as the potential for alliances or other arrangements with strategic partners. Discussions with potential strategic partners are focused primarily on national oil companies and other sovereign or government entities from Asian and Middle Eastern countries that have approached Ivanhoe and expressed interest in participating in the Company’s heavy oil activities in Ecuador, Canada and around the world. However, no assurances can be given that Ivanhoe will be able to enter into one or more strategic business alliances with third parties or that the Company will be able to raise sufficient additional capital. If the Company is unable to enter into such business alliances or obtain adequate additional financing, the Company may be required to curtail its operations, which may include the sale of assets.

 

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ITEM 4.  
CONTROLS AND PROCEDURES
The Company’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 2011. Based upon this evaluation, management concluded that these controls and procedures were (1) designed to ensure that material information relating to the Company is made known to the Company’s Chief Executive Officer and Chief Financial Officer as appropriate to allow timely decisions regarding disclosure and (2) effective, in that they provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
It should be noted that while the Company’s Chief Executive Officer and Chief Financial Officer believe that the Company’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Company’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
There were no changes in the Company’s internal control over financial reporting in the quarter ended March 31, 2011, that have materially affected, or are reasonably likely to have a material effect on the Company’s internal control over financial reporting.
PART II OTHER INFORMATION
ITEM 1.  
LEGAL PROCEEDINGS
The Company is a defendant in a lawsuit filed on November 20, 2008, in the United States District Court for the District of Colorado by Jack J. Grynberg and three affiliated companies. The suit alleged bribery and other misconduct and challenged the propriety of a contract awarded to the Company’s wholly-owned subsidiary Ivanhoe Energy Ecuador Inc. to develop Ecuador’s Pungarayacu heavy oil field. The plaintiff’s claims were for unspecified damages or ownership of the Company’s interest in the Pungarayacu field. The Company and related defendants filed motions to dismiss the lawsuit for lack of jurisdiction. The Court granted the motion and dismissed the case without prejudice. The Court granted Mr. Robert Friedland’s request to sanction plaintiffs and plaintiffs’ counsel for their conduct related to bringing the suit by awarding Mr. Friedland fees and costs. The Ivanhoe corporate defendants, including the Company, have been awarded their costs in defending the suit and have requested an award of attorneys’ fees.
On October 16, 2009, the plaintiffs filed a motion requesting that the Court vacate its judgment and allow discovery on jurisdictional issues on the grounds that plaintiffs had discovered new evidence. On July 15, 2010, the Court denied the plaintiffs’ motion to vacate the judgment. The request for attorneys’ fees remains pending before the Court. On August 13, 2010, the plaintiffs filed a notice of appeal challenging the district court’s judgment and some of its orders. The appeal is currently pending in the United States Court of Appeals for the Tenth Circuit. Briefing on the appeal is complete; the plaintiffs have filed an opening and reply brief and the Company and related defendants have filed a response brief. The Court has set oral arguments on the appeal for May 9, 2011, in Denver, Colorado. The likelihood of loss or gain resulting from the lawsuit, and the estimated amount of ultimate loss or gain, are not determinable or reasonably estimable at this time.
On December 30, 2010, the Company received a demand for arbitration from GAR Energy and Associates, Inc. (“GAR Energy”) and Gonzalo A. Ruiz and Janis S. Ruiz as successors in interest to and assignees of GAR Energy. GAR Energy subsequently abandoned its demand for arbitration and filed suit against the Company in the Superior court for Kern County, California. The lawsuit alleges breach of contract, fraud and other misconduct arising from a consulting agreement and various other agreements between GAR Energy and the Company relating to the Pungarayacu heavy oil field. The Plaintiffs seek actual damages of $250,000, a portion of the Company’s interest in the Pungarayacu field and other miscellaneous relief. Although the lawsuit was filed March 11, 2011, the Company has yet to receive service of the complaint, meaning there is no current schedule for the Company’s responsive filing. The likelihood of loss or gain resulting from this dispute, and the estimated amount of ultimate loss or gain, are not determinable or reasonably estimable at this time.

 

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ITEM 6.  
EXHIBITS
         
Exhibit Number   Description
       
 
  10.1    
Warrant Indenture Amendment Agreement
       
 
  10.2    
Warrant Indenture Amendment Agreement
       
 
  31.1    
Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
       
 
  31.2    
Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
       
 
  32.1    
Certification by the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
       
 
  32.2    
Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.
         
IVANHOE ENERGY INC.    
 
       
By:
  /s/ Gerald D. Schiefelbein
 
Gerald D. Schiefelbein
   
 
  Chief Financial Officer    
 
       
Date:
  May 10, 2011    

 

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