Form 10-Q
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 September 30, 2011
Commission file number: 000-30586
 
(IVANHONE 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 October 31, 2011, Ivanhoe Energy Inc. had 344,139,428 Common Shares outstanding with no par value.
 
 

 

 


 

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 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)
                                 
            September 30,     December 31,     January 1,  
(US$000s)   Notes     2011     2010     2010  
 
                               
Assets
                               
Current Assets
                               
Cash and cash equivalents
    3       58,168       68,317       24,362  
Accounts receivable
            8,248       6,359       5,021  
Note receivable
            222       264       225  
Prepaid and other
            690       2,859       771  
 
                         
 
            67,328       77,799       30,379  
 
                               
Intangible
    4       310,430       273,568       207,750  
Property, plant and equipment
    5       46,966       40,618       41,983  
Long term receivables
            3,723       2,433       839  
 
                         
 
            428,447       394,418       280,951  
 
                         
 
                               
Liabilities and Shareholders’ Equity
                               
Current Liabilities
                               
Accounts payable and accrued liabilities
            23,032       21,482       10,779  
Debt
    6             39,832        
Derivative instruments
    7       286       8,447       13,023  
Income taxes
            734             530  
Decommissioning costs
                        753  
 
                         
 
            24,052       69,761       25,085  
 
                               
Long term debt
    6       60,146             36,934  
Long term derivative instruments
    7       1,810              
Long term provisions
            1,366       3,008       2,187  
Deferred income taxes
            21,901       21,165       22,336  
 
                         
 
            109,275       93,934       86,542  
 
                         
 
                               
Shareholders’ Equity
                               
Share capital
    10       586,108       550,562       422,322  
Contributed surplus
    11       25,677       23,141       18,724  
Accumulated deficit
            (292,613 )     (273,219 )     (246,637 )
 
                         
 
            319,172       300,484       194,409  
 
                         
 
            428,447       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     Nine Months Ended  
            September 30,     September 30,  
(US$000s, except share and per share amounts)   Note     2011     2010     2011     2010  
 
                                       
Revenue
                                       
Oil
            10,769       4,177       28,277       15,554  
Interest
            219       88       429       130  
 
                               
 
            10,988       4,265       28,706       15,684  
 
                               
 
                                       
Expenses
                                       
Operating
    13       5,489       2,996       15,351       9,702  
Exploration and evaluation
    4       2,143       788       2,143       2,378  
General and administrative
            12,239       10,898       37,400       28,423  
Depletion and depreciation
    5       2,131       1,490       5,853       4,948  
Foreign currency exchange gain
            (670 )     (1,188 )     (1,133 )     (2,289 )
Derivative instruments gain
    7       (5,429 )     (622 )     (12,629 )     (20,405 )
Interest
            431       4       798       12  
Gain on derecognition of long term provision
            (1,900 )           (1,900 )      
 
                               
 
            14,434       14,366       45,883       22,769  
 
                               
 
                                       
Loss before income taxes
            (3,446 )     (10,101 )     (17,177 )     (7,085 )
 
                                       
(Provision for) recovery of income taxes
                                       
Current
            (682 )           (1,481 )     (115 )
Deferred
            (29 )     496       (736 )     49  
 
                               
 
            (711 )     496       (2,217 )     (66 )
 
                               
 
                                       
Net loss and comprehensive loss
            (4,157 )     (9,605 )     (19,394 )     (7,151 )
 
                               
 
                                       
Net loss per common share
                                       
Basic and diluted
            (0.01 )     (0.03 )     (0.06 )     (0.02 )
 
                               
 
                                       
Weighted average number of common shares (000s)
                                       
Basic and diluted
            338,592       334,012       342,173       325,153  
 
                               
(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
                              (7,151 )     (7,151 )
Shares issued for cash, net of share issue costs
            50,000       121,697                   121,697  
Shares issued for services
            280       799                   799  
Exercise of stock options
    11       1,171       4,323       (2,225 )           2,098  
Exercise of purchase warrants
            2       9                   9  
Share-based compensation expense
    11                   3,811             3,811  
 
                                     
Balance September 30, 2010
            334,012       549,150       20,310       (253,788 )     315,672  
 
                                     
 
                                               
            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
                              (19,394 )     (19,394 )
Shares issued for services
            169       335                   335  
Exercise of stock options
    11       984       4,164       (2,231 )           1,933  
Exercise of purchase warrants
            8,621       31,047                   31,047  
Share-based compensation expense
    11                   4,767             4,767  
 
                                     
Balance September 30, 2011
            344,139       586,108       25,677       (292,613 )     319,172  
 
                                     
(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     Nine Months Ended  
            September 30,     September 30,  
(US$000s)   Note     2011     2010     2011     2010  
 
                                       
Operating Activities
                                       
Net loss
            (4,157 )     (9,605 )     (19,394 )     (7,151 )
Adjustments to reconcile net loss to cash from operating activities
                                       
Depletion and depreciation
    5       2,131       1,490       5,853       4,948  
Share-based compensation expense
    11       1,680       1,379       4,927       3,811  
Unrealized foreign currency exchange (gain) loss
            636       (1,496 )     (1,144 )     (2,834 )
Unrealized gain on derivative instruments
    7       (5,429 )     (622 )     (12,629 )     (20,405 )
Current income tax expense
            682             1,481       115  
Deferred income tax expense (recovery)
            29       (496 )     736       (49 )
Exploration and evaluation expense
    4       2,143       788       2,143       2,378  
Interest expense
            431       4       798       12  
Finance costs
                        269        
Derecognition of long term provision
            (1,900 )           (1,900 )      
Other
            25       (2 )     13        
Current income tax paid
            (423 )     (8 )     (747 )     (646 )
Decommissioning costs settled
                  3             (179 )
Changes in non-cash working capital items
    14       (1,062 )     652       916       380  
 
                               
Net cash used in operating activities
            (5,214 )     (7,913 )     (18,678 )     (19,620 )
 
                               
 
                                       
Investing Activities
                                       
Intangible expenditures
            (12,368 )     (16,654 )     (36,140 )     (50,794 )
Property, plant and equipment expenditures
            (4,475 )     (821 )     (11,938 )     (3,056 )
Long term receivables
            (845 )     (442 )     (1,308 )     (1,288 )
Interest paid
            (1,039 )     (790 )     (2,042 )     (1,634 )
Changes in non-cash working capital items
    14       (4,254 )     854       324       3,709  
 
                               
Net cash used in investing activities
            (22,981 )     (17,853 )     (51,104 )     (53,063 )
 
                               
 
                                       
Financing Activities
                                       
Shares and warrants issued on private placements, net of share issue costs
                  (69 )           135,696  
Convertible debentures issued, net of issue costs
    6                   72,914        
Repayment of convertible note
    6       (41,421 )           (41,421 )      
Proceeds from exercise of options and warrants
    8, 11             8       29,873       2,102  
Changes in non-cash working capital items
    14       104       (41 )     57       (2 )
 
                               
Net cash provided by (used in) financing activities
            (41,317 )     (102 )     61,423       137,796  
 
                               
 
                                       
Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency
            (5,628 )     2,299       (1,790 )     3,623  
 
                               
Increase (decrease) in cash and cash equivalents, for the period
            (75,140 )     (23,569 )     (10,149 )     68,736  
Cash and cash equivalents, beginning of period
            133,308       116,667       68,317       24,362  
 
                               
Cash and cash equivalents, end of period
            58,168       93,098       58,168       93,098  
 
                               
(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 September 30, 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 September 30, 2011, Ivanhoe had an accumulated deficit of $292.6 million and working capital of $43.6 million excluding derivative financial liabilities. For the nine months ended September 30, 2011, cash used in operating activities was $18.7 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 or obtain it on favorable terms. 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 September 30, 2011 Financial Statements were approved by the Board of Directors and authorized for issue on October 25, 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”, 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.
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 17. The accounting policies adopted by Ivanhoe as a result of IFRS may be found in Note 3 of the Company’s March 31, 2011 financial statements.
The Financial Statements have been prepared on an historical cost basis, except derivative instruments, which are measured at fair value.
The Company has reviewed new and revised accounting pronouncements listed below, that have been issued, but are not yet effective. The Company has not yet evaluated the impact of these changes on its financial statements.

 

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IFRS 9 Financial Instruments (“IFRS 9”)
IFRS 9 was issued in November 2009 and is intended to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”) in phases. IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, as opposed to the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments given its business model and the contractual cash flow characteristics of the financial assets. The standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39. IFRS 9 is effective for reporting periods beginning on or after January 1, 2013. On 4 August 2011, the IASB issued an exposure draft proposing to change the mandatory effective date of IFRS 9 to annual periods beginning on or after January 1, 2015.
IFRS 10 Consolidated Financial Statements (“IFRS 10”)
IFRS 10 was issued in May 2011 and sets a single basis for consolidation, that being control of an entity. IFRS 10 replaces portions of IAS 27, “Consolidated and Separate Financial Statements” that address how entities should prepare consolidated financial statements. This standard is effective for reporting periods on or after January 1, 2013, with earlier adoption permitted.
IFRS 11 Joint Arrangements (“IFRS 11”)
IFRS 11, issued in May 2011, establishes principles for financial reporting by entities involved in a joint arrangement. IFRS 11 supersedes the current IAS 31, “Interests in Joint Ventures” and Standing Interpretations Committee (“SIC”) 13, “Jointly Controlled Entities-Non Monetary Contributions by Venturers” and is effective for reporting periods beginning on or after January 1, 2013. Earlier application is permitted.
IFRS 12 Disclosure of Interests in Other Entities (“IFRS 12”)
IFRS 12, issued in May 2011, establishes a single set of disclosure objectives, and requires minimum disclosures designed to meet those objectives, regarding interests in subsidiaries, joint arrangements, associates or unconsolidated structured entities. IFRS 12 is intended to combine the disclosure requirements on interests in other entities currently located throughout different standards. This standard is effective for reporting periods on or after January 1, 2013, with earlier adoption permitted.
IFRS 13 Fair Value Measurements (“IFRS 13”)
IFRS 13, issued in May 2011, defines fair value, sets out a single IFRS framework for measuring fair value and requires disclosures about fair value measurements. IFRS 13 applies to IFRS that require or permit fair value measurements or related disclosures, except in specified circumstances. IFRS 13 is to be applied for reporting periods beginning on or after January 1, 2013. Earlier application is permitted.
IAS 12 Income Taxes (“IAS 12”)
IAS 12 was amended in December 2010 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset. The amendment introduces a presumption that an entity will assess whether or not the carrying value of an asset will be recovered through the sale of the asset. The amendment to IAS 12 is effective for reporting periods beginning on or after January 1, 2012.
IAS 28 Investments in Associates and Joint Ventures (“IAS 28”)
IAS 28 was amended in 2011 which prescribes the accounting for investments in associates and sets out the requirements for the application of the equity method when accounting for investments in associates and joint ventures. IAS 28 is effective for reporting periods beginning on or after January 1, 2013. Earlier application is permitted.
There are no other standards or interpretations in issue, but not yet adopted, that are anticipated to have a material effect on the reported loss or net assets of the Company.

 

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3. CASH AND CASH EQUIVALENTS
                         
    September 30,     December 31,     January 1,  
    2011     2010     2010  
Cash at banks and on hand
    57,145       10,147       6,797  
Term deposits
          57,670        
Money market accounts
                14,715  
Restricted cash
    1,023       500       2,850  
 
                 
 
    58,168       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.
4. INTANGIBLE ASSETS
                                                 
    Exploration and Evaluation Assets             Total  
                    Latin             HTLTM     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
    21,974       7,481       9,550       39,005             39,005  
Exploration and evaluation expense
    (2,143 )                 (2,143 )           (2,143 )
 
                                   
Balance September 30, 2011
    57,966       131,236       29,075       218,277       92,153       310,430  
 
                                   
Amortization of the Heavy-to-Light (“HTLTM”) technology has not commenced and its carrying value had not been impaired since it was acquired in 2005.
In the nine months ended September 30, 2011, $1.7 million (year ended December 31, 2010 — $2.1 million) in direct and incremental employee benefits attributable to E&E assets were capitalized.

 

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5. 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
    11,015                   11,015       1,190       12,205  
Disposals
                            (5 )     (5 )
 
                                   
Balance September 30, 2011
    46,954                   46,954       14,194       61,148  
 
                                   
 
                                               
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
    5,032                   5,032       821       5,853  
Disposals
                            (1 )     (1 )
 
                                   
Balance September 30, 2011
    11,228                   11,228       2,954       14,182  
 
                                   
 
                                               
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 September 30, 2011
    35,726                   35,726       11,240       46,966  
 
                                   
Oil and Gas Property and Equipment
In the nine months ended September 30, 2011, nil (year ended December 31, 2010 — $0.1 million) in employee benefits directly attributable to property, plant and equipment (“PP&E”) were capitalized.
Other Assets
Other assets include the Company’s Feedstock Test Facility (“FTF”) at the Southwest Research Institute in San Antonio, Texas, and general furniture and fixtures.
6. DEBT
6.1 Convertible Note
                         
    September 30,     December 31,     January 1,  
    2011     2010     2010  
Convertible note
          40,217       38,005  
Unamortized discount
          (385 )     (1,071 )
 
                 
Carrying amount
          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”). The Convertible Note matured on July 11, 2011 and was repaid in full.
In the nine months ended September 30, 2011, $1.5 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 and nine months ended September 30, 2011 (three months and nine months ended September 30, 2010 — nil).

 

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6.2 Convertible Debentures
                         
    September 30,     December 31,     January 1,  
    2011     2010     2010  
Convertible debentures
    70,565              
Unamortized financing costs and derivative instrument
    (10,419 )            
 
                 
Carrying amount
    60,146              
 
                 
On June 9, 2011, the Company issued Cdn$73.3 million in 5.75% convertible unsecured subordinated debentures (“Convertible Debentures”) at a price of $1,000 per debenture. The issuance included a bought deal of Cdn$50.0 million. The issuance also included Cdn$23.3 million in privately placed debentures with the same terms as the public offering.
The Convertible Debentures mature on June 30, 2016, pay interest semi-annually on June 30 and December 31 and are convertible at a price of Cdn$3.36 per share. They are redeemable after June 30, 2014 at Ivanhoe’s option.
The carrying amount of the Convertible Debentures at September 30, 2011 was $60.1 million. The Canadian dollar denominated debt is considered an embedded derivative since the functional currency of the Company is the US dollar and, as such, the option was separated and recognized at fair value as a long term derivative liability as further described in Note 8. The remaining unamortized financing costs in the table above include $8.7 million related to the option as well as $1.7 million in transaction costs. Transaction costs of $0.3 million were allocated to the derivative and charged to earnings in the period.
In the three and nine months ended September 30, 2011, $0.3 million and $0.7 million, respectively, was recorded as interest expense (three and nine months ended September 30, 2010 — nil). In the nine months ended September 30, 2011, $1.0 million (year ended December 31, 2010 — nil) of interest from the Convertible Debentures was capitalized to E&E assets and $0.1 million (year ended December 31, 2010 — nil) was capitalized to PP&E assets.
7. FINANCIAL INSTRUMENTS
The following table presents the Company’s derivative financial instruments measured at fair value through profit and loss (“FVTPL”):
                                                 
    Level 1     Level 2     Level 3        
                    2008     2011                
    2006     2009 & 2010     Convertible     Convertible             Total  
    Purchase     Purchase     Component     Component     Subsidiary     Fair  
    Warrants     Warrants     of Debt     of Debentures     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  
Issuance of convertible debentures
                      9,852             9,852  
Exercise of options
    (2 )     (3,107 )                       (3,109 )
Expiration of purchase warrants through profit and loss
    (2,346 )     (1,477 )                       (3,823 )
Derivative (gains) losses through profit and loss
    (3,267 )     2,968       (1,216 )     (7,577 )     286       (8,806 )
Foreign exchange gains
                      (465 )           (465 )
 
                                   
Balance September 30, 2011
                      1,810       286       2,096  
 
                                   
The gain on derivative instruments of $12.6 million for the nine months ended September 30, 2011, (nine months ended September 30, 2010 — $20.4 million, year ended December 31, 2010 — $18.6 million) originated from the expiration and revaluation of derivative financial instruments measured at FVTPL.

 

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8. DERIVATIVE INSTRUMENTS
The Company’s derivative instruments are comprised of the convertible component of the Convertible Debentures and the Subsidiary Option.
8.1 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
    (16,013 )     (16,013 )
 
           
Balance September 30, 2011
           
 
           
All of the Company’s purchase warrants have expired in 2011 and no purchase warrants remain outstanding at September 30, 2011.
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 TSX 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.
8.2 Convertible Note
The Company issued a Cdn$40.0 million Convertible Note, as described in Note 6.1. The outstanding principal amount was convertible, at Talisman’s option, into common shares of the Company. The fair value of the convertible component was nil at September 30, 2011 (December 31, 2010 — $1.2 million) as the Convertible Note was paid in full on July 11, 2011.
8.3 Convertible Debentures
The Company issued Cdn$73.3 million in Convertible Debentures in the second quarter of 2011, as described in Note 6.2. The outstanding principal amount is convertible into common shares of the Company. The fair value of the convertible component was $1.8 million at September 30, 2011 (December 31, 2010 — nil), calculated with the Black-Scholes valuation method using a weighted average risk-free interest rate of 1.39%, a dividend yield of 0.0%, a weighted average volatility factor of 40% and an expected life of approximately 5 years.
If the volatility used to fair value the convertible debt decreased by 10%, the fair value would decrease by $1.2 million. Increasing the volatility by 10% would increase the fair value by $1.7 million.

 

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8.4 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 at September 30, 2011 was $0.3 million, calculated with the Black Scholes valuation method using an estimated share value of $17.13, an exercise price of $30.00 per share, a risk-free interest rate of 0.90%, a dividend yield of 0.0%, an expected life of approximately five months and an estimated volatility of 65.6%, which is similar to Ivanhoe.
If the estimated volatility used to fair value the Subsidiary Option decreased by 10%, the fair value would decrease by $0.1 million. Increasing the volatility by 10% would have had the opposite, but approximately equal, impact.
9. COMMITMENTS AND CONTINGENCIES
9.1 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 remote.
9.2 Operating Lease Arrangements
In the three months and nine months ended September 30, 2011, the Company expended $0.4 million and $1.3 million, respectively, (three months and nine months ended September 30, 2010 — $0.3 million and $0.9 million, respectively) on operating leases relating to the rental of office space, which expire between 2011 and 2013.
At September 30, 2011, future net minimum payments for operating leases were:
         
Remainder of 2011
    428  
2012-2013
    1,133  
 
     
 
    1,561  
 
     
9.3 Other
Should Ivanhoe receive government and other approvals necessary to develop the northern border of one of the Tamarack leases, the Company will be required to make a cash payment to Talisman of up to Cdn$15.0 million, as a conditional, final payment for the 2008 purchase transaction.
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. Similarly, agreements entered into by the Company may contain cancellation fees or liquidated damages provisions for early termination. These fees are not considered to be material.

 

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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.
In the ordinary course of business, the Company is subject to legal proceedings being brought against it. While the final outcome of these proceedings is uncertain, the Company believes that these proceedings, in the aggregate, are not reasonably likely to have a material effect on its financial position or earnings.
10. SHARE CAPITAL
     
Authorized
  Unlimited common shares with no par value
Unlimited preferred shares with no par value
 
   
Issued and Outstanding
  344,139,428 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 for the nine months ended September 30, 2011 and 2010.
11. SHARE-BASED PAYMENTS
Share-based transactions were charged to earnings, as general and administrative or operating expenses, or capitalized to E&E assets as follows:
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
Share-based expense related to
                               
Equity settled transactions
    1,533       1,379       4,768       3,811  
Cash settled transactions
    147             159        
 
                       
Total share-based expense
    1,680       1,379       4,927       3,811  
 
                       
Share-based payments capitalized as E&E assets
                335       799  
 
                       
11.1 Stock Option Plan
Details of transactions under the Company’s stock option plan are as follows:
                                 
    September 30, 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
    1,914       2.66       6,041       2.56  
Exercised
    (1,687 )     2.50       (2,743 )     2.28  
Expired
    (710 )     2.97       (635 )     2.60  
Forfeited
    (1,082 )     2.42       (749 )     2.64  
 
                       
Outstanding, end of period
    15,362       2.25       16,927       2.24  
 
                       
Exercisable, end of period
    7,370       2.12       7,324       2.19  
 
                       
The weighted average share price at the date of exercise for stock options exercised in the nine months end September 30, 2011 was Cdn$3.15 (nine months ended September 30, 2010 — Cdn$3.50).

 

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The weighted average fair value of stock options granted from the stock option plan during the nine months ended September 30, 2011 was Cdn$1.58 (nine months ended September 30, 2010 — Cdn$1.99) per option at the grant date using the Black Scholes option pricing model. The weighted average assumptions used for the calculation were:
                 
Nine months ended September 30,   2011     2010  
Expected life (in years)
    6.3       6.1  
Volatility (1)
    74.4 %     98.5 %
Dividend yield
           
Risk-free rate
    2.7 %     3.0 %
Estimated forfeiture rate
    6.0 %     5.2 %
 
     
(1)  
Expected volatility factor based on historical volatility of the Company’s publicly traded common shares.
The following table summarizes information in respect of stock options outstanding and exercisable at September 30, 2011:
                         
            Weighted Average        
            Remaining     Weighted Average  
    Outstanding     Contractual Life     Exercise Price  
Range of Exercise Prices (Cdn$)   (000s)     (years)     (Cdn$)  
1.51 to 2.06
    5,223       2.2       1.71  
2.15 to 2.71
    8,526       4.8       2.39  
2.77 to 3.44
    1,613       5.1       3.21  
 
                 
 
    15,362       3.9       2.25  
 
                 
11.2 Restricted Share Unit Plan
The Company adopted a restricted share unit (“RSU”) plan in the second quarter of 2011 under which it may issue restricted share units to directors and eligible employees. RSUs vest evenly over three years and are settled in shares or cash on the anniversary date. RSUs do not entitle the holder to voting rights until they have vested and shares have been provided to the participant.
Details of transactions under the Company’s RSU plan are as follows:
                 
    September 30, 2011  
            Weighted Average  
    Number of RSUs     Fair Value  
    (000s)(1)     (Cdn$)  
Outstanding, beginning of period
           
Granted
    1,115       1.62  
Forfeited
    (132 )     1.89  
 
           
Outstanding, end of period
    983       1.59  
 
           
 
     
(1)  
Includes RSUs that will be withheld on behalf of employees to satisfy statutory tax withholding requirements.

 

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The weighted average fair value of RSU’s granted during the nine months ended September 30, 2011 was Cdn$1.62 per RSU at the grant date using the Black Scholes option pricing model. The weighted average assumptions used for the calculation were:
         
    Nine months ended  
    September 30, 2011  
Expected life (in years)
    3.0  
Volatility (1)
    62.9 %
Dividend yield
     
Risk-free rate
    1.7 %
Estimated forfeiture rate
    6.1 %
 
     
(1)  
Expected volatility factor based on historical volatility of the Company’s publicly traded common shares.
The liabilities arising from the RSUs to be settled by way of cash payments and the intrinsic value of those liabilities are:
         
    September 30,  
    2011  
Current liabilities related to RSUs
    90  
Long term liabilities related to RSUs
    69  
Intrinsic value of vested RSUs
     
12. 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. 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.

 

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The following table presents the Company’s segment assets, segment income (loss) and segment revenues reconciled to the Company’s Financial Statements.
                                                 
                    Latin     Technology              
    Asia     Canada     America     Development     Corporate     Total  
Segment revenue (1)
                                               
For the three months ended September 30, 2011
    10,770                         218       10,988  
For the three months ended September 30, 2010
    4,177                         88       4,265  
 
                                               
For the nine months ended September 30, 2011
    28,281                         425       28,706  
For the nine months ended September 30, 2010
    15,559                         125       15,684  
 
                                               
Segment income (loss)
                                               
For the three months ended September 30, 2011
    (3,485 )     (625 )     (2,070 )     (2,839 )     4,862       (4,157 )
For the three months ended September 30, 2010
    (2,218 )     (875 )     (2,917 )     (953 )     (2,642 )     (9,605 )
 
                                               
For the nine months ended September 30, 2011
    (5,196 )     (2,911 )     (5,937 )     (7,846 )     2,496       (19,394 )
For the nine months ended September 30, 2010
    (3,838 )     (2,826 )     (6,583 )     (3,667 )     9,763       (7,151 )
 
                                               
Segment assets (2)
                                               
As at September 30, 2011
    107,362       131,692       36,893       102,458       50,042       428,447  
As at December 31, 2010
    85,273       123,890       24,392       101,899       58,964       394,418  
As at January 1, 2010
    57,528       94,594       7,778       101,893       19,158       280,951  
 
                                               
Segment liabilities (3)
                                               
As at September 30, 2011
    142,265       141,988       58,507       85,151       (318,636 )     109,275  
As at December 31, 2010
    114,980       131,277       42,162       76,747       (271,232 )     93,934  
As at January 1, 2010
    81,047       98,262       13,145       56,909       (162,821 )     86,542  
 
                                               
Capital investments — Intangible
                                               
For the three months ended September 30, 2011
    7,649       1,451       3,268                   12,368  
For the three months ended September 30, 2010
    8,907       2,752       4,995                   16,654  
 
                                               
For the nine months ended September 30, 2011
    21,755       5,298       9,087                   36,140  
For the nine months ended September 30, 2010
    13,395       24,094       13,305                   50,794  
 
                                               
Capital investments — Property, plant and equipment
                                               
For the three months ended September 30, 2011
    4,713             (2 )     (236 )           4,475  
For the three months ended September 30, 2010
    592             176       70       (17 )     821  
 
                                               
For the nine months ended September 30, 2011
    11,014             55       869             11,938  
For the nine months ended September 30, 2010
    2,043       3       263       376       371       3,056  
 
     
(1)  
All oil revenues in Asia are generated from the sale of oil production in China to one customer.
 
(2)  
Segment assets include investments in subsidiaries that are eliminated for consolidation under Corporate.
 
(3)  
Liabilities for Corporate include intercompany receivables of $411.6 million at September 30, 2011 (December 31, 2010 — $352.5 million; January 1, 2010 — $216.7 million) resulting in a negative balance.
13. OPERATING EXPENSES
Operating expenses for the Company are comprised of the following:
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
Asia
                               
Field operating
    1,695       1,244       5,010       3,908  
Windfall levy
    2,584       637       6,343       2,317  
Engineering support
    126       135       339       375  
 
                       
 
    4,405       2,016       11,692       6,600  
Technology Development FTF operating costs
    1,084       980       3,659       3,102  
 
                       
Total operating costs
    5,489       2,996       15,351       9,702  
 
                       

 

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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.
14. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-Cash Activities
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
Operating activities
                               
Accounts receivable
    29       1,338       (2,617 )     1,029  
Note receivable
    10       (4 )     43       (35 )
Prepaid and other current assets
    54       1,092       (94 )     414  
Accounts payable and accrued liabilities
    (1,155 )     (1,774 )     3,584       (1,028 )
 
                       
 
    (1,062 )     652       916       380  
 
                       
Investing activities
                               
Accounts receivable
    177       (298 )     733       (327 )
Prepaid and other current assets
    22       (1,055 )     2,263       (972 )
Accounts payable and accrued liabilities
    (4,453 )     2,207       (2,672 )     5,008  
 
                       
 
    (4,254 )     854       324       3,709  
 
                       
Financing activities
                               
Accounts payable and accrued liabilities
    104       (41 )     57       (2 )
 
                       
 
    (5,212 )     1,465       1,297       4,087  
 
                       
15. 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 is as follows:
                                     
        Three months ended     Nine months ended  
        September 30,     September 30,  
Related Party   Nature of Transaction   2011     2010     2011     2010  
Global Mining Management Corp.
  Administration     117       313       446       954  
Ivanhoe Capital Aviation Ltd.
  Aircraft     300       300       900       900  
I2MS.Net PTE Ltd.
  Information systems     51       80       159       264  
Ivanhoe Capital Services Ltd.
  Administration     125       108       246       191  
SouthGobi Resources Ltd.
  Administration     38       38       115       38  
Ibex Resources Inc.
  Business development           6             39  
1092155 Ontario Inc.
  HTLTM technology     12       15       32       42  
Ensyn Technologies Inc.
  HTLTM technology                       7  
Ivanhoe Capital PTE Ltd.
  Administration     17       10       132       19  
Ivanhoe Mines Ltd.
  Administration                       13  
 
                                   
 
        660       870       2,030       2,467  
 
                                   

 

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The liabilities of the Company include the following amounts due to related parties:
                             
        September 30,     December 31,     January 1,  
Related Party   Nature of Transaction   2011     2010     2010  
Global Mining Management Corp.
  Administration     67       86       40  
I2MS.Net PTE Ltd.
  Information systems     16       13       17  
SouthGobi Resources Ltd.
  Administration     13       38        
Ivanhoe Capital Services Ltd.
  Administration     43       70       15  
Ivanhoe Capital PTE Ltd.
  Administration                  
 
                     
 
        139       207       72  
 
                     
16. REMUNERATION OF KEY MANAGEMENT PERSONNEL
The remuneration of directors and other key members of management was:
                                 
    Three months ended     Nine months ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
Base salaries or fees and other cash payments
    743       737       3,123       2,925  
Employer’s contributions to retirement plan
    11       17       37       50  
Share-based compensation expense
    753       581       2,289       1,615  
 
                       
 
    1,507       1,335       5,449       4,590  
 
                       
17. FIRST-TIME ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS
The Company adopted IFRS on January 1, 2011, with a transition date of January 1, 2010. The accounting policies adopted by Ivanhoe as a result may be found in Note 3 of the Company’s March 31, 2011 financial statements.
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.
17.1 Exemptions from Full Retrospective Application
IFRS 1 outlines 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 the Company’s oil and gas properties recorded in PP&E and intangible assets. The Company elected to re-measure its FTF decommissioning provision under IFRS.
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.

 

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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.
17.2 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) income 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 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 September 30, 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       93,098             93,098  
Accounts receivable
    5,021             5,021       6,359             6,359       4,332             4,332  
Note receivable
    225             225       264             264       260             260  
Prepaid and other current assets
    771             771       2,859             2,859       1,329             1,329  
 
                                                     
 
    30,379             30,379       77,799             77,799       99,019             99,019  
 
                                                                       
Intangible assets
    92,153       115,597 a     207,750       92,153       197,193 a     273,568       92,153       174,655 a     259,172  
 
                                  (7,482 )b                     (5,356 )b        
 
                                  175 c                     98 c        
 
                                  (8,471 )g                     (2,378 )g        
Property, plant and equipment, net
    158,392       (115,597 )a     41,983       237,200       (197,193 )a     40,618       213,685       (174,655 )a     39,624  
 
            (904 )b                     (2,014 )b                     (1,407 )b        
 
            92 c                     189 c                     205 c        
 
                                  2,436 f                     1,796 f        
Long term receivables
    839             839       2,433             2,433       2,126             2,126  
 
                                                     
 
    281,763       (812 )     280,951       409,585       (15,167 )     394,418       406,983       (7,042 )     399,941  
 
                                                     
 
                                                                       
Liabilities and Shareholders’ Equity
                                                                       
Current Liabilities
                                                                       
Accounts payable and accrued liabilities
    10,779             10,779       21,482             21,482       14,394             14,394  
Debt
                      39,832             39,832       38,279             38,279  
Derivative financial instruments
          13,023 d     13,023             8,447 d     8,447             6,613 d     6,613  
Income tax payable
    530             530                                      
Decommissioning costs
    753             753                                      
 
                                                     
 
    12,062       13,023       25,085       61,314       8,447       69,761       52,673       6,613       59,286  
 
                                                                       
Long term debt
    36,934             36,934                                      
Long term provisions
    2,095       92 c     2,187       2,644       364 c     3,008       2,396       301 c     2,697  
Deferred income tax liability
    22,643       (307 )b     22,336       21,518       (367 )b     21,165       22,624       (349 )b     22,286  
 
                                  14 f                     11 f        
 
                                                     
 
    73,734       12,808       86,542       85,476       8,458       93,934       77,693       6,576       84,269  
 
                                                     
 
                                                                       
Shareholders’ Equity
                                                                       
Share capital
    422,322             422,322       550,562             550,562       549,220       (70 )e     549,150  
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       20,343       (2,946 )d     20,310  
 
            1,642 e                     3,105 e                     2,913 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 )     (275,782 )     21,994       (253,788 )
 
                                                     
 
    208,029       (13,620 )     194,409       324,109       (23,625 )     300,484       329,290       (13,618 )     315,672  
 
                                                     
 
    281,763       (812 )     280,951       409,585       (15,167 )     394,418       406,983       (7,042 )     399,941  
 
                                                     

 

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Reconciliation of Consolidated Statements of Loss and Comprehensive Loss
                                                                         
    Three months ended September 30, 2010     Nine months ended September 30, 2010     Year ended December 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  
 
                                                                       
Revenue
                                                                       
Oil
    4,177             4,177       15,554             15,554       21,720             21,720  
Interest
    88             88       130             130       208             208  
 
                                                     
 
    4,265             4,265       15,684             15,684       21,928             21,928  
 
                                                     
 
                                                                       
Expenses
                                                                       
Operating
    2,955       41 b     2,996       9,607       95 b     9,702       13,514       111 b     13,625  
Exploration and evaluation
          788 g     788             2,378 g     2,378             8,471 g     8,471  
General and administrative
    8,120       2,451 b     10,898       21,459       5,763 b     28,423       32,864       8,481 b     42,807  
 
            327 e                     1,201 e                     1,462 e        
Depletion and depreciation
    2,079       (589 )f     1,490       6,744       (1,796 )f     4,948       8,960       (2,436 )f     6,524  
Foreign currency exchange
    (1,188 )           (1,188 )     (2,289 )           (2,289 )     (3,325 )           (3,325 )
Derivative instruments gain
          (622 )d     (622 )           (20,405 )d     (20,405 )           (18,571 )d     (18,571 )
Interest
    6       (2 )     4       14       (2 )c     12       24             24  
 
                                                     
 
    11,972       2,394       14,366       35,535       (12,766 )     22,769       52,037       (2,482 )     49,555  
 
                                                     
 
                                                                       
Loss before income taxes
    (7,707 )     (2,394 )     (10,101 )     (19,851 )     12,766       (7,085 )     (30,109 )     2,482       (27,627 )
 
                                                                       
(Provision for) recovery of income taxes
                                                                       
Current
                      (115 )           (115 )     (126 )           (126 )
Deferred
    479       21 b     496       19       41 b     49       1,125       60 b     1,171  
 
            (4 )f                     (11 )f                     (14 )f        
 
                                                     
 
    479       17       496       (96 )     30       (66 )     999       46       1,045  
 
                                                     
 
                                                                       
Net loss and comprehensive loss
    (7,228 )     (2,377 )     (9,605 )     (19,947 )     12,796       (7,151 )     (29,110 )     2,528       (26,582 )
 
                                                     

 

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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 “Exploration for and evaluation of mineral resources”, 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 warrants 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.
 
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.
 
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 and impaired geological and geophysical assets will be charged to earnings as E&E expense.

 

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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.
Statements that contain words such as “could”, “should”, “can”, “anticipate”, “estimate”, “propose”, “plan”, “expect”, “believe”, “will”, “may” and similar expressions and statements relating to matters that are not historical facts constitute “forward-looking statements” within the meaning of the “safe harbor” provisions of the United States Private Securities Litigation Reform Act of 1995. In particular, forward-looking statements contained in this Form 10-Q include, but are not limited to statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil prices; future production levels; future royalty and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for the Company’s capital programs; future debt levels; availability of future credit facilities; possible commerciality of the Company’s projects; development plans or capacity expansions; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected operating costs; the expectation of negotiating of an extension to certain of the Company’s production sharing agreements; the expectation of the Company’s ability to comply with the newly enacted safety and environmental rules; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and the Company’s ability to comply therewith; dates by which certain areas will be developed, come on-stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements.
Statements relating to “reserves” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.
The forward-looking statements contained in this Form 10-Q are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. By their nature, forward-looking statements involve inherent risks and uncertainties including the risk that the outcome that they predict will not be achieved. Undue reliance should not be placed on forward-looking statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in the forward-looking statements, including those set out below and those detailed in Item 1A, “Risk Factors,” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (“2010 Form 10-K”). Such factors include, but are not limited to: the Company’s short history of limited revenue, losses and negative cash flow from its current exploration and development activities in Canada, Ecuador, China, Mongolia and the United States; the Company’s limited cash resources and consequent need for additional financing; the ability to raise capital as and when required, or to raise capital on acceptable terms; the timing and extent of changes in prices for oil and gas; competition for oil and gas exploration properties from larger, better financed oil and gas companies; environmental risks; title matters; drilling and operating risks; uncertainties about the estimates of reserves and the potential success of the Company’s Heavy-to-light (“HTL™”) technology; the potential success of the Company’s oil and gas properties in Canada, Ecuador, China and Mongolia; 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 the Company’s capital investment program.
The forward-looking statements contained in this Form 10-Q are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking statements contained herein are expressly qualified in their entirety by this cautionary statement.
Special Note to Canadian Investors
The Company is a registrant under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) 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.

 

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Advisories
This Form 10-Q should be read in conjunction with the Company’s September 30, 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 International Financial Reporting Standards (“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 generally accepted accounting principles (“GAAP”), to IFRS is set out in Note 17 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, as issued by the International Accounting Standards Board, 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 their usefulness as comparative measures.
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 U.S. 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   mbbls/d   =   thousand barrels per day
bbls/d
  =   barrels per day   mboe   =   thousands of barrels of oil equivalent
boe
  =   barrel of oil equivalent   mboe/d   =   thousands of barrels of oil equivalent per day
boe/d
  =   barrels of oil equivalent per day   mmbbls   =   million barrels
mbbls
  =   thousand barrels   mmbls/d   =   million barrels per day
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. Copies of the charters for each of the committees of the Company’s board of directors are available through the Company’s website at www.ivanhoeenergy.com/index.php?page=mandate_of_the_boardcommittee_overview.

 

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INTERNATIONAL FINANCIAL REPORTING STANDARDS
The Company adopted IFRS on January 1, 2011, with a transition date of January 1, 2010. IFRS employs a conceptual framework that is similar to Canadian GAAP, however, significant differences exist in certain matters of recognition, measurement and disclosure. The accounting policies and financial statement accounts of the Company that were materially affected by the adoption of IFRS, as well as the IFRS 1, “First-Time Adoption of International Financial Reporting Standards,” exemptions utilized by the Company, were described in the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.
The adoption of IFRS resulted in changes to the reported financial position and earnings of the Company and the 2010 comparative periods have been restated under IFRS. Reconciliations of the statements of financial position and statements of loss presented under Canadian GAAP to IFRS is included in Note 17 to the Financial Statements. Changes made to the statements of financial position and statements of loss 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.
HIGHLIGHTS
                                 
    Three months     Nine months  
    ended September 30,     ended September 30,  
($000, except as stated)   2011     2010     2011     2010  
Average daily production (bbls/d)
    1,029       610       992       760  
Realized oil prices ($/bbl)
    113.74       74.41       104.40       74.92  
Oil revenue
    10,769       4,177       28,277       15,554  
Capital expenditures
    16,843       17,475       48,078       53,850  
 
                               
Cash flow used in operating activities
    (5,214 )     (7,913 )     (18,678 )     (19,620 )
Net loss
    (4,157 )     (9,605 )     (19,394 )     (7,151 )
Net loss per share, basic and diluted
    (0.01 )     (0.03 )     (0.06 )     (0.02 )
Oil production increased in the nine months ended September 30, 2011 as Ivanhoe received additional volumes to offset capital expenditures incurred at Dagang in 2011. Additional production in combination with stronger realized prices, resulted in higher oil revenue for the Company. The net loss in the nine months ended September 30, 2011 was $19.4 million compared to a $7.2 million net loss in the prior period. Although oil revenue increased in 2011, net income was impacted by higher operating and general and administrative expenses as well as lower non-cash foreign currency exchange and derivative instrument gains in comparison to 2010.
Capital expenditures totaled $16.8 million in the three months ended September 30, 2011. In China, the Yixin-2 and Zitong-1 gas wells were gas flow tested and down hole electronic recorders were run until late July. Analysis of the data collected is ongoing and results will provide critical information for completion and stimulation techniques for future exploitation programs on the Zitong Block. At Dagang, two wells were drilled in the third quarter and one well was completed, in addition to the continuation of the Company’s fracture stimulation program.
In the Nyalga basin of Mongolia, drilling was concluded at the Company’s first exploration well at N16-1E-1A. The well was plugged and abandoned as it did not encounter oil shows in the reservoir. However, the well provided information that will be used in combination with seismic data to guide future drilling. The drilling rig was subsequently mobilized to a second site, N16-2E-B, located approximately 12 kilometres from the first well. Drilling commenced in the middle of September.
In Canada, regulators completed their initial review of the Company’s Environmental Impact Assessment for the Tamarack project and Ivanhoe received expected Supplemental Information Requests in the third quarter of 2011. Ivanhoe anticipates submitting the additional information to the regulators in the fourth quarter of 2011.

 

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In Ecuador, the Company continued internal processing and interpretation of the seismic data acquired during the second quarter of 2011 from the Company’s 190-kilometre 2-D survey of Block 20. Early interpretation indicates deeper faulting, with the potential to trap lighter oil resources which could prove beneficial for blending purposes and overall project economics. Additionally, initial internal interpretations may also suggest an extension of the field beyond what was originally estimated.
RESULTS OF OPERATIONS
                                 
    Three months     Nine months  
    ended September 30,     ended September 30,  
    2011     2010     2011     2010  
Asia (net bbls)
                               
Dagang
    92,576       52,420       261,105       195,424  
Daqing
    2,098       3,711       9,749       12,173  
 
                       
Total production
    94,674       56,131       270,854       207,597  
 
                       
Average daily production (bbls/d)
    1,029       610       992       760  
 
                               
Pricing
                               
Average realized oil price ($/bbl)
    113.74       74.41       104.40       74.92  
West Texas Intermediate (WTI) ($/bbl)
    89.40       76.06       95.31       77.54  
Oil Revenue
Ivanhoe’s oil revenue in the three and nine months ended September 30, 2011, increased from the prior periods 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 capital activity at Dagang in the three and nine months ended September 30, 2011, additional oil production was allocated to Ivanhoe.
Net Revenue from Operations
                                 
    Three months     Nine months  
    ended September 30,     ended September 30,  
($/bbl)   2011     2010     2011     2010  
Oil revenue(1)
    113.74       74.41       104.40       74.92  
Less operating costs
                               
Field operating
    (17.91 )     (22.15 )     (18.50 )     (18.82 )
Windfall Levy
    (27.30 )     (11.34 )     (23.42 )     (11.16 )
Engineering and support costs
    (1.34 )     (2.42 )     (1.25 )     (1.81 )
 
                       
Net operating revenue(1)
    67.19       38.50       61.23       43.13  
Depletion
    (19.53 )     (23.41 )     (18.56 )     (23.55 )
 
                       
Net revenue from operations(1)
    47.66       15.09       42.67       19.58  
 
                       
     
(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 this MD&A for more details.

 

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Operating Costs
                                 
    Three months     Nine months  
    ended September 30,     ended September 30,  
    2011     2010     2011     2010  
Asia
                               
Field operating
    1,695       1,244       5,010       3,908  
Windfall Levy
    2,584       637       6,343       2,317  
Engineering support
    126       135       339       375  
 
                       
 
    4,405       2,016       11,692       6,600  
Technology Development
                               
FTF operating costs
    1,084       980       3,659       3,102  
 
                       
Total operating costs
    5,489       2,996       15,351       9,702  
 
                       
Operating costs in China rose $2.4 million and $5.1 million, respectively, in the three and nine months ended September 30, 2011, over the comparable periods of 2010. The increase is primarily attributable to the additional Windfall Levy administered by the People’s Republic of China, which rises with higher oil prices.
Field operating costs in total increased over the prior periods due to additional production volumes. On a per barrel basis, field operating costs were $4.24/bbl lower in the three months ended September 30, 2011 compared to the prior year as field staff focused their efforts on drilling and completion activities in the Company’s Dagang field. On a per barrel basis, year to date field operating costs in the nine months ended September 30, 2011 were consistent with the prior year.
Operating costs in the Technology Development segment are incurred at the Company’s Feedstock Test Facility (“FTF”) at the Southwest Research Institute in San Antonio, Texas. FTF operating costs in the three months ended September 30, 2011 were consistent with costs sustained during the third quarter of 2010. FTF operating costs to date in 2011 are higher than in 2010 due to activities associated with assay and analyses related to the successful upgrading of the heavy oil recovered from the Pungarayacu IP-5B well in Ecuador and planned maintenance costs associated with enhancements implemented at the FTF unit in the second quarter of 2011.
Exploration and Evaluation
Costs of exploring for, and evaluating, oil and gas properties are initially capitalized as intangible exploration and evaluation assets and charged to exploration and evaluation (“E&E”) expense only if sufficient reserves cannot be established. In the three and nine months ended September 30, 2011, $2.1 million of drilling costs were expensed in connection with the exploration well in Mongolia that was plugged and abandoned.
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, $0.8 million and $2.4 million of geological costs incurred in prior periods were expensed as E&E costs in the three and nine months ended September 30, 2010.
General and Administrative
G&A expenses were higher in the three and nine months ended September 30, 2011, than in the comparable periods. In the third quarter of 2011, professional fees rose due to higher legal costs incurred in connection with the proceedings described in Part II of this Form 10-Q and increasing contract engineering costs related to Ivanhoe’s HTLTM technology. The Company also incurred additional staff, office and travel costs in the third quarter of 2011.
In the nine months ended September 30, 2011, G&A increased over the prior period due to additional staff, office and travel costs. Professional fees rose in comparison to the prior year as a result of higher legal costs, contract engineering costs related to Ivanhoe’s HTLTM technology and other services. G&A in 2011 also included financing and filing fees associated with the Cdn$73.3 million convertible unsecured subordinated debentures (“Convertible Debentures”) issued in the second quarter of 2011.

 

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Depletion and Depreciation
Depletion and depreciation expense in the three months ended September 30, 2011 was higher than in the third quarter of 2010 due to additional production in Asia during the current quarter.
Depletion and depreciation expense in the nine month ended September 30, 2011 increased in comparison to 2010 due to a combination of factors. Depletion in Asia rose $0.2 million in 2011 due to higher year to date production, despite a lower depletion rate from additional Dagang reserves. The depreciation expense associated with the de-activated and dismantled Commercial Demonstration Facility (“CDF”) and FTF was $0.6 million higher in the current year due to revisions to the CDF salvage values reducing depreciation in 2010.
On a per barrel basis, depletion in Asia decreased in the three and nine months ended September 30, 2011 in comparison to the prior periods due to additional proved and probable reserves booked at Dagang at January 1, 2011.
Foreign Exchange
The Company incurred a lower foreign exchange gain in the third quarter of 2011 compared to the third quarter of 2010. The Canadian dollar weakened in comparison to the US dollar during the current quarter. As a result, foreign exchange gains on the Company’s Convertible Debentures were offset by foreign exchange losses incurred on the translation of Canadian dollar cash. The Canadian dollar strengthened against the US dollar during the third quarter of 2010 resulting in a higher net foreign exchange gain than in the current quarter.
In the nine months ended September 30, 2011, the foreign exchange gain was less than in the prior comparable period. In the prior year, the Company incurred a large foreign exchange gain in the first quarter of 2010 due to the Canadian dollar strengthening against the US dollar in the first quarter of 2010, which was partially offset by a loss incurred in the second quarter of 2010 when the Canadian dollar weakened.
Derivative Instruments
In the third quarter of 2011, the Company incurred an unrealized gain of $5.4 million on the revaluation of the convertible component of its Convertible Debentures. The unrealized gain of $0.6 million in the third quarter of 2010 resulted from the revaluation of the Company’s share purchase warrants issued in 2006, 2009 and 2010 (“Purchase Warrants”).
In the nine months ended September 30, 2011, the unrealized gain on derivative instruments was less than in the prior comparable period. The unrealized gain on the Convertible Debentures totaled $7.6 million to date in 2011. A combination of the expiry and revaluation of the Company’s Purchase Warrants resulted in a gain of $4.1 million and a gain of $1.2 million was recognized on the revaluation of the convertible portion of the Cdn$40.0 million convertible promissory note (“Convertible Note”). The revaluation of an option granted to a private investor in January 2010 to acquire an equity interest in one of the Company’s subsidiaries created a loss of $0.3 million.
The $20.4 million unrealized gain recognized in the nine months ended September 30, 2010 stemmed from a $16.0 million and $4.3 million gain, respectively, on the revaluation of the Purchase Warrants and Convertible Note.
Provision for Income Taxes
Current taxes in China increased in both the three and nine months ended September 30, 2011, due to higher oil revenue than in the comparable periods. Ivanhoe incurred a future tax expense of $0.7 million to date in 2011 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 the Company’s 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.
                                                 
    Total     2011     2012     2013     2014     After 2014  
Long term debt
    69,939                               69,939  
Interest
    20,349       2,259       4,021       4,021       4,021       6,027  
Decommissioning provisions(1)
    2,111                   317             1,794  
Lease commitments
    1,561       428       867       266              
 
                                   
 
    93,960       2,687       4,888       4,604       4,021       77,760  
 
                                   
     
(1)  
Represents undiscounted asset retirement obligations after inflation. The discounted value of these estimated obligations is provided for in the Financial Statements.
Long Term Debt and Interest
As described in the Financial Statements, the Company issued Cdn$73.3 million of Convertible Debentures, maturing on June 30, 2016. The Convertible Debentures bear interest at an annual rate of 5.75%, payable semi-annually on the last day of June and December of each year, commencing on December 31, 2011.
Decommissioning Provisions
The Company is required to remedy the effect of our activities on the environment at its operating sites by dismantling and removing production facilities and remediating any damage caused. At September 30, 2011, Ivanhoe estimated the total undiscounted, inflated cost to settle its asset retirement obligations in Canada, for the FTF and in Ecuador was $2.1 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 productive wells will not be abandoned while the Company has an economic interest in the field.
Operating Leases
The Company has long term operating leases for office space, which expire between 2011 and 2013.
Other
Should Ivanhoe receive government and other approvals necessary to develop the northern border of one of the Tamarack project leases, the Company will be required to make a cash payment to Talisman Energy Canada (“Talisman”) of up to Cdn$15.0 million, as a conditional, final payment for the 2008 purchase transaction.
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. Similarly, agreements entered into by the Company may contain cancellation fees or liquidated damages provisions for early termination. 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.
In the ordinary course of business, the Company is subject to legal proceedings being brought against it. While the final outcome of these proceedings is uncertain, the Company believes that these proceedings, in the aggregate, are not reasonably likely to have a material effect on its financial position or earnings.

 

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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 flows, are summarized in the following table:
                                 
    Three months     Nine months  
    ended September 30,     ended September 30,  
    2011     2010     2011     2010  
Cash used in operating activities
    (5,214 )     (7,913 )     (18,678 )     (19,620 )
Cash used in investing activities
    (22,981 )     (17,853 )     (51,104 )     (53,063 )
Cash provided by (used in) financing activities
    (41,317 )     (102 )     61,423       137,796  
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. 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 or available on acceptable terms.
Operating Activities
In the three and nine months ended September 30, 2011, cash used in operating activities was lower than in 2010 as growth in revenue exceeded increases in operating costs and G&A expenses.
Investing Activities
E&E Expenditures
E&E capital expenditures in the nine months ended September 30, 2011 totaled $36.1 million. The Yixin-2 and Zitong-1 gas wells at the Company’s Zitong project in China were drilled and fracture stimulated. Subsequent to post-fracture gas flow tests, down-hole electronic recorders were installed to gather additional pressure data during an extended shut-in period and analysis of the data collected is ongoing.
In the Nyalga basin of Mongolia, expenditures incurred on the Company’s first exploration well at N16-1E-1A were expensed when the well did not encounter oil shows in the reservoir. The drilling rig was mobilized to a second site, N16-2E-B, and drilling commenced in the middle of September.
In Canada, regulators completed their initial review of the Company’s Environmental Impact Assessment for the Tamarack project and, as is customary, provided the Company with an initial set of Supplemental Information Requests in the third quarter of 2011. Ivanhoe anticipates submitting the additional information to the regulators in the fourth quarter of 2011.
In Ecuador, the Company concluded its 190-kilometre 2-D seismic survey of Block 20 initiated during the second quarter of 2011. The initial phase of shooting was completed in July and analysis of the data is ongoing.
PP&E Expenditures
In the nine months ended September 30, 2011, PP&E additions totaled $11.9 million. At Dagang, four wells were drilled, of which three were completed and fracture stimulated in 2011. A well drilled in 2010 was completed in early 2011. In addition, the fracture stimulation program at Dagang has been ongoing throughout 2011.
Financing Activities
Cash provided by financing activities was higher in the nine months ended September 30, 2011 than in the prior periods. In June 2011, the Company raised $72.9 million, net of issuance costs, through the issuance of the Convertible Debentures. The net proceeds were used to repay the Convertible Note due to Talisman Energy Canada on July 11, 2011, as well as operating expenses and capital expenditures. In the first quarter of 2011, cash proceeds of $29.9 million were raised through the exercise of purchase warrants and stock options.
In comparison, the Company raised $135.7 million, net of issuance costs, through a private placement of 50 million special warrants at a price of Cdn$3.00 per special warrant in the nine months ended September 30, 2010.

 

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Capital Structure
                 
    September 30,     December 31,  
As at   2011     2010  
Debt
          39,832  
Long term debt
    60,146        
Shareholders’ equity
    319,172       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 the Company will be able to obtain such financing, or obtain it on favorable terms, and any future equity issuances may be dilutive to current investors. If Ivanhoe cannot secure additional financing, the Company may have to delay its capital programs and forfeit or dilute its rights in existing oil and gas property interests.
Outlook
In China, upon acceptance by CNPC, Ivanhoe will proceed with a 150-square-kilometre 3-D seismic program covering certain areas of the Zitong Block. The seismic program will assist in planning and designing a horizontal well-path for three wells in the Guan and Wen structures. It is anticipated that this program will be executed in the next 24 to 30 months and will provide the groundwork for the eventual development of the Zitong Block.
Following the drilling and abandonment of the Company’s first exploration well in Mongolia, the Company mobilized the rig to a second location in east-central Mongolia. Drilling of the second well began in mid-September and is targeting a total depth of approximately 2,500 metres.
In Canada, Alberta Environment (AENV) and the Energy Resources Conservation Board (ERCB) have completed their initial review of Ivanhoe Energy’s Application for the Tamarack integrated oil sands project, which is comprised of a two-phased 40,000 bbl/d steam-assisted gravity drainage thermal recovery (SAGD) and Heavy-to-Light (HTL) facility. The first round of Supplementary Information Requests (SIRS) was received from the regulators in the third quarter of 2011 and the Company will submit responses to these SIRs in the fourth quarter of 2011. It is anticipated that the regulatory approval process will be complete later in 2012. Project advancement, as currently envisaged, is subject to regulatory approval and financing.
Ivanhoe completed its 190-kilometre 2-D seismic survey over the southern portion of Block 20 in Ecuador and processing is ongoing. Internal interpretation suggests the heavy oil field may extend further southward than previously expected and geologic evidence suggests that a deeper, lighter oil play may also exist on the block. This internal analysis will be followed by expert external interpretation in the fourth quarter of 2011. The Company anticipates securing the necessary drilling licenses and environmental permits by the end of 2011 for wells to be drilled as part of the appraisal phase of the project.
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 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 3.  
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There has been no material change in the Company’s assessment of its sensitivity to market risk since its presentation set forth in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in the 2010 Form 10-K.
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 September 30, 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 September 30, 2011, that have materially affected, or are reasonably likely to have a material effect on the Company’s internal control over financial reporting.

 

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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 plaintiffs’ 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, also have been awarded costs and fees as the prevailing parties in the trial court.
On August 13, 2010, the plaintiffs filed a notice of appeal challenging the district court’s judgment and some of its related orders. The appeal is currently pending in the United States Court of Appeals for the Tenth Circuit. Briefing on the appeal is complete and the Court heard oral arguments on May 9, 2011, in Denver, Colorado. There has been no ruling as of yet on the appeal. 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 and subsidiaries in the Superior Court for Kern County, California on March 11, 2011. 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. On June 2, 2011, the Company filed its Answer to the Complaint and on June 3, 2011 removed the lawsuit to the United States District Court for the Eastern District of California. After the lawsuit was removed to federal court, the plaintiffs filed their First Amended Complaint and a motion asking the district court to remand the action to state court. The Company filed its Answer to the First Amended Complaint including a counterclaim for attorneys’ fees and a motion asking the court to dismiss some of the claims against it on July 11, 2011. Plaintiffs’ motion to remand remains pending, as do Company’s defendants’ motion to dismiss and a motion to compel arbitration of certain claims. 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
       
 
  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:
  November 9, 2011    

 

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