##### 



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-Q þ
    
    Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
 For the quarterly period ended March 31, 2005
 or o
    
    Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
 For the transition period from  to
 Commission file number 000-30586
 IVANHOE ENERGY INC. (Exact name of registrant as specified in its charter)
 Yukon, Canada
    
    98-0372413(State or other jurisdiction of
    
    (I.R.S. Employerincorporation or organization)
    
    Identification No.)
 Suite 654  999 Canada Place
Vancouver, British Columbia, Canada
V6C 3E1(Address of principal executive office) (604) 688-8323(registrants telephone number, including area code) Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report:
Not Applicable 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. Yes þ                      No o Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of
the Exchange Act) Yes þ                      No o The number of shares of the registrants capital stock outstanding as of March 31, 2005 was
169,892,413 Common Shares, no par value.




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##### 



TABLE OF CONTENTS PagePART I
    
    Financial InformationItem 1
    
    Financial StatementsUnaudited Condensed Consolidated Balance Sheets as at March 31, 2005 and December 31, 2004
    
    
    3Unaudited Condensed Consolidated Statements of Loss and Accumulated Deficit for the Three-Month Periods Ended March 31, 2005 and 2004
    
    
    4Unaudited Condensed Consolidated Statements of Cash Flow for the Three-Month Periods Ended March 31, 2005 and 2004
    
    
    5Notes to the Unaudited Condensed Consolidated Financial Statements
    
    
    6Item 2.
    
    Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    15Item 3.
    
    Quantitative and Qualitative Disclosures About Market Risks
    
    
    24Item 4.
    
    Controls and Procedures
    
    
    24PART II
    
    Other InformationItem 1.
    

Legal
Proceedings
    
    
    25Item 2.
    
    Unregistered Sales of Equity Securities and Use of Proceeds
    
    
    25Item 3.
    
    Defaults Upon Senior Securities
    
    
    25Item 4.
    
    Submission of Matters To a Vote of Securityholders
    
    
    25Item 5.
    
    Other Information
    
    
    25Item 6.
    
    Exhibits and Reports on Form 8-K
    
    
    25
 2




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##### 



Part I  Financial Information Item 1 Financial Statements IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Balance Sheets
(stated in thousands of U.S. Dollars except share amounts) March 31, 2005
    
    
    December 31, 2004AssetsCurrent AssetsCash and cash equivalents
    
    $
    9,335
    
    
    $
    9,322Notes and accounts receivable
    
    
    6,253
    
    
    
    5,377Prepaid and other current assets
    
    
    719
    
    
    
    81216,307
    
    
    
    15,511Long term assets
    
    
    7,409
    
    
    
    6,424Oil and gas properties and investments, net
    
    
    106,621
    
    
    
    96,551$
    130,337
    
    
    $
    118,486Liabilities and Shareholders EquityCurrent LiabilitiesAccounts payable and accrued liabilities
    
    $
    16,826
    
    
    $
    9,845Note payable  current portion
    
    
    1,667
    
    
    
    1,667Convertible loan
    
    
    6,000
    
    
    
    24,493
    
    
    
    11,512Long term debt
    
    
    2,222
    
    
    
    2,639Asset retirement obligations
    
    
    747
    
    
    
    749Commitments and contingenciesShareholders EquityShare capital, issued 169,892,413 common shares;
December 31, 2004 169,664,911 common shares
    
    
    184,102
    
    
    
    183,617Contributed surplus
    
    
    2,035
    
    
    
    1,748Accumulated deficit
    
    
    (83,262
    )
    
    
    (81,779
    )102,875
    
    
    
    103,586$
    130,337
    
    
    $
    118,486
 (See accompanying notes) 3




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##### 



IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Statements of Loss and Deficit
Three-Month Periods Ended March 31
(stated in thousands of U.S. Dollars except per share amounts) 2005
    
    
    2004RevenueOil and gas revenue
    
    $
    5,693
    
    
    $
    3,292Interest income
    
    
    43
    
    
    
    405,736
    
    
    
    3,332ExpensesOperating costs
    
    
    1,762
    
    
    
    1,275General, administrative and business development
    
    
    3,130
    
    
    
    1,880Depletion and depreciation
    
    
    2,207
    
    
    
    1,446Interest expense
    
    
    120
    
    
    
    237,219
    
    
    
    4,624Net Loss
    
    
    1,483
    
    
    
    1,292Deficit, beginning of period
    
    
    81,779
    
    
    
    61,054Deficit, end of period
    
    $
    83,262
    
    
    $
    62,346Net Loss per share  Basic and Diluted
    
    $
    0.01
    
    
    $
    0.01Weighted Average Number of Shares (in thousands)
    
    
    169,816
    
    
    
    162,127
 (See accompanying notes) 4




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##### 



IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Statements of Cash Flow
Three-Month Periods Ended March 31
(stated in thousands of U.S. Dollars) 2005
    
    
    2004Operating ActivitiesNet loss
    
    $
    (1,483
    )
    
    $
    (1,292
    )Items not requiring use of cashDepletion and depreciation
    
    
    2,207
    
    
    
    1,446Stock based compensation
    
    
    296
    
    
    
    239Changes in non-cash working capital items
    
    
    (244
    )
    
    
    (1,439
    )776
    
    
    
    (1,046
    )Investing ActivitiesCapital investments and other
    
    
    (12,534
    )
    
    
    (10,423
    )Equity investment and other related costs
    
    
    (730
    )
    
    
    (500
    )Changes in non-cash working capital items
    
    
    6,883
    
    
    
    598(6,381
    )
    
    
    (10,325
    )Financing ActivitiesShares issued on private placements, net of share issue costs
    
    
    
    
    
    
    20,428Shares issued on exercise of options
    
    
    35
    
    
    
    139Proceeds from debt obligations
    
    
    6,000
    
    
    
    10,000Repayments of debt obligations
    
    
    (417
    )
    
    
    5,618
    
    
    
    30,567Increase in cash and cash equivalents, for the period
    
    
    13
    
    
    
    19,196Cash and cash equivalents, beginning of period
    
    
    9,322
    
    
    
    14,491Cash and cash equivalents, end of period
    
    $
    9,335
    
    
    $
    33,687Included in the above are the following:Taxes paid
    
    $
    2
    
    
    $
    3Interest paid
    
    $
    56
    
    
    $
    14Changes in non-cash working capital itemsOperating Activities:Accounts receivable
    
    $
    (39
    )
    
    $
    (1,234
    )Prepaid and other current assets
    
    
    (130
    )
    
    
    38Accounts payable and accrued liabilities
    
    
    (75
    )
    
    
    (243
    )(244
    )
    
    
    (1,439
    )Investing ActivitiesAccounts receivable
    
    
    (837
    )
    
    
    322Prepaid and other current assets
    
    
    223
    
    
    
    (10
    )Accounts payable and accrued liabilities
    
    
    7,497
    
    
    
    2866,883
    
    
    
    598$
    6,639
    
    
    $
    (841
    )
 (See accompanying notes) 5




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##### 



Notes to the Condensed Consolidated Financial Statements
March 31, 2005
(all tabular amounts are expressed in thousands of U.S. dollars except per share amounts)
(Unaudited) 1. BASIS OF PRESENTATION The Companys accounting policies are in accordance with accounting principles generally accepted
in Canada. These policies are consistent with accounting principles generally accepted in the U.S.,
except as outlined in Note 12. The unaudited condensed consolidated financial statements
have been prepared on a basis consistent with the accounting principles and policies reflected in
the December 31, 2004 consolidated financial statements. These interim condensed consolidated
financial statements do not include all disclosures normally provided in annual consolidated
financial statements and should be read in conjunction with the most recent annual consolidated
financial statements. The December 31, 2004 consolidated balance sheet was derived from the audited
consolidated financial statements, but does not include all disclosures required by generally
accepted accounting principles (GAAP) in Canada and the U.S. In the opinion of management, all
adjustments (which included normal recurring adjustments) necessary for the fair presentation for the interim periods have been made. The
results of operations and cash flows are not necessarily indicative of the results for a full year. The preparation of financial statements requires management to make estimates and assumptions that
affect the reported amounts and other disclosures in these consolidated financial statements.
Actual results may differ from those estimates. Certain items in the 2004 financial statements have been reclassified for comparison to the 2005
presentation. 2. OIL AND GAS PROPERTIES AND INVESTMENTS Capital assets categorized by geographical location and business segment are as follows: As at March 31, 2005Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    TotalOil and Gas Properties:Proved
    
    $
    81,902
    
    
    $
    42,294
    
    
    $
    
    
    
    $
    
    
    
    $
    124,196Unproved
    
    
    20,966
    
    
    
    13,610
    
    
    
    
    
    
    
    
    
    
    
    34,576102,868
    
    
    
    55,904
    
    
    
    
    
    
    
    
    
    
    
    158,772Accumulated depletion
    
    
    (12,102
    )
    
    
    (7,697
    )
    
    
    
    
    
    
    
    
    
    
    (19,799
    )Accumulated provision for impairment
    
    
    (50,350
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (50,350
    )40,416
    
    
    
    48,207
    
    
    
    
    
    
    
    
    
    
    
    88,623GTL and EOR Investments:GTL master license
    
    
    
    
    
    
    
    
    
    
    10,000
    
    
    
    
    
    
    
    10,000Feasibility studies and other deferred costs
    
    
    
    
    
    
    
    
    
    
    4,008
    
    
    
    3,804
    
    
    
    7,812
    
    
    
    
    
    
    
    14,008
    
    

    
    3,804
    
    
    
    17,812Furniture and equipment
    
    
    435
    
    
    
    91
    
    
    
    
    
    
    
    12
    
    
    
    538Accumulated depreciation
    
    
    (326
    )
    
    
    (25
    )
    
    
    
    
    
    
    (1
    )
    
    
    (352
    )109
    
    
    
    66
    
    
    
    
    
    
    
    11
    
    
    
    186$
    40,525
    
    
    $
    48,273
    
    
    $
    14,008
    
    
    $
    3,815
    
    
    $
    106,621
 6




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##### 



As at December 31, 2004Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    TotalOil and Gas Properties:Proved
    
    $
    81,648
    
    
    $
    35,771
    
    
    $
    
    
    
    $
    
    
    
    $
    117,419Unproved
    
    
    20,447
    
    
    
    10,581
    
    
    
    
    
    
    
    
    
    
    
    31,028102,095
    
    
    
    46,352
    
    
    
    
    
    
    
    
    
    
    
    148,447Accumulated depletion
    
    
    (10,956
    )
    
    
    (6,663
    )
    
    
    
    
    
    
    
    
    
    
    (17,619
    )Accumulated provision for impairment
    
    
    (50,350
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (50,350
    )40,789
    
    
    
    39,689
    
    
    
    
    
    
    
    
    
    
    
    80,478GTL and EOR Investments:GTL master license
    
    
    
    
    
    
    
    
    
    
    10,000
    
    
    
    
    
    
    
    10,000Feasibility studies and other deferred costs
    
    
    
    
    
    
    
    
    
    
    3,793
    
    
    
    2,091
    
    
    
    5,884
    
    
    
    
    
    
    
    13,793
    
    
    
    2,091
    
    
    
    15,884Furniture and equipment
    
    
    417
    
    
    
    84
    
    
    
    
    
    
    
    11
    
    
    
    512Accumulated depreciation
    
    
    (300
    )
    
    
    (22
    )
    
    
    
    
    
    
    (1
    )
    
    
    (323
    )117
    
    
    
    62
    
    
    
    
    
    
    
    10
    
    
    
    189$
    40,906
    
    
    $
    39,751
    
    
    $
    13,793
    
    
    $
    2,101
    
    
    $
    96,551
 Included in proved properties as at March 31, 2005 and December 31, 2004 is $0.6 million of
costs associated with future asset retirement and abandonment of oil and gas properties in the U.S. Costs as at March 31, 2005 and December 31, 2004 of $34.6 million and $31.0 million, respectively,
related to unproved oil and gas properties were excluded from the depletion and ceiling test
calculations. For the three-month periods ended March 31, 2005 and 2004, general and administrative expenses
related directly to oil and gas acquisition, exploration and development activities, and
investments in GTL and EOR projects of $0.9 million and $0.7 million, respectively, were
capitalized. 3. LONG TERM ASSETS During 2004, the Company acquired a 15% equity interest in Ensyn Petroleum International Ltd.
(EPIL) and exclusive rights to use the proprietary Ensyn RTPTM Technology
(RTPTMTechnology) in key international markets. The RTPTM Technology,
patented in the U.S., Canada and other countries, upgrades the quality of heavy oil by producing
lighter, more valuable crude oil. In December 2004, the Company and Ensyn Group, Inc. (Ensyn),
the parent company of EPIL, announced the signing of an Agreement and Plan of Merger (Merger
Agreement) in which Ensyn will be merged with the Company (Merger) and Ensyn will become a
wholly owned subsidiary of the Company. With this Merger, the Company will gain full ownership of
EPIL and the exclusive right to employ the RTPTM Technology for petroleum process
applications worldwide (See Note 11). The cost to acquire the 15% equity interest in Ensyn Petroleum International Ltd. of $3.0 million
plus $3.2 million and $2.5 million of costs as at March 31, 2005 and December 31, 2004,
respectively, incurred by the Company associated with the Merger are included in long-term assets. 4. SEGMENT INFORMATION The following tables present the Companys interim segment information for the three-month periods
ended March 31, 2005 and 2004 and identifiable assets as at March 31, 2005 and December 31, 2004: 7




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##### 



Three-Month Period Ended March 31, 2005Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    Corporate
    
    
    TotalOil and gas revenue
    
    $
    2,869
    
    
    $
    2,824
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    5,693Interest income
    
    
    6
    
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    35
    
    
    
    432,875
    
    
    
    2,826
    
    
    
    
    
    
    
    
    
    
    
    35
    
    
    
    5,736Operating costs
    
    
    1,116
    
    
    
    646
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,762General, administrative and business development
    
    
    157
    
    
    
    224
    
    
    
    404
    
    
    
    315
    
    
    
    2,030
    
    
    
    3,130Depletion and depreciation
    
    
    1,167
    
    
    
    1,034
    
    
    
    3
    
    
    
    2
    
    
    
    1
    
    
    
    2,207Interest expense
    
    
    70
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    50
    
    
    
    1202,510
    
    
    
    1,904
    
    
    
    407
    
    
    
    317
    
    
    
    2,081
    
    
    
    7,219Net (Income) Loss
    
    $
    (365
    )
    
    $
    (922
    )
    
    $
    407
    
    
    $
    317
    
    
    $
    2,046
    
    
    $
    1,483Capital Investments
    
    $
    799
    
    
    $
    9,806
    
    
    $
    215
    
    
    $
    1,714
    
    
    $
    
    
    
    $
    12,534Identifiable Assets (As at March 31, 2005)
    
    $
    47,602
    
    
    $
    54,501
    
    
    $
    14,056
    
    
    $
    3,891
    
    
    $
    10,287
    
    
    $
    130,337Identifiable Assets (As at December 31, 2004)
    
    $
    49,465
    
    
    $
    44,960
    
    
    $
    13,867
    
    
    $
    2,441
    
    
    $
    7,753
    
    
    $
    118,486
 Three-Month Period Ended March 31, 2004Oil and GasU.S.
    
    
    China
    
    
    GTL
    
    
    EOR
    
    
    Corporate
    
    
    TotalOil and gas revenue
    
    $
    1,793
    
    
    $
    1,499
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    3,292Interest income
    
    
    2
    
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    35
    
    
    
    401,795
    
    
    
    1,502
    
    
    
    
    
    
    
    
    
    
    
    35
    
    
    
    3,332Operating costs
    
    
    755
    
    
    
    520
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,275General, administrative and business development
    
    
    106
    
    
    
    256
    
    
    
    277
    
    
    
    
    
    
    
    1,241
    
    
    
    1,880Depletion and depreciation
    
    
    863
    
    
    
    577
    
    
    
    5
    
    
    
    
    
    
    
    1
    
    
    
    1,446Interest expense
    
    
    22
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    231,746
    
    
    
    1,353
    
    
    
    282
    
    
    
    
    
    
    
    1,243
    
    
    
    4,624Net (Income) Loss
    
    $
    (49
    )
    
    $
    (149
    )
    
    $
    282
    
    
    $
    
    
    
    $
    1,208
    
    
    $
    1,292Capital Investments
    
    $
    3,118
    
    
    $
    6,875
    
    
    $
    67
    
    
    $
    363
    
    
    $
    
    
    
    $
    10,423
 5. SHARE CAPITAL Following is a summary of the changes in share capital and stock options outstanding for the
three-month period ended March 31, 2005: Common Shares
    
    
    
    
    
    
    Stock OptionsWeightedAverageExerciseNumber
    
    
    
    
    
    
    Contributed
    
    
    Number
    
    
    Price(thousands)
    
    
    Amount
    
    
    Surplus
    
    
    (thousands)
    
    
    Cdn.$Balance December 31, 2004
    
    
    169,665
    
    
    $
    183,617
    
    
    $
    1,748
    
    
    
    8,246
    
    
    $
    2.65Shares issued for services
    
    
    192
    
    
    
    441
    
    
    
    
    
    
    
    
    
    
    
    Shares issued on exercise of options
    
    
    35
    
    
    
    44
    
    
    
    (9
    )
    
    
    (35
    )
    
    $
    1.42Options granted
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    363
    
    
    $
    3.12Options expired
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (60
    )
    
    $
    1.42Stock based compensation
    
    
    
    
    
    
    
    
    
    
    296
    
    
    
    
    
    
    $
    Balance March 31, 2005
    
    
    169,892
    
    
    $
    184,102
    
    
    $
    2,035
    
    
    
    8,514
    
    
    $
    2.68
 8




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##### 



As at March 31, 2005, the following purchase warrants are exercisable to purchase additional
common shares through the anniversary dates of the special warrant financing at the price per share
as indicated: Year of
    
    Price per
    
    
    Number of
    
    
    Remaining
    
    
    
    
    
    
    Second AnniversarySpecial
    
    Special
    
    
    Purchase
    
    
    Number of
    
    
    Number of
    
    
    
    
    Price perWarrant
    
    Warrant
    
    
    Warrants
    
    
    Purchase
    
    
    Common
    
    
    
    
    ShareFinancing
    
    (U.S.$)
    
    
    Issued
    
    
    Warrants
    
    
    Shares
    
    
    Date
    
    (US$)(thousands)2003
    
    $
    1.00
    
    
    
    3,000
    
    
    
    3,000
    
    
    
    1,500
    
    
    July 3, 2005
    
    $
    1.102003
    
    $
    1.00
    
    
    
    3,000
    
    
    
    3,000
    
    
    
    1,500
    
    
    August 18, 2005
    
    $
    1.102003
    
    $
    1.70
    
    
    
    3,529
    
    
    
    3,029
    
    
    
    1,515
    
    
    August 21, 2005
    
    $
    1.872003
    
    $
    4.00
    
    
    
    1,250
    
    
    
    1,250
    
    
    
    1,250
    
    
    October 31, 2005
    
    $
    4.302004
    
    $
    2.90
    
    
    
    5,449
    
    
    
    5,449
    
    
    
    2,725
    
    
    February 18, 2006
    
    $
    3.202004
    
    $
    2.90
    
    
    
    1,724
    
    
    
    1,724
    
    
    
    862
    
    
    March 5, 2006
    
    $
    3.2017,952
    
    
    
    17,452
    
    
    
    9,352
 6. STOCK BASED COMPENSATION The Company accounts for all stock options granted using the fair value based method of accounting.
This method was adopted effective January 1, 2004 for stock options granted to employees and
directors after January 1, 2002. Under this method, compensation costs are recognized in the
financial statements over the stock options vesting period using an option-pricing model for determining the
fair value of the stock options at the grant date. For the three-month periods ended March 31, 2005 and 2004, the Company expensed $0.3 million and
$0.2 million, respectively, in stock based compensation, which is included in general and
administrative expense. 7. NOTE AND ADVANCE PAYABLE In February 2003, the Company obtained a bank facility for up to $5.0 million to develop the
southern expansion of its South Midway field. The note is repayable over three years starting
August 2004 with interest at 0.5% above the banks prime rate or 3.0% over the London Inter-Bank
Offered rate (LIBOR), at the option of the Company. The note is secured by all the Companys
rights and interests in the South Midway properties. The note balance, as at March 31, 2005 and
December 31, 2004, was $3.9 million and $4.3 million, respectively, with a six-month fixed LIBOR
rate of 5.25% per annum as at March 31, 2005. The scheduled maturities of the bank note payable as at March 31, 2005 were as follows: 2005
    
    $
    1,2502006
    
    
    1,6672007
    
    
    9723,889Less: current portion
    
    
    1,667$
    2,222
 In March 2004, the Company received a $10.0 million advance as part of a $20.0 million
up-front payment due to a farm-in to the Companys Dagang oil project. Upon finalization of the
farm-in agreement in June 2004, the Companys farm-in partner elected to apply $10.0 million of the
up-front payment due to the Company against the advance. 8. CONVERTIBLE LOAN The $6.0 million unsecured convertible loan bears interest at 8.0% per annum and is due upon the
earliest of i.) five days following receipt of proceeds from a private placement or public offering
of Company common shares ii.) ninety days following written demand for repayment from lender or
iii.) August 23, 2005. During the term of the loan the lender may convert at its option unpaid
principal and interest, in whole or in part, to the Companys common shares at $2.25 per share. The
fair value of the convertible loan approximates its carrying value due to the 9




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##### 



short-term maturity. No value was assigned to the equity component of the loan. The lender waived its right to have the
loan repaid from the proceeds of the special warrant financing described in Note 11. 9. ASSET RETIREMENT OBLIGATIONS The undiscounted amount of expected cash flows required to settle the Companys asset retirement
obligations as at March 31, 2005 was estimated at $1.3 million to be settled over a twelve-year
period starting in 2010. The liability for the expected cash flows, as reflected in the financial
statements, has been discounted at 5% to 7%. 10. COMMITMENTS AND CONTINGENCIES Zitong Exploration Commitment With the signing of the production-sharing contract in September 2002 for the Zitong block, the
Company is obligated to conduct a minimum exploration program during the first three years, which
will include acquiring seismic data, reprocessing existing seismic and drilling two exploration
wells. At the end of the three-year period, if the Company does not complete the minimum exploration program,
and elects not to continue, it will be obligated to pay, to PetroChina within 30 days, a cash
equivalent of the deficiency in the work program. The remaining cost of the minimum exploration
program is estimated to be $9.4 million as at March 31, 2005. Northwest Lost Hills Abandonment The Company has temporarily abandoned the Northwest Lost Hills #1-22 well pending the
identification of one or more partners to share the costs of the testing program. If the well were
permanently abandoned, the Company would be obligated for its share of the costs to plug and
abandon the well, which is estimated to be $1.1 million. There is no provision in the balance sheet
for this conditional obligation. 11. SUBSEQUENT EVENTS On April 15, 2005, the Company and Ensyn completed the Merger (as more fully described in the
Companys 2004 Annual Report filed on Form 10-K) in which the Company paid $10.0 million in cash
and issued 30 million Ivanhoe common shares (Merger Shares) in exchange for all of the issued and
outstanding Ensyn common shares. Ten million of the Merger Shares issued were deposited in an
escrow fund and will be held to secure certain obligations on the part of the former Ensyn
stockholders to indemnify the Company for damages arising from any breaches of warranties and
covenants in the Merger Agreement and certain liabilities. The estimated total purchase consideration and cost of acquisition was $89.0 million as follows: Purchase Consideration29,999,886 Company shares at $2.50 per share
    
    $
    75,000Cash
    
    
    10,00085,000Acquisition related costs
    
    
    4,000Total purchase consideration and cost of acquisition
    
    $
    89,000Net Assets AcquiredNet current liabilities
    
    $
    (96
    )Tangible assets
    
    
    4,465Intangible assets
    
    
    87,631Less : previous investment in EPIL
    
    
    (3,000
    )$
    89,000
 Intangible assets consist of the underlying value of the exclusive, perpetual license to
deploy the RTPTM Technology for petroleum process applications worldwide. The intangible
assets are subject to periodic tests for impairment. 10




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##### 



On April 15, 2005, the Company closed a $10.3 million special warrant financing, by way of a
private placement, with six institutional and individual investors. Proceeds from the financing
were used to complete the acquisition of Ensyn and for general corporate purposes. The financing
consisted of 4,100,000 special warrants at Cdn.$3.10 per special warrant. Each special warrant
entitles the holder to receive, at no additional cost, one common share and one common share
purchase warrant before or immediately following the filing and regulatory acceptance of a Canadian
prospectus, or four months after the closing date, which ever occurs first. Two common share
purchase warrants will entitle the holder to purchase one common share at a price of Cdn.$3.50
exercisable until the first anniversary date of the closing. 12. ADDITIONAL DISCLOSURE REQUIRED UNDER U.S. GAAP The consolidated financial statements have been prepared in accordance with Canadian GAAP, which
conforms to U.S. GAAP except as described below: Condensed Consolidated Balance Sheets Shareholders Equity and Oil and Gas Properties and Investments As at March 31, 2005Oil and Gas
    
    

Shareholders EquityProperties and
    
    
    
    
    
    
    Contributed
    
    
    AccumulatedInvestments
    
    
    Share Capital
    
    
    Surplus
    
    
    Deficit
    
    
    TotalCanadian GAAP
    
    $
    106,621
    
    
    $
    184,102
    
    
    $
    2,035
    
    
    $
    (83,262
    )
    
    $
    102,875Adjustment for reduction in stated capital
    
    
    
    
    
    
    74,455
    
    
    
    
    
    
    
    (74,455
    )
    
    
    Adjustment to ascribed value of shares
issued for U.S. royalty interests, net
    
    
    1,358
    
    
    
    1,358
    
    
    
    
    
    
    
    
    
    
    
    1,358Provision for impairment
    
    
    (8,650
    )
    
    
    
    
    
    
    
    
    
    
    (8,650
    )
    
    
    (8,650
    )Depletion adjustments due to differences in
provision for impairment
    
    
    654
    
    
    
    
    
    
    
    
    
    
    
    654
    
    
    
    654GTL and EOR development costs expensed
    
    
    (7,812
    )
    
    
    
    
    
    
    
    
    
    
    (7,812
    )
    
    
    (7,812
    )Adjustment for change in accounting for
stock based compensation
    
    
    
    
    
    
    (300
    )
    
    
    (1,892
    )
    
    
    2,192
    
    
    
    U.S. GAAP
    
    $
    92,171
    
    
    $
    259,615
    
    
    $
    143
    
    
    $
    (171,333
    )
    
    $
    88,425
 As at December 31, 2004Oil and Gas
    
    

Shareholders EquityProperties and
    
    
    
    
    
    
    Contributed
    
    
    AccumulatedInvestments
    
    
    Share Capital
    
    
    Surplus
    
    
    Deficit
    
    
    TotalCanadian GAAP
    
    $
    96,551
    
    
    $
    183,617
    
    
    $
    1,748
    
    
    $
    (81,779
    )
    
    $
    103,586Adjustment for reduction in stated capital
    
    
    
    
    
    
    74,455
    
    
    
    
    
    
    
    (74,455
    )
    
    
    Adjustment to ascribed value of shares
issued for U.S. royalty interests, net
    
    
    1,358
    
    
    
    1,358
    
    
    
    
    
    
    
    
    
    
    
    1,358Provision for impairment
    
    
    (8,650
    )
    
    
    
    
    
    
    
    
    
    
    (8,650
    )
    
    
    (8,650
    )Depletion adjustments due to differences in
provision for impairment
    
    
    482
    
    
    
    
    
    
    
    
    
    
    
    482
    
    
    
    482GTL and EOR development costs expensed
    
    
    (5,884
    )
    
    
    
    
    
    
    
    
    
    
    (5,884
    )
    
    
    (5,884
    )Adjustment for change in accounting for
stock based compensation
    
    
    
    
    
    
    (300
    )
    
    
    (1,660
    )
    
    
    1,960
    
    
    
    U.S. GAAP
    
    $
    83,856
    
    
    $
    259,130
    
    
    $
    88
    
    
    $
    (168,326
    )
    
    $
    90,892
 Share Capital and Accumulated Deficit In June 1999, the shareholders approved a reduction of stated capital in respect of the common
shares by an amount of $74.4 million being equal to the accumulated deficit as at December 31,
1998. Under U.S. GAAP, a 11




---



##### 



reduction of the accumulated deficit such as this is not recognized except
in the case of a quasi reorganization. The effect of this is that under U.S. GAAP, share capital
and accumulated deficit are increased by $74.4 million as at March 31, 2005 and December 31, 2004. Oil and Gas Properties and Investments As more fully described in our financial statements in Item 8 of our 2004 Annual Report filed on
Form 10-K, there are differences between the full cost method of accounting for oil and gas
properties as applied in Canada and as applied in the U.S. The principal difference is in the method of
performing ceiling test evaluations under the full cost method of accounting rules. The Company
performed the ceiling test in accordance with U.S. GAAP and determined that for 2004 an impairment
provision of $15.0 million was required on its U.S. oil and gas properties compared to a $16.3
million impairment provision under Canadian GAAP. For 2001, a $10.0 million provision for
impairment was required, for U.S. GAAP purposes, in connection with the Companys China oil and gas
properties. These differences result in accumulated net additional impairment provisions of $8.7
million for U.S. GAAP purposes as at March 31, 2005 and December 31, 2004. The differences in the amount of impairment provisions between Canadian and U.S. GAAP resulted in a
reduction in accumulated depletion of $0.7 million and $0.5 million as at March 31, 2005 and
December 31, 2004, respectively. As more fully described in our financial statements in Item 8 of our 2004 Annual Report filed on
Form 10-K, for Canadian GAAP, the Company capitalizes certain costs incurred for GTL and EOR
projects subsequent to executing a memorandum of understanding to determine the technical and
commercial feasibility of a project, including studies for the marketability for the projects
products. If no definitive agreement is reached, then the projects capitalized costs, which are
deemed to have no future value, are written down and charged to operations with a corresponding
reduction in the investments in GTL and EOR assets. For U.S. GAAP, feasibility, marketing and related costs are considered to be research and
development and are expensed as incurred. As at March 31, 2005 and December 31, 2004, the Company
capitalized $7.8 million and $5.9 million, respectively, for Canadian GAAP, which was expensed for
U.S. GAAP purposes. For U.S. GAAP purposes, the aggregate value attributed to the acquisition of U.S. royalty rights
during 1999 and 2000 was $1.4 million higher, due to the difference between Canadian and U.S. GAAP
in the value ascribed to the shares issued, primarily resulting from differences in the recognition
of effective dates of the transactions. For the year ended December 31, 2004, a ceiling test
impairment of $1.0 million of the U.S. GAAP difference related to royalty rights was recognized in
the results of operations. Condensed Consolidated Statements of Loss The application of U.S. GAAP had the following effects on net loss and net loss per share as
reported under Canadian GAAP: Three-Month Periods Ended March 31,2005
    
    
    2004Net
    
    
    Net Loss
    
    
    Net
    
    
    Net LossLoss
    
    
    Per Share
    
    
    Loss
    
    
    Per ShareCanadian GAAP
    
    $
    1,483
    
    
    $
    0.01
    
    
    $
    1,292
    
    
    $
    0.01Stock based compensation expense
    
    
    (232
    )
    
    
    
    
    
    
    (229
    )
    
    
    Depletion adjustments due to differences in
provision for impairment
    
    
    (172
    )
    
    
    
    
    
    
    (23
    )
    
    
    GTL and EOR development costs expensed, net
    
    
    1,929
    
    
    
    0.01
    
    
    
    430
    
    
    
    U.S. GAAP
    
    $
    3,008
    
    
    
    0.02
    
    
    $
    1,470
    
    
    $
    0.01Weighted Average Number of Shares under U.S.
GAAP (in thousands)
    
    
    
    
    
    
    169,816
    
    
    
    
    
    
    
    162,127
 As discussed under Oil and Gas Properties and Investments in this note, there is a
difference in performing the 12




---



##### 



ceiling test evaluation under the full cost method of accounting between U.S. and Canadian GAAP. Application of the ceiling test evaluation under U.S. GAAP resulted
in accumulated net additional impairment provisions of $8.7 million for U.S. GAAP purposes as at
March 31, 2005 and December 31, 2004. The net increase in impairment provisions resulted in lower depletion rates
for U.S. GAAP purposes and a reduction of $0.2 million in the net loss for the three-month period
ended March 31, 2005 and a minimal reduction in the net loss for the three-month period ended March
31, 2004. For Canadian GAAP, the Company accounts for all stock options granted using the fair value based
method of accounting. Under this method, compensation costs are recognized in the financial
statements over the stock options vesting period using an option-pricing model for determining the
fair value of the stock options at the grant date. For U.S. GAAP, the Company continues to apply
APB Opinion No. 25, as interpreted by FASB Interpretation No. 44, in accounting for its stock
option plan and does not recognize compensation costs in its financial statements for
stock options issued to employees and directors. For U.S. GAAP purposes, this resulted in a
reduction of $0.2 million in the net losses for the three-month periods ended March 31, 2005 and
2004. As described under Oil and Gas Properties and Investments in this note, for Canadian GAAP,
feasibility, marketing and related costs incurred prior to executing a GTL or EOR definitive
agreement are capitalized and are subsequently written down upon determination that a projects
future value has been impaired. For U.S. GAAP, such costs are considered to be research and
development and are expensed as incurred. For the three-month periods ended March 31, 2005 and
2004, the Company expensed $1.9 million and $0.4 million, respectively, of GTL and EOR development
costs for U.S. GAAP purposes. Stock Based Compensation Had stock based compensation expense been determined based on fair value at the stock option grant
date, consistent with the method of SFAS No. 123, Accounting for Stock Based Compensation, the
Companys net loss and net loss per share would have been increased to the pro forma amounts
indicated below: Three-Month PeriodsEnded March 31,2005
    
    
    2004Net loss under U.S. GAAP
    
    $
    3,008
    
    
    $
    1,470Stock-based compensation expense determined under the fair
value based method for employee and director awards
    
    
    263
    
    
    
    494Pro forma net loss under U.S. GAAP
    
    $
    3,271
    
    
    $
    1,964Basic loss per common share under U.S. GAAP:As reported
    
    $
    0.02
    
    
    $
    0.01Pro forma
    
    $
    0.02
    
    
    $
    0.01Weighted Average Number of Shares under U.S. GAAP (in thousands)
    
    
    169,816
    
    
    
    162,127
 Stock based compensation for U.S. GAAP was calculated in accordance with the Black Scholes
option-pricing model using the same assumptions as used for Canadian GAAP. Condensed Consolidated Statements of Cash Flow As a result of the write-down of GTL and EOR development costs required under U.S. GAAP, the
statements of cash flow as reported would result in a cash deficiency from operating activities of
$1.2 million and $1.5 million for the three-month periods ended March 31, 2005 and 2004,
respectively. Additionally, capital investments reported under investing activities would be $10.6
million and $10.0 million for the same periods ended, respectively. 13




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##### 



Impact of New and Pending Canadian GAAP Accounting Standards In January 2005, the CICA approved Section 1530 Comprehensive Income (S.1530), Section 3855
Financial Instruments  Recognition and Measurement (S.3855) and Section 3865 Hedges
(S.3865) to harmonize financial instrument and hedge accounting with U.S. GAAP and introduce the
concept of comprehensive income. S.1530 requires presentation of certain gains and losses outside
of net income, such as unrealized gains and losses related to hedges or other derivative
instruments. S.3855 establishes standards for recognizing and measuring financial assets and
financial liabilities and non-financial derivatives as required to be disclosed under Section 3861
Financial Instruments Disclosure and Presentation. S.3865 establishes standards for how and when
hedge accounting may be applied. We apply SFAS No. 133 Accounting for Derivative Instruments and
Hedging Activities for U.S. GAAP purposes and will implement S.3865 for Canadian GAAP for hedging
activities. These sections apply to interim and annual financial statements relating to fiscal
years beginning on or after October 1, 2006 and are not expected to have a material impact on our
financial statements. In January 2005, the CICA approved Section 3251 Equity which establishes standards for the
presentation of equity and changes in equity during a reporting period. This section applies to
interim and annual financial statements relating to fiscal years beginning on or after October 1,
2006 and is not expected to have a material impact on our financial statements. Effective January 1, 2005, the Company adopted revised Canadian Institute of Chartered Accountants
(CICA) Accounting Guideline 15 (AcG 15), Consolidation of Variable Interest Entities. AcG 15
is harmonized in all material respects with U.S. GAAP and provides guidance for applying
consolidation principles to certain entities (defined as VIEs) that are subject to control on a
basis other than ownership of voting interests. An entity is a VIE when, by design, one or both of
the following conditions exist: (a) total equity investment at risk is insufficient to permit that
entity to finance its activities without additional subordinated support from other parties; (b) as
a group, the holders of the equity investment at risk lack certain essential characteristics of a
controlling financial interest. AcG 15 requires consolidation by a business of VIEs in which it is
the primary beneficiary. The primary beneficiary is defined as the party that has exposure to the
majority of the expected losses and/or expected residual returns of the VIE. AcG 15 does not impact
us at this time. Impact of New and Pending U.S. GAAP Accounting Standards In June 2004, the Financial Accounting Standards Board (FASB) issued an exposure draft of a
proposed statement, Fair Value Measurements to provide guidance on how to measure the fair value
of financial and non-financial assets and liabilities when required by other authoritative
accounting pronouncements. The proposed statement attempts to address concerns about the ability to
develop reliable estimates of fair value and inconsistencies in fair value guidance provided by
current U.S. GAAP, by creating a framework that clarifies the fair value objective and its
application in GAAP. In addition, the proposal expands disclosures required about the use of fair
value to re-measure assets and liabilities. The standard would be effective for financial
statements issued for fiscal years beginning after June 15, 2005. In December 2004, the FASB issued a revision to SFAS No. 123, Accounting for Stock Based
Compensation which supersedes APB No. 25, Accounting for Stock Issued to Employees. This
statement requires measurement of the cost of employee services received in exchange for an award
of equity instruments based on the fair value of the award on the date of the grant and recognition
of the cost in the results of operations over the period during which an employee is required to
provide service in exchange for the award. No compensation cost is recognized for equity
instruments for which employees do not render the requisite service. The Company applies APB
Opinion No. 25, as interpreted by FASB Interpretation No. 44, in accounting for awards issued from
our stock option plan and does not recognize compensation costs in its U.S. GAAP financial
statements for stock options issued to its employees and directors. This statement is effective for
the first fiscal year that begins after June 15, 2005 and may be implemented on a modified prospective or retrospective basis. The Company
has elected to implement this statement on a modified prospective basis starting in the first
quarter of 2006. Under the modified prospective basis the Company would recognize stock based
compensation in its U.S. GAAP results of operations for the unvested portion of awards outstanding
as of January 1, 2006 and for all awards granted after January 1, 2006. 14




---



##### 



In March 2005, the FASB issued Interpretation No. 47 (FIN 47) Accounting for Conditional Asset
Retirement Obligations  an interpretation of FASB Statement No. 143. A conditional asset
retirement obligation refers to a legal obligation to perform an asset retirement activity in which
the timing and (or) method of settlement are conditional on a future event that may or may not be
within the control of the entity. The obligation to perform the asset retirement activity is
unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus,
the timing and (or) method of settlement may be conditional on a future event. FIN 47 requires an
entity to recognize a liability for the fair value of a conditional asset retirement obligation if
the fair value of the liability can be reasonably estimated. FIN 47 is effective no later than the
end of fiscal years ending after December 15, 2005 (December 31, 2005, for calendar-year
enterprises). Retrospective application for interim financial information is permitted but is not
required. The Company has a conditional asset retirement obligation with respect to the abandonment
of its Northwest Lost Hills # 1-22 well. Had the Company implemented FIN 47 for the three-month
period ended March 31, 2005, it would have recognized approximately $0.7 million in additional
asset retirement costs and asset retirement obligations and approximately $0.1 million of
cumulative accretion expense in its results of operations. The following standards issued by the FASB do not impact the Company at this time: SFAS No. 151, Inventory Costsan amendment of ARB No. 43, Chapter 4 effective for inventory costs
incurred during fiscal years beginning after June 15, 2005. SFAS No. 153, Exchanges of Nonmonetary Assetsan amendment of APB Opinion No. 29 effective for
nonmonetary asset exchanges occurring in fiscal years beginning after June 15, 2005. 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 Form 10-Q are
forward looking statements that involve risks and uncertainties. Certain statements contained in
this Form 10-Q, including statements which may contain words such as could, should, expect,
believe, will and similar expressions and statements relating to matters that are not
historical facts are forward-looking statements. Such statements involve known and unknown risks
and uncertainties which may cause our actual results, performances or achievements to be materially
different from any future results, performance or achievements expressed or implied by such
forward-looking statements. Although we believe that our expectations are based on reasonable
assumptions, we can give no assurance that our goals will be achieved. Important factors that
could cause actual results to differ materially from those in the forward-looking statements herein
include, but are not limited to, our ability to raise capital as and when required, the timing and
extent of changes in prices for oil and gas, competition, environmental risks, drilling and
operating risks, uncertainties about the estimates of reserves and the potential success of
heavy-to-light and gas-to-liquids development technologies, 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 we operate and implementation of our capital
investment program. The following should be read in conjunction with the Companys consolidated financial statements
contained herein and in the Form 10-K for the year ended December 31, 2004, along with Managements
Discussion and Analysis of Financial Condition and Results of Operations contained in
such Form 10-K. Any terms used but not defined in the following discussion have the same meaning
given to them in the Form 10-K. The unaudited condensed consolidated financial statements in this
Quarterly Report filed on Form 10-Q have been prepared in accordance with generally accepted
accounting principles in Canada. The impact of significant differences between Canadian and U.S.
accounting principles on the unaudited condensed consolidated financial statements is disclosed in
Note 12. The date of this discussion is April 29, 2005. Executive Overview of 2005 Results Although our revenues for the first quarter of 2005 improved significantly over those achieved
during the comparable period in 2004, our net loss increased $0.2 million from the comparable
period in 2004. Oil and gas 15




---



##### 



revenues for the first quarter of 2005 increased by 73% to $5.7 million due equally to an increase in production volumes as well as higher oil and gas prices.
However, this improvement was offset by increased costs related to our significant EOR and HTL
business development activities, professional fees related to our assessment of the effectiveness
of the design and operation of our internal control over financial reporting pursuant to Section
404 of the Sarbanes-Oxley Act of 2002 and higher depletion costs. Despite these cost increases, we
achieved positive cash flow from operations of $0.8 million for the first quarter of 2005 compared
to a deficit of $1.0 million for the comparable period in 2004. We are excited about the progress we made in the first quarter of 2005 and ongoing developments in
our EOR projects including our HTL initiatives. The RTPTM Commercial Demonstration
Facility (RTPTMCDF) near Bakersfield, California was successfully tested and we
completed our merger with Ensyn in April 2005 whereby Ensyn became a wholly-owned subsidiary of
Ivanhoe and Ensyn changed its name to Ivanhoe Energy HTL Inc. With the completion of the Merger we have the exclusive right to employ the RTP Technology for
petroleum process applications worldwide and we are actively pursing opportunities for the
commercial deployment of the technology in a number of countries. Our single goal remains the
building of oil and gas reserves and production. We intend to use the RTP Technology as a tool to
acquire and develop heavy oil reserves around the world. The following table sets forth certain selected consolidated data for the first quarters of 2005
and 2004: Three-Month Periods EndedMarch 31,(stated in thousands of U.S. dollars, except per share and production amounts)
    
    2005
    
    
    2004Oil and gas revenue
    
    $
    5,693
    
    
    $
    3,292Net loss
    
    $
    1,483
    
    
    $
    1,292Net loss per share
    
    $
    0.01
    
    
    $
    0.01Average production (Mboe/d)
    
    
    1,664
    
    
    
    1,195Capital investments
    
    $
    12,534
    
    
    $
    10,423Cash flow (deficit) from operating activities
    
    $
    776
    
    
    $
    (1,046
    )
 Financial Results  Quarter to Quarter Change in Net Loss The following provides an analysis of our changes in net losses for the first quarter of 2005 when
compared to the same period for 2004: 16




---



##### 



(stated in thousands of U.S. Dollars)
    
    2005 vs. 2004Net Loss for the three-month period ended March 31, 2004
    
    $
    1,292Favorable (unfavorable) variances:Cash Items:Net Operating Revenues:Production volumes
    
    
    1,237Oil and gas prices
    
    
    1,164Less: Operating costs
    
    
    (487
    )1,914General, administrative and business development
    
    
    (1,193
    )Net interest
    
    
    (94
    )Total Cash Variances
    
    
    627Non-Cash Items:Depletion and depreciation
    
    
    (761
    )Stock based compensation
    
    
    (57
    )Total Non-Cash Variances
    
    
    (818
    )Net Loss for the three-month period ended March 31, 2005
    
    $
    1,483
 Our net loss for the first quarter of 2005 was $1.5 million ($0.01 per share) compared to our
net loss for the same period in 2004 of $1.3 million ($0.01 per share). The increase in our net
loss from 2004 to 2005 of $0.2 million is mainly due to $1.3 million increase in general,
administrative and business development expense, including stock based compensation, and an
increase of $0.8 in depletion and depreciation. This is partially offset by a $1.9 million increase
in net operating revenues. Significant variances in our net losses are explained in the sections that follow. Net Operating Revenues  
    Production Volumes 2005 vs. 2004 Net production volumes for the first quarter of 2005 increased 38% when compared to the same period
in 2004 due to 43% and 33% increases in production volumes in our China and U.S. properties,
respectively, resulting in increased revenues of $1.2 million. Net production volumes at the Dagang field increased 46% in the first quarter of 2005 compared to
the same period in 2004 despite the farm-out of a 40% working interest in June 2004. In the first
quarter of 2005, we placed an additional 6 wells on production bringing the total wells on
production or available for production to 28 wells at quarter-end. However, our gross production
exit rate at the Dagang field decreased 21% from the end of 2004 to March 31, 2005 as we
experienced higher water cuts, particularly in the older wells, and our most productive well was
shut-in due to a maintenance workover at the end of the first quarter of 2005. Additionally,
results from the new wells drilled in the northern blocks of the Dagang field have been less than
expected, with initial unstimulated production of approximately 75 Bopd per well. We continue to benefit from the expanded Daqing development program and the royalty interest we
hold. Royalty volumes for the first quarter of 2005 increased 32% over the same 2004 period. Net production volumes in the U.S. increased 33% mainly from our Citrus and Knights Landing fields.
Three Citrus wells were on production in the first quarter of 2005 compared to only 1 well for the
same period in 2004. We farmed into the Knights Landing gas field in northern California in
February 2004 with a 50% working interest in 4 producing natural gas wells, which started
production in April 2004. In December 2004, we increased our working interest to between 80% and
100% in 12 Knights Landing natural gas wells capable of production. We continue to see increased
production rates from our successful drilling and steaming operations at our South Midway field. We
drilled 4 producing South Midway wells in the second quarter of 2004, increased our steam 17




---



##### 



injection in the primary area of South Midway in the third quarter of 2004 and started a continuous steam injection pilot program
in the southern expansion of South Midway in the fourth quarter of 2004, all of which have
contributed to the increased production rates at South Midway for the first quarter of 2005. The following is a comparison of changes in production volumes for the first quarter of 2005 when
compared to the same period in 2004: Average
Net Boes
    
    
    Percentage2005
    
    
    2004
    
    
    ChangeChina:Dagang
    
    
    60,236
    
    
    
    41,260
    
    
    
    46
    %Daqing
    
    
    11,999
    
    
    
    9,102
    
    
    
    32
    %72,235
    
    
    
    50,362
    
    
    
    43
    %U.S.:South Midway
    

    
    49,768
    
    
    
    43,151
    
    
    
    15
    %Citrus
    
    
    9,528
    
    
    
    3,433
    
    
    
    178
    %Knights Landing
    
    
    11,300
    
    
    
    
    
    
    
    100
    %Others
    
    
    6,941
    
    
    
    11,782
    
    
    
    -41
    %77,537
    
    
    
    58,366
    
    
    
    33
    %149,772
    
    
    
    108,728
    
    
    
    38
    %
  
    Oil and Gas Prices 2005 vs. 2004 Oil and gas prices increased 26% per Boe for the first quarter of 2005 generating $1.2 million in
additional revenue as compared to the same period in 2004. We realized an average of $39.09 per Boe
from our operations in China during the first quarter of 2005, which is an increase of $9.33 per
Boe for the same period in 2004 and accounts for $0.7 million of our increase in revenues. From the
U.S. operations, we realized an average of $37.00 per Boe during the first quarter of 2005, which
is an increase of $6.29 per Boe and accounts for $0.5 million of our increased revenues.  
    Operating Costs 2005 vs. 2004 For the first quarter of 2005, operating costs, including production taxes and engineering support,
increased $0.5 million in absolute terms from the same period in 2004 or $0.04 on a per barrel of
oil equivalent basis. Operating costs in China, including engineering support, decreased 13% or $1.38 per Boe for the
first quarter of 2005 when compared to the same period in 2004 due mainly to an increase in
production from the Dagang field in relation to the level of engineering support required to
operate the field. Operating costs in the U.S., including engineering support and production taxes, increased 11% or
$1.46 per Boe for first quarter of 2005 when compared to the same period in 2004. Field operating
costs increased $1.58 per Boe due mainly to an increase in fuel costs incurred for the increased
level of cyclic and continuous steam operations at South Midway. Engineering support increased
$0.56 per Boe due mainly to the start up of production operations at Citrus in late first quarter
of 2004 and also at Knights Landing where we became the operator in December 2004. Production taxes
are down $0.68 per Boe due mainly to a reassessment of property values at South Midway. 18




---



##### 



Production and operating information including oil and gas revenue, operating costs and depletion,
on a per Boe basis are detailed below: Three-Months Periods Ended March 31,2005
    
    
    2004U.S.
    
    
    China
    
    
    Total
    
    
    U.S.
    
    
    China
    
    
    TotalNet Production:BOE
    
    
    77,537
    
    
    
    72,235
    
    
    
    149,772
    
    
    
    58,366
    
    
    
    50,362
    
    
    
    108,728BOE/day
    
    
    862
    
    
    
    803
    
    
    
    1,664
    
    
    
    641
    
    
    
    553
    
    
    
    1,195Per Boe
    
    
    
    
    
    
    
    
    
    Per BoeOil and gas revenue
    
    $
    37.00
    
    
    $
    39.09
    
    
    $
    38.01
    
    
    $
    30.71
    
    
    $
    29.76
    
    
    $
    30.27Operating costs
    
    
    10.76
    
    
    
    7.76
    
    
    
    9.31
    
    
    
    9.18
    
    
    
    7.38
    
    
    
    8.35Production taxes
    
    
    0.50
    
    
    
    
    
    
    
    0.26
    
    
    
    1.18
    
    
    
    
    
    
    
    0.63Engineering support
    
    
    3.13
    
    
    
    1.18
    
    
    
    2.19
    
    
    
    2.57
    
    
    
    2.94
    
    
    
    2.7414.39
    
    
    
    8.94
    
    
    
    11.76
    
    
    
    12.93
    
    
    
    10.32
    
    
    
    11.72Net revenue before depletion
    
    
    22.61
    
    
    
    30.15
    
    
    
    26.25
    
    
    
    17.78
    
    
    
    19.44
    
    
    
    18.55Depletion
    
    
    14.77
    
    
    
    14.30
    
    
    
    14.54
    
    
    
    14.33
    
    
    
    11.43
    
    
    
    12.99Net revenue from operations
    
    $
    7.84
    
    
    $
    15.85
    
    
    $
    11.71
    
    
    $
    3.45
    
    
    $
    8.01
    
    
    $
    5.56
 General, Administration and Business Development Our changes in general, administrative and business development expenses, including stock based
compensation expense, by segment for the first quarter of 2005 when compared to the same period for
2004 were as follows: Favorable (unfavorable) variances: Oil and Gas Activities:U.S.
    
    $
    (51
    )China
    
    
    32GTL
    
    
    (127
    )EOR
    
    
    (315
    )Corporate
    
    
    (789
    )$
    (1,250
    )
  
    General, Administrative and Business Development 2005 vs. 2004 General, administrative and business development expenses increased $1.3 million for the first
quarter of 2005 compared to the same period in 2004. Corporate general and administrative expenses
increased $0.8 million due mainly to professional fees incurred during the first quarter of 2005 to
comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002. Business development
expenses increased $0.4 million for the first quarter of 2005 due mainly to increased activities in
Egypt, Iraq and other Northern Africa and Middle East countries. Depletion and Depreciation  
    Depletion and Depreciation 2005 vs. 2004 Depletion and depreciation increased $0.8 million for the first quarter of 2005 when compared to
the same period in 2004, which was primarily due to an increase in production rates resulting in a
$0.5 million increase in depletion. Additionally, depletion rates increased $1.55 per Boe to $14.54
per Boe in the first quarter of 2005 compared to $12.99 per Boe in 2004. The China depletion rate for the first quarter of 2005 was $14.30 per Boe, a 25% increase from the
same period in 2004, due mainly to a downward revision of our share of proved reserves at Dagang as
a result of continued increases in oil prices. During periods of increasing oil prices our share of
proved oil reserves decreases, as fewer barrels of oil are required to recover our costs under our
production-sharing contract. 19




---



##### 



Capital Investments The following provides an analysis of our capital investment activities for the first quarter of
2005 when compared to the same period for 2004: Three-Month Periods EndedMarch 31,(Increase)2005
    
    
    2004
    
    
    DecreaseOil and Gas Activities:U.S.
    
    $
    799
    
    
    $
    3,118
    
    
    $
    2,319China
    
    
    9,806
    
    
    
    6,875
    
    
    
    (2,931
    )GTL
    
    
    215
    
    
    
    67
    
    
    
    (148
    )EOR
    
    
    1,714
    
    
    
    363
    
    
    
    (1,351
    )$
    12,534
    
    
    $
    10,423
    
    
    $
    (2,111
    )
 Oil and Gas Activities  U.S. Capital investment in the U.S. is down $2.3 million for the first quarter 2005 when compared to the
same period in 2004, due mainly to $1.5 million and $0.8 million decreases in our development
activities in the Knights Landing and Citrus fields, respectively. In February 2004, we farmed into the Knights Landing gas field, which is a 13,000-acre block
located in the Sutter and Yolo counties, in northern California. Subsequent to the construction of
gas gathering, surface treatment facilities and meters to connect 4 commercial wells to an existing
pipeline system in the first quarter of 2004 we drilled 9 wells during the second and third
quarters of 2004. Three of these new wells were successful and by April 2005 had been tied into the
existing pipeline system and were on production. Due to weather and scheduling delays we do not
expect to start our 3-D seismic acquisition program at Knights Landing until the fourth quarter of
2005. Drilling activities in Knights Landing will recommence after interpretation of the 3-D
seismic. We completed the drilling of Citrus # 1 in the first quarter of 2004 and we continue to assess
drilling an additional horizontal leg in this well later this year to fully evaluate the potential
of the Upper Antelope zone in this section of our Citrus acreage. During the first quarter of 2005, we discovered natural gas at the Peach prospect in the North
Antelope Hills area in Kern County, California. The prospect is 50 miles west of Bakersfield, in a
major hydrocarbon-producing region along the west side of the San Joaquin Basin. We farmed out part
of our 1,800-acre Peach prospect in November 2004 for 100% of the drilling costs of the first Peach
well to earn a 50% interest in the prospect. We will retain a 50% interest in this well after
payout and will retain a 50% working interest in the prospect. We expect to drill an appraisal well
to the discovery during the second quarter of 2005. Production of the discovery well and connection
to a gas sales pipeline is pending the results of the appraisal well. Oil and Gas Activities  China Capital investment in China for the first quarter of 2005 was $9.8 million, a $2.9 million or 43%
increase compared to the same period in 2004 primarily due to increased drilling activities at
Dagang. Expenditures at Dagang increased $2.4 million to $6.8 million during the first quarter of 2005. By
the end of the quarter, we completed 3 wells, drilled and completed 1 well, drilled 4 wells that
are awaiting completion, re-completed 1existing well and converted 1 well to an injector. By the
end of the first quarter of 2005, 3 wells were in the process of drilling. The wells drilled in the
first quarter 2005 were all located in the northern 2 blocks of the Dagang field. Post completion
results from the wells in this area have been less than expected, with initial unstimulated
production of approximately 75 Bopd per well. We are currently analyzing core samples to develop a
stimulation program for the wells in the northern blocks. We expect to initiate this program in the
second quarter of 2005. If this initial stimulation program is successful, we anticipate
stimulating additional wells in these northern blocks to increase production. 20




---



##### 



Our capital investment for our Zitong block was $3.0 million during the first quarter of 2005, an
increase of $0.5 million from the same period in 2004. We spent $1.9 million during the first
quarter of 2005 for the completion of the remaining 160 miles of our 700-mile seismic acquisition
program, which we commenced in 2004. Additionally, we incurred $1.1 million during the first
quarter of 2005 to acquire right-of-ways, build a road and well location and purchase all tubular
equipment required to drill our first well in the Zitong block, Dingyuan 1, which commenced
drilling April 1, 2005. The well is expected to take 60 days to drill to a target depth of 8,700
feet. A second exploratory well in the Zitong block is planned for later in 2005. Enhanced Oil Recovery and Heavy-To-Light Oil Activities We incurred $1.4 million more in capital investment activities on EOR and HTL projects for the
first quarter of 2005 compared to the same period in 2004. In Iraq, we incurred $0.4 million to further our study of the Qaiyarah heavy oil field. The fields
reservoirs contain a large proven accumulation of 17.1o API heavy oil at a depth of
about 1,000 feet. The studies include the potential response of the Qaiyarah heavy oil field to the
latest in EOR techniques, along with the potential value that could be added using the
RTPTM Technology to produce higher quality, more valuable crude oil. Additionally, we
incurred $0.2 million on costs to bid on a fourth engineering, design and procurement contract for
a gas field in Iraq. We incurred $0.3 million to further our study of the heavy crudes from the large Castilla and
Chichimene oil fields in Colombia. This included 10 runs of heavy oil samples from these two fields
at Ensyns RTPTM pilot plant in Ottawa, Canada. In March 2005, the performance testing of the RTP CDF was completed successfully and the results
of the test were verified by independent consulting firms Muse, Stancil & Co. and Purvin & Gertz, &
Co. The RTP CDF demonstrated an overall processing capacity of approximately 1,000 barrels-per-day
of raw, heavy oil and a hot section capacity of 300 barrels-per-day. This successful test of the
RTP CDF and verification of the liquid product quality, volume yield and by-product energy by Muse
Stancil & Co. facilitated the completion of the Merger between Ivanhoe and Ensyn (IE HTL) in
April 2005. We incurred $0.5 million during the first quarter of 2005 for a preliminary design
package being prepared by Colt Engineering Corporation for a 10,000 to 15,000 barrels-per-day of
raw, heavy oil (5,000 barrels per day hot-section) commercial RTP plant. The design work for this
commercial RTP plant is expected to be completed in the third quarter of 2005. We intend to apply the leading-edge RTPTM Technology to upgrade heavy oil in plants
located in the field to produce lighter, more valuable crude oil at lower costs and in smaller size
plants than required by conventional technologies. The upgraded heavy oil, similar to less viscous
conventional light crude oil, brings a higher price and can be easily transported. In addition to a
dramatic improvement in oil quality, an RTPTM plant can yield large amounts of surplus
energy for producing steam and electricity used in heavy-oil production. The thermal energy from
the process provides heavy-oil producers with an alternative to high-priced natural gas that now is
widely used to generate steam. The RTPTM Technology offers an excellent opportunity to
optimize the development of mature heavy oil fields and also enables the development of stranded
heavy oil deposits. Under a preexisting agreement between Ensyn, now IE HTL, and ConocoPhillips Canada Resources Corp.
(ConocoPhillips Canada), certain non-exclusive rights to use the RTP Technology for petroleum
applications in Canada were granted. ConocoPhillips Canada has the right, through August 2010, to
place orders for RTP plants with input capacity of up to 250,000 barrels-per-day. Should
ConocoPhillips Canada install RTP plants, IE HTL is entitled to receive royalties per barrel after
the first 50,000 barrels-per day of feedstock input capacity. Gas-To-Liquids Activities We spent $0.1 million more in capital investment activities on GTL projects for the first quarter
of 2005 compared to the same period in 2004. We are updating the design for a 45,000 and 90,000
barrels-per-day GTL plant for a designated site in Egypt. The objective is to develop full plant
design documentation and associated cost estimates 21




---



##### 



based upon improvements in Syntroleums GTL process and catalysts as well as equipment technology in general. After completing the plant design
and economics update we will present a proposal for a GTL plant to Egypts Ministry of Petroleum.
Additionally, we plan to update our marketing study that will provide GTL product price forecasts
and identify end users for these products from this plant. Liquidity and Capital Resources Sources and Uses of Cash Our net cash and cash equivalents was basically unchanged for the first quarter of 2005 compared to
an increase of $19.2 million for the same period in 2004. Our operating activities provided $0.8
million in cash for the first quarter of 2005 compared to a deficit of $1.0 million for the same
period in 2004 due mainly to a 38% increase in our production volumes and a 26% increase in oil and
gas prices compared to the same period in 2004. The increase in net revenues for the first quarter
of 2005 was partially offset by a $1.2 million increase in general, administrative and business
development expenses. Our capital investing activities, less changes in non-cash working capital
associated with our capital investing activities, decreased $3.9 million for the first quarter of
2005 compared to the same period in 2004. Cash from financing activities decreased $25.0 million
for the first quarter of 2005 compared to the same period in 2004. We raised $6.0 million from debt
facilities in the first quarter of 2005 less $0.4 million for payments on notes. For the same
period in 2004, we raised $20.6 million from two special warrant financings and from the exercise
of stock options and $10.0 million for an advance payment related to the farm-out of a 40% working
interest in the Dagang field. Three Months Ended March 31,2005
    
    
    2004Cash flow (deficit) from operating activities
    
    $
    776
    
    
    $
    (1,046
    )Investing ActivitiesCapital investments, after changes in non-cash working capital
    
    
    (5,651
    )
    
    
    (9,825
    )Equity investment and other related costs
    
    
    (730
    )
    
    
    (500
    )(6,381
    )
    
    
    (10,325
    )Financing ActivitiesPrivate placements, net of share issue costs
    
    
    
    
    
    
    20,428Proceeds from exercise of options
    
    
    35
    
    
    
    139Net debt financing
    
    
    5,583
    
    
    
    10,0005,618
    
    
    
    30,567Net Sources of Cash
    
    $
    13
    
    
    $
    19,196
 Outlook for 2005 Our capital investments for the first quarter of 2005 were $12.5 million and are expected to be
$54.2 million for all of 2005. This compares to a capital investment budget of $18.2 million for
the first quarter of 2005 and $79.0 million for all of 2005. The reduction in capital investments
of $5.7 million for the first quarter of 2005 compared to our budget was primarily due to a
slippage to 2006 in additional drilling at our Knights Landing and Citrus properties until after
the planned acquisition and interpretation of our 3-D seismic data in the fourth quarter of 2005 at
Knights Landing and the evaluation of the potential of the Upper Antelope zone with the drilling of
an additional horizontal leg in Citrus #1. Additionally, drilling of our first well in the Zitong
block was delayed into the second quarter of 2005 but we anticipate our 2005 capital investment program in the Zitong block to remain
unchanged from our original budget. The $24.8 million reduction in our capital investment program
for all of 2005 is primarily due to a reduction in our Dagang drilling schedule for the remainder
of 2005 pending evaluation of the stimulation program for the wells drilled in the northern blocks
of the Dagang field. Our 2005 capital investment budget is also expected to be reduced due to the
slippage to 2006 of our drilling programs at our Knights Landing and Citrus fields as previously
mentioned. 22




---



##### 



Our capital investment budget for the remainder of 2005 is $41.7 million. We plan to seek financing
on an as needed basis, from equity markets, project lenders, joint ventures or other potential
financing sources to pursue our 2005 capital investment program, acquisitions of proven and
probable reserves and to deploy our HTL and GTL technologies. In addition, we, together with our
40% partner in the Dagang project, are in active discussions with European and Chinese lending
banks to provide funding for the development of the Dagang field. In October 2003, we filed a base shelf prospectus with Canadian securities regulatory authorities
and a shelf registration statement with the U.S. Securities and Exchange Commission to qualify for
potential future sale in Canada and the U.S. up to $100 million of various types of securities,
including common shares, preferred shares, warrants and debt securities. These shelf filings, which
expire in November 2005 but which may be renewed, are expected to give us greater flexibility to
fund our expansion and capital programs and will allow us to take advantage of a broader range of
financing opportunities on a timelier basis. A combination of such equity financing, as well as
convertible loan, debt and mezzanine financing and joint venture partner participation, will be
required to complete our future capital programs. We cannot assure you that we will be successful
in raising the additional funds necessary or securing joint venture partners to complete our
capital programs. If we are unsuccessful, we will have to prioritize our capital programs, which
may result in delaying and potentially losing some valuable business opportunities. Contractual Obligations The table below summarizes the contractual obligations that are reflected in our Unaudited
Condensed Consolidated Balance Sheet as at March 31, 2005 and/or disclosed in the accompanying
Notes: Payments Due by Year(stated in thousands of U.S. dollars)Total
    
    
    2005
    
    
    2006
    
    
    2007
    
    
    2008
    
    
    After 2008Purchase Agreement:
    
    $
    150
    
    
    $
    50
    
    
    $
    100
    
    
    $
    
    
    
    $
    
    
    
    $
    Consolidated Balance Sheets:Note payable  current portion (Note 7)
    
    
    1,667
    
    
    
    1,250
    
    
    
    417
    
    
    
    
    
    
    

    
    
    
    
    Long term debt (Note 7)
    
    
    2,222
    
    
    
    
    
    
    
    1,250
    
    
    
    972
    
    
    
    
    
    
    
    Convertible loan (Note 8)
    
    
    6,000
    
    
    
    6,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Other Commitments:
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Interest payable
    
    
    497
    
    
    
    381
    
    
    
    99
    
    
    
    17
    
    
    
    
    
    
    
    Lease commitments
    
    
    2,036
    
    
    
    471
    
    
    
    551
    
    
    
    344
    
    
    
    287
    
    
    
    383Zitong exploration commitment (Note 10)
    
    
    9,400
    
    
    
    9,400
    
    
    
    

    
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    21,972
    
    
    $
    17,552
    
    
    $
    2,417
    
    
    $
    1,333
    
    
    $
    287
    
    
    $
    383
 Off Balance Sheet Arrangements At March 31, 2005 and December 31, 2004, we did not have any relationships with unconsolidated
entities or financial partnerships, such as structured finance or special purpose entities, which
would have been established for the purpose of facilitating off-balance sheet arrangements or other
contractually narrow or limited purposes. In addition, we do not engage in trading activities
involving non-exchange traded contracts. As such, we are not materially exposed to any financing,
liquidity, market or credit risk that could arise if we had engaged in such relationships. We do
not have relationships and transactions with persons or entities that derive benefits from their
non-independent relationship with us, or our related parties, except as disclosed herein. Outstanding Share Data As at April 29, 2005, there were 199,902,299 common shares of the Company issued and outstanding
which included 29,999,886 common shares issued by the Company on April 15, 2005 in connection with
its merger with Ensyn. Additionally, the Company had 21,551,826 share purchase warrants outstanding
and exercisable to purchase 11,400,913 common shares which included 4,100,000 special purchase
warrants issued by way of a private placement on April 15, 2005 for the purchase of 2,050,000
common shares at a price of Cdn.$3.50 exercisable until the first anniversary date of the closing.
As at April 29, 2005, there were 8,504,257 incentive stock options outstanding to purchase the
Companys common shares. 23




---



##### 



Quarterly Financial Data In Accordance With Canadian and U.S. GAAP (Unaudited) QUARTER ENDED2005
    
    
    2004
    
    
    20031st Qtr
    
    
    4th Qtr
    
    
    3rd Qtr
    
    
    2nd Qtr
    
    
    1st Qtr
    
    
    4th Qtr
    
    
    3rd Qtr
    
    
    2nd QtrTotal revenue
    
    $
    5,736
    
    
    $
    6,212
    
    
    $
    4,932
    
    
    $
    3,521
    
    
    $
    3,332
    
    
    $
    2,330
    
    
    $
    2,423
    
    
    $
    2,338Net loss
 Canadian GAAP
    
    $
    1,483
    
    
    $
    17,184
    
    
    $
    951
    
    
    $
    1,298
    
    
    $
    1,292
    
    
    $
    23,154
    
    
    $
    1,330
    
    
    $
    4,587Net loss  U.S. GAAP
    
    $
    3,008
    
    
    $
    15,736
    
    
    $
    980
    
    
    $
    1,510
    
    
    $
    1,470
    
    
    $
    23,270
    
    
    $
    1,306
    
    
    $
    1,325Net loss per share  Canadian
    
    $
    0.01
    
    
    $
    0.09
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.15
    
    
    $
    0.01
    
    
    $
    0.03Net loss per share  U.S. GAAP
    
    $
    0.02
    
    
    $
    0.09
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.15
    
    
    $
    0.01
    
    
    $
    0.01
 The 2003 quarterly earnings for Canadian GAAP have been restated to give effect to the
retroactive application of CICA Section 3870  Stock Based Compensation and Other Stock Based
Payments, which is more fully described in Note 2 under Stock Based Compensation in the
Companys 2004 Annual Report on Form 10-K. The net losses in the fourth quarter of 2004, for
Canadian and U.S. GAAP, were primarily due to impairment provisions of $16.3 million and $15.0
million, respectively, for U.S. oil and gas properties. The net losses in the fourth quarter of
2003, for both Canadian and U.S. GAAP, were primarily due to an impairment provision of $20.0
million for U.S. oil and gas properties. The net loss under Canadian GAAP for the second quarter of
2003 included a $3.3 million write-down of costs associated with the unsuccessful negotiations of a
GTL contract in Qatar. For U.S. GAAP, these costs are expensed as they are incurred. The
differences in the net loss and net loss per share for the first quarter of 2005 was due mainly to
GTL and EOR investments, which are capitalized for Canadian GAAP but expensed as incurred for U.S.
GAAP. Item 3. Quantitative and Qualitative Disclosures About Market Risk No material changes since December 31, 2004. Item 4. Controls and Procedures The Companys management, including our Chief Executive Officer and Chief Financial Officer,
evaluated the effectiveness of the design and operation of the Companys disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 2005. 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 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 Securities Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the SECs rules and forms. Management of the Company is responsible for establishing and maintaining adequate internal control
over financial reporting as such term is defined under Rule 13a-15(f) under the Securities Exchange
Act of 1934. During the fiscal 2004 implementation of Section 404 of the Sarbanes-Oxley Act of
2002, management identified two material weaknesses in the Companys internal control over
financial reporting (this section of Item 4. Controls and Procedures should be read in
conjunction with Item 9A. Controls and Procedures, included in the Companys Annual Report filed
on Form 10-K for the fiscal year ended December 31, 2004 and as amended on Form 10-K/A filed on May
2, 2005). In the first quarter of fiscal 2005, management took several steps to address the
identified weaknesses. Specifically, the Company implemented the following changes in internal control over financial
reporting: Prior to March 31, 2005, we engaged an independent firm to handle all complaints, whether from
employees or third parties with respect to concerns regarding accounting or auditing matters and
any perceived violations of our Code of Business Conduct and Ethics. By means of a secure website
or telephone, all issues raised will be 24




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automatically directed to the Chairman of our Audit Committee who will have primary responsibility for responding to and pursuing all reported matters. As part of our new complaint process, we have formally communicated the roles and responsibilities
related to internal control over financial reporting to all employees. As part of our responsibilities under Section 404 of the Sarbanes-Oxley Act of 2002, there will be
an annual and extensive formal review to monitor and detect control deficiencies related to
internal control over financial reporting. With respect to financial reporting, prior to December 31, 2004 and since that date, we have
formalized our financial reporting processes, instituted changes in the division of financial
reporting responsibilities and are changing our policies and procedures to require written
documentation of our approvals and reviews in those financial reporting processes where
deficiencies have been identified. Part II  Other Information Item 1. Legal Proceedings: None Item 2. Unregistered Sales of Equity Securities and Use of Proceeds: On April 15, 2005, we issued the following securities which were not registered under the
Securities Act of 1933 (the Act):  
    4,100,000 special warrants at a price of Cdn.$3.10 per special warrant to institutional
and individual investors in a transaction exempt from registration under Rule 903 of the
Act. Each special warrant entitles the holder to receive, at no additional cost, one common
share and one common share purchase warrant before or immediately following the filing and
regulatory acceptance of a Canadian prospectus, or four months after the closing date,
which ever occurs first. Two common-share purchase warrants will entitle the holder to
purchase one common share at a price of Cdn.$3.50 exercisable until the first anniversary
date of the closing.
    29,999,886 common shares were issued in exchange for all of the issued and outstanding
Ensyn common shares as part of an Agreement and Plan of Merger dated December 11, 2004 in a
transaction not subject to registration pursuant to an exemption under Section 3(a)(10) of
the Act. Ten million of the common shares issued were deposited in an escrow fund and will
be held to secure certain obligations on the part of the former Ensyn stockholders to
indemnify the Company for damages arising from any breaches of warranties and covenants in
the Merger Agreement and certain liabilities Item 3. Defaults Upon Senior Securities: None Item 4. Submission of Matters To a Vote of Securityholders: None Item 5. Other Information: None Item 6. Exhibits and Reports on Form 8-K  (a)
    Exhibits EXHIBITNUMBER
    
    DESCRIPTION31.1
    
    Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 200231.2
    
    Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002
 25




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EXHIBITNUMBER
    
    DESCRIPTION32.1
    
    Certification by the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 200232.2
    
    Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
  (b)
    Reports on Form 8-K: None 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/ W. Gordon LancasterName: W. Gordon LancasterTitle: Chief Financial Officer
 Dated: May 5, 2005 26




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INDEX TO EXHIBITS ExhibitNumber
    
    Description31.1
    
    Certification by the Chief Executive Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 200231.2
    
    Certification by the Chief Financial Officer Pursuant to Section 302 of the
Sarbanes-Oxley Act of 200232.1
    
    Certification by the Chief Executive Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 200232.2
    
    Certification by the Chief Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
 27