##### 



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 June 30, 2004oro
    
    Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.For the transition period from  toCommission file number 000-30586
 IVANHOE ENERGY INC. (Exact name of registrant as specified in its charter)
 Yukon, Canada(State or other jurisdiction of
incorporation or organization)
    
    98-0372413(I.R.S. Employer
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 June
30, 2004 was 169,419,911 Common Shares, no par value.




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##### 



TABLE OF CONTENTS PagePART I
    
    Financial InformationItem 1.
    
    Financial StatementsUnaudited Consolidated Balance Sheets as at
June 30, 2004 and December 31, 2003 (restated)
    
    
    3Unaudited Consolidated Statements of Loss and Deficit
for the Three-Month and Six-Month Periods Ended June 30, 2004 and 2003 (restated)
    
    
    4Unaudited Consolidated Statements of Cash Flow for the
Three-Month and Six-Month Periods Ended June 30, 2004
and 2003 (restated)
    
    
    5Notes to the Unaudited Consolidated Financial
Statements
    
    
    6Item 2.
    
    Managements Discussion and Analysis of Financial Condition
and Results of Operations
    
    
    13Item 3.
    
    Quantitative and Qualitative Disclosures About Market Risks
    
    
    21Item 4.
    
    Controls and Procedures
    
    
    21PART II
    
    Other InformationItem 1.
    
    Legal Proceedings
    
    
    22Item 2.
    
    Changes in Securities and Use of Proceeds
    
    
    22Item 3.
    
    Defaults Upon Senior Securities
    
    
    22Item 4.
    
    Submission of Matters To a Vote of Securityholders
    
    
    22Item 5.
    
    Other Information
    
    
    22Item 6.
    
    Exhibits and Reports on Form 8-K
    
    
    22
 2




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##### 



Part I  Financial Information Item 1 Financial Statements IVANHOE ENERGY INC. Unaudited Consolidated Balance Sheets
(stated in thousands of U.S. Dollars except share amounts) June 30,
    
    December 31,2004
    
    2003(restatedNotes 2 and 7)AssetsCurrent AssetsCash and cash equivalents
    
    $
    30,361
    
    
    $
    14,491Accounts receivable
    
    
    4,729
    
    
    
    2,720Other
    
    
    378
    
    
    
    40935,468
    
    
    
    17,620Long term assets
    
    
    3,677
    
    
    
    998Oil and gas properties, equipment and investments, net
    
    
    96,577
    
    
    
    87,956$
    135,722
    
    
    $
    106,574Liabilities and Shareholders EquityCurrent LiabilitiesAccounts payable and accrued liabilities
    
    $
    11,522
    
    
    $
    4,516Note payable  current portion
    
    
    917
    
    
    
    16712,439
    
    
    
    4,683Note payable
    
    
    2,083
    
    
    
    833Asset retirement obligations
    
    
    623
    
    
    
    521Commitments and contingenciesShareholders EquityShare capital, issued 169,419,911 common shares;
December 31, 2003 161,359,339 common shares
    
    
    183,225
    
    
    
    161,075Contributed surplus
    
    
    996
    
    
    
    516Deficit
    
    
    (63,644
    )
    
    
    (61,054
    )120,577
    
    
    
    100,537$
    135,722
    
    
    $
    106,574
 (See accompanying notes) 3




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##### 



IVANHOE ENERGY INC.
Unaudited Consolidated Statements of Loss and Deficit
(stated in thousands of U.S. Dollars except per share amounts) Three Months
    
    Six MonthsEnded June 30,
    
    Ended June 30,2004
    
    2003
    
    2004
    
    2003(restated
    
    
    
    
    
    (restatedNotes 2 and 7)
    
    
    
    
    
    Notes 2 and 7)RevenueOil and gas revenue
    
    $
    3,472
    
    
    $
    2,332
    
    
    $
    6,764
    
    
    $
    4,864Interest income
    
    
    49
    
    
    
    6
    
    
    
    89
    
    
    
    423,521
    
    
    
    2,338
    
    
    
    6,853
    
    
    
    4,906ExpensesOperating costs
    
    
    1,157
    
    
    
    948
    
    
    
    2,431
    
    
    
    1,845General and administrative
    
    
    1,909
    
    
    
    1,905
    
    
    
    3,813
    
    
    
    3,764Depletion and depreciation
    
    
    1,503
    
    
    
    751
    
    
    
    2,949
    
    
    
    1,671Write down of GTL investments
    
    
    250
    
    
    
    3,321
    
    
    
    250
    
    
    
    3,3214,819
    
    
    
    6,925
    
    
    
    9,443
    
    
    
    10,601Net Loss
    
    
    1,298
    
    
    
    4,587
    
    
    
    2,590
    
    
    
    5,695Deficit, beginning of period, as previously reported
    
    
    62,346
    
    
    
    31,562
    
    
    
    60,267
    
    
    
    30,564Retroactive application of change in accounting policy for
stock based compensation
    
    
    
    
    
    
    421
    
    
    
    787
    
    
    
    311Deficit, beginning of the period, as restated
    
    
    62,346
    
    
    
    31,983
    
    
    
    61,054
    
    
    
    30,875Deficit, end of period
    
    $
    63,644
    
    
    $
    36,570
    
    
    $
    63,644
    
    
    $
    36,570Net Loss per share  Basic and Diluted
    
    $
    0.01
    
    
    $
    0.03
    
    
    $
    0.02
    
    
    $
    0.04Weighted Average Number of Shares (in thousands)
    
    
    169,116
    
    
    
    145,055
    
    
    
    165,622
    
    
    
    144,832
 (See accompanying notes) 4




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##### 



IVANHOE ENERGY INC.
Unaudited Consolidated Statements of Cash Flow
(stated in thousands of U.S. Dollars) Three Months
    
    Six MonthsEnded June 30,
    
    Ended June 30,2004
    
    2003
    
    2004
    
    2003(restated
    
    
    
    
    
    (restatedNotes 2 and 7)
    
    
    
    
    
    Notes 2 and 7)Operating ActivitiesNet loss
    
    $
    (1,298
    )
    
    $
    (4,587
    )
    
    $
    (2,590
    )
    
    $
    (5,695
    )Items not requiring use of cashDepletion and depreciation
    
    
    1,503
    
    
    
    751
    
    
    
    2,949
    
    
    
    1,671Write down of GTL investments
    
    
    250
    
    
    
    3,321
    
    
    
    250
    
    
    
    3,321Stock based compensation
    
    
    242
    
    
    
    122
    
    
    
    481
    
    
    
    232Changes in non-cash working capital items
    
    
    602
    
    
    
    1,300
    
    
    
    244
    
    
    
    1,6501,299
    
    
    
    907
    
    
    
    1,334
    
    
    
    1,179Investing ActivitiesCapital spending
    
    
    (14,933
    )
    
    
    (2,856
    )
    
    
    (25,356
    )
    
    
    (4,774
    )Deposit on investment
    
    
    (2,000
    )
    
    
    
    
    
    
    (2,500
    )
    
    
    Proceeds from sale of assets
    
    
    13,458
    
    
    
    
    
    
    
    13,458
    
    
    
    Changes in non-cash working capital items
    
    
    5,614
    
    
    
    511
    
    
    
    5,131
    
    
    
    7102,139
    
    
    
    (2,345
    )
    
    
    (9,267
    )
    
    
    (4,064
    )Financing ActivitiesShares issued on private placements, net of
share issue costs
    
    
    
    
    
    
    
    
    
    
    20,428
    
    
    
    Shares issued on exercise of options
    
    
    1,236
    
    
    
    
    
    
    
    1,375
    
    
    
    Proceeds from notes and advances
    
    
    2,000
    
    
    
    1,500
    
    
    
    12,000
    
    
    
    1,750Redemption of advance payable
    
    
    (10,000
    )
    
    
    
    
    
    
    (10,000
    )
    
    
    (6,764
    )
    
    
    1,500
    
    
    
    23,803
    
    
    
    1,750Increase (decrease) in cash and cash
equivalents, for the period
    
    
    (3,326
    )
    
    
    62
    
    
    
    15,870
    
    
    
    (1,135
    )Cash and cash equivalents, beginning of period
    
    
    33,687
    
    
    
    2,783
    
    
    
    14,491
    
    
    
    3,980Cash and cash equivalents, end of period
    
    $
    30,361
    
    
    $
    2,845
    
    
    $
    30,361
    
    
    $
    2,845Financing activities, non-cashShares issued on conversion of debenture
    
    $
    
    
    
    $
    1,000
    
    
    $
    
    
    
    $
    1,000Included in the above are the following:Taxes paid
    
    $
    
    
    
    $
    
    
    
    $
    3
    
    
    $
    6Interest paid
    
    $
    14
    
    
    $
    23
    
    
    $
    28
    
    
    $
    42Changes in non-cash working capital itemsOperating Activities:Accounts receivable
    
    $
    (266
    )
    
    $
    495
    
    
    $
    (856
    )
    
    $
    380Other current assets
    
    
    3
    
    
    
    575
    
    
    
    31
    
    
    
    512Accounts payable and accrued liabilities
    
    
    865
    
    
    
    230
    
    
    
    1,069
    
    
    
    758602
    
    
    
    1,300
    
    
    
    244
    
    
    
    1,650Investing ActivitiesAccounts receivable
    
    
    (831
    )
    
    
    
    
    
    
    (1,153
    )
    
    
    Accounts payable and accrued liabilities
    
    
    6,445
    
    
    
    511
    
    
    
    6,284
    
    
    
    7105,614
    
    
    
    511
    
    
    
    5,131
    
    
    
    710$
    6,216
    
    
    $
    1,811
    
    
    $
    5,375
    
    
    $
    2,360
 (See accompanying notes) 5




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Notes to the Consolidated Financial Statements
June 30, 2004
(all tabular amounts are expressed in thousands of U.S. dollars except per share data)
(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 consolidated financial statements have been prepared on a basis
consistent with the accounting principles and policies reflected in the
December 31, 2003 consolidated financial statements, except for a change in the
policy of accounting for stock based compensation which has been implemented
retroactively with a restatement of prior period financial statements, and
should be read in conjunction therewith. These interim 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, 2003
consolidated balance sheet, as restated, 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.  2.
    
    CHANGE IN ACCOUNTING POLICY Prior to January 1, 2004, the Company accounted for options granted to
employees and directors using the intrinsic-value of the options. Under this
method, compensation costs were not recognized in the financial statements for
share options granted at market value but rather disclosure was required, on a
pro forma basis, of the impact on net income of using the fair value at the
option grant date. The Company does, however, recognize compensation costs in
its financial statements for options granted to non-employees after January 1,
2002 based on the fair value of the options at the date granted. The Company
uses the Black-Scholes option pricing model for determining the fair value of
options issued at grant date. For fiscal years beginning on or after January 1, 2004, Canadian GAAP requires
compensation costs to be recognized in the financial statements using the fair
value based method of accounting for all stock options granted after January 1,
2002. Implementation of this change in accounting policy requires retroactive
application with the option of restating financial statements of prior periods. Accordingly, effective January 1, 2004, the Company changed its accounting
policy, for Canadian GAAP purposes, to recognize compensation costs using the
fair value based method of accounting for stock options granted to employees
and directors after January 1, 2002. This change has been adopted retroactively
and the Company has elected to restate the financial statements of prior
periods (See Note 7). 6




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##### 



3.
    
    OIL AND GAS PROPERTIES, EQUIPMENT AND INVESTMENTS Oil and gas properties, equipment and investments are net of accumulated
depletion and depreciation of $13.4 million and $10.5 million as well as a
provision for impairment of oil and gas properties of $34.0 million as at June
30, 2004 and December 31, 2003, respectively. In January 2004, the Company signed farm-out and joint operating agreements
with Richfirst Holdings Limited (Richfirst), a wholly owned subsidiary of
China International Trust & Investment Company to jointly develop the Dagang
oil project. Richfirst acquired a 40% working interest in the project for $20.0
million following Chinese regulatory approvals, which were finalized in June
2004 (see Note 9). The carrying value of the Companys oil and gas assets was
reduced by $13.5 million for the amount of the proceeds associated with the
sale of the working interest. The reduction in the carrying value does not
significantly alter the depletion rate of the China oil and gas assets. The
balance of the $20.0 million proceeds will be used to fund a portion of
Richfirsts share of future Dagang oil project costs. In February 2004, the Company farmed into the Knights Landing project in
northern California. Under this exploration and development farm-in agreement,
the Company purchased, for $1.0 million, a 50% non-operated interest in four
recent discoveries in the contract area and agreed to fund, for $0.6 million,
gas gathering, surface treatment facilities and meters to connect the four
wells to an existing pipeline system. Additionally, the Company agreed to fund
100% of the drilling costs for 10 exploratory gas wells at an estimated cost of
$2.3 million to earn a 40% working interest in this prospect. As a result of the Companys on-going evaluation of its GTL investments, $0.3
million of its investments were written down for the three-month period ended
June 30, 2004 as the opportunity to build a 45,000 bpd GTL fuels plant in Oman
failed to materialize due to a lack of sufficient uncommitted gas volumes to
support a plant of that size.  4.
    
    LONG TERM ASSETS In January 2004, the Company signed a Stock Purchase and Shareholders
Agreement with Ensyn Group Inc. (Ensyn Group) and its subsidiary, Ensyn
Petroleum International Ltd. (Ensyn), pursuant to which the Company acquired
a 10% equity interest in Ensyn and exclusive rights to use the proprietary
Ensyn RTPTM Process in several key international markets. The Company paid $2.0
million and will grant Ensyn rights to acquire equity interests in the
Companys international oil development projects that use the
Ensyn RTPTM
Process. In April 2004, the Company signed an agreement with Ensyn Group and Ensyn
pursuant to which the Company advanced to Ensyn an additional $1.0 million in
consideration for the right to elect to either take an additional 5% equity
interest in Ensyn or consider the advance as a loan to be repaid with interest
over a period of 90 days commencing on July 31, 2005. As at June 30, 2004, all amounts paid to Ensyn under the above agreements are
included in long-term assets.  5.
    
    SEGMENT INFORMATION The following tables present the Companys interim segment information for the
three-month and six-month periods ended June 30, 2004 and 2003 and identifiable
assets as at June 30, 2004 and December 31, 2003: 7




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##### 



Three Month Periods Ended June 30,2004
    
    2003(restated Notes 2 and 7)U.S.
    
    China
    
    Total
    
    U.S.
    
    China
    
    TotalOil and gas revenue
    
    $
    2,006
    
    
    $
    1,466
    
    
    $
    3,472
    
    
    $
    1,247
    
    
    $
    1,085
    
    
    $
    2,332Interest income
    
    
    49
    
    
    
    
    
    
    
    49
    
    
    
    6
    
    
    
    
    
    
    
    62,055
    
    
    
    1,466
    
    
    
    3,521
    
    
    
    1,253
    
    
    
    1,085
    
    
    
    2,338Operating costs
    
    
    677
    
    
    
    480
    
    
    
    1,157
    
    
    
    511
    
    
    
    437
    
    
    
    948Depletion and depreciation
    
    
    1,002
    
    
    
    501
    
    
    
    1,503
    
    
    
    423
    
    
    
    328
    
    
    
    7511,679
    
    
    
    981
    
    
    
    2,660
    
    
    
    934
    
    
    
    765
    
    
    
    1,699Segment income before the following
    
    $
    376
    
    
    $
    485
    
    
    
    861
    
    
    $
    319
    
    
    $
    320
    
    
    
    639Write down of GTL investments
    
    
    
    
    
    
    
    
    
    
    250
    
    
    
    
    
    
    
    
    
    
    
    3,321General and administrative
    
    
    
    
    
    
    
    
    
    
    1,909
    
    
    
    
    
    
    
    
    
    
    
    1,905Net loss
    
    
    
    
    
    
    
    
    
    $
    1,299
    
    
    
    
    
    
    
    
    
    
    $
    4,587Capital Expenditures:Oil and gas
    
    $
    6,905
    
    
    $
    7,277
    
    
    $
    14,182
    
    
    $
    1,556
    
    
    $
    1,097
    
    
    $
    2,653Gas-to-liquids and EOR
Investments
    
    
    
    
    
    
    
    
    
    
    751
    
    
    
    
    
    
    
    
    
    
    
    203$
    14,933
    
    
    
    
    
    
    
    
    
    
    $
    2,856
 Six Month Periods Ended June 30,2004
    
    2003(restated Notes 2 and 7)U.S.
    
    China
    
    Total
    
    U.S.
    
    China
    
    TotalOil and gas revenue
    
    $
    3,800
    
    
    $
    2,964
    
    
    $
    6,764
    
    
    $
    2,689
    
    
    $
    2,175
    
    
    $
    4,864Interest income
    
    
    89
    
    
    
    
    
    
    
    89
    
    
    
    42
    
    
    
    
    
    
    
    423,889
    
    
    
    2,964
    
    
    
    6,853
    
    
    
    2,731
    
    
    
    2,175
    
    
    
    4,906Operating costs
    
    
    1,431
    
    
    
    1,000
    
    
    
    2,431
    
    
    
    1,013
    
    
    
    832
    
    
    
    1,845Depletion and depreciation
    
    
    1,873
    
    
    
    1,076
    
    
    
    2,949
    
    
    
    988
    
    
    
    683
    
    
    
    1,6713,304
    
    
    
    2,076
    
    
    
    5,380
    
    
    
    2,001
    
    
    
    1,515
    
    
    
    3,516Segment income before the following
    
    $
    585
    
    
    $
    888
    
    
    
    1,473
    
    
    $
    730
    
    
    $
    660
    
    
    
    1,390Write down of GTL investments
    
    
    
    
    
    
    
    
    
    
    250
    
    
    
    
    
    
    
    
    
    
    
    3,321General and administrative
    
    
    
    
    
    
    
    
    
    
    3,813
    
    
    
    
    
    
    
    
    
    
    
    3,764Net loss
    
    
    
    
    
    
    
    
    
    $
    2,590
    
    
    
    
    
    
    
    
    
    
    $
    5,695Capital expenditures:Oil and gas
    
    $
    10,023
    
    
    $
    14,152
    
    
    $
    24,175
    
    
    $
    2,670
    
    
    $
    1,691
    
    
    $
    4,361Gas-to-liquids and EOR Investments
    
    
    
    
    
    
    
    
    
    
    1,181
    
    
    
    
    
    
    
    
    
    
    
    413$
    25,356
    
    
    
    
    
    
    
    
    
    
    $
    4,774
 As at June 30, 2004
    
    As at December 31, 2003U.S.
    
    China
    
    Total
    
    U.S.
    
    China
    
    TotalIdentifiable Assets:Oil & gas
    
    $
    89,054
    
    
    $
    30,934
    
    
    $
    119,988
    
    
    $
    61,379
    
    
    $
    30,766
    
    
    $
    92,145Gas-to-liquids and EOR Investments
    
    
    
    
    
    
    
    
    
    
    15,734
    
    
    
    
    
    
    
    
    
    
    
    14,429$
    135,722
    
    
    
    
    
    
    
    
    
    
    $
    106,574
  6.
    
    SHARE CAPITAL Following is a summary of the changes in share capital and stock options
outstanding for the six-month period ended June 30, 2004: 8




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##### 



Common Shares
    
    Stock OptionsWeightedAverageExerciseNumber
    
    
    
    
    
    Number
    
    Price(thousands)
    
    Amount
    
    (thousands)
    
    Cdn.$(restatedNotes 2 and 7)Balance December 31, 2003, as previously reported
    
    
    161,359
    
    
    $
    160,804
    
    
    
    8,949
    
    
    $
    2.64Retroactive application of change in accounting
policy for stock based compensation
    
    
    
    
    
    
    271
    
    
    
    
    
    
    
    Balance December 31, 2003, as restated
    
    
    161,359
    
    
    
    161,075
    
    
    
    8,949
    
    
    $
    2.64Shares issued on private placements, net of
share issue costs
    
    
    7,173
    
    
    
    20,428
    
    
    
    
    
    
    
    Shares issued on exercise of options
    
    
    730
    
    
    
    1,375
    
    
    
    (730
    )
    
    $
    2.58Shares issued for services
    
    
    158
    
    
    
    347
    
    
    
    
    
    
    
    Options granted
    
    
    
    
    
    
    
    
    
    
    30
    
    
    $
    3.06Balance June 30, 2004
    
    
    169,420
    
    
    $
    183,225
    
    
    
    8,249
    
    
    $
    2.65
 In the first quarter of 2004, the Company closed two special warrant financings
to advance its international and North American oil and gas operations and for
general corporate purposes. The financings consist of 7,172,414 special
warrants at $2.90 per special warrant. Each special warrant entitles the holder
to acquire one common share and one common-share purchase warrant at no
additional cost. Two common-share purchase warrants are exercisable to purchase
an additional common share at $3.00 at any time on or prior to the first
anniversary date following the special warrant date of issue and at $3.20
thereafter until the second anniversary date of the special warrant date of
issue. The net proceeds from the special warrant financings have been
apportioned to the common shares. No amounts have been apportioned to the
purchase warrants. The following common-share purchase warrants are outstanding and exercisable as
at June 30, 2004: First Anniversary
    
    Second AnniversaryRemainingNumber of
    
    Number of
    
    
    
    Price per
    
    
    
    Price perPurchase
    
    Common
    
    
    
    Share
    
    
    
    ShareWarrants
    
    Shares
    
    Date
    
    (US$)
    
    Date
    
    (US$)(thousands)3,000
    
    
    
    1,500
    
    
    July 3, 2004
    
    $
    1.00
    
    
    July
3, 2005
    
    $
    1.103,000
    
    
    
    1,500
    
    
    August 18, 2004
    
    $
    1.00
    
    
    August
18, 2005
    
    $
    1.103,029
    
    
    
    1,515
    
    
    August 21, 2004
    
    $
    1.70
    
    
    August
21, 2005
    
    $
    1.871,250
    
    
    
    1,250
    
    
    October 31, 2004
    
    $
    4.00
    
    
    October
31, 2005
    
    $
    4.305,448
    
    
    
    2,724
    
    
    February 18, 2005
    
    $
    3.00
    
    
    February
18, 2006
    
    $
    3.201,724
    
    
    
    862
    
    
    March 5, 2005
    
    $
    3.00
    
    
    March
5, 2006
    
    $
    3.2017,451
    
    
    
    9,351
  7.
    
    STOCK BASED COMPENSATION The Company accounts for all stock options granted using the fair value based
method of accounting. This method was adopted retroactively 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 options vesting period using an option- pricing model for
determining the fair value of the options at the grant date. The effect of the accounting change on the net loss for the three-month and
six-month periods ended June 30, 2004 was an increase of $0.2 million and $0.5
million, respectively, and on the net loss for the three-month and six-month
periods ended June 30, 2003, as previously 9




---



##### 



reported, was an increase of $0.2
million and $0.1 million, respectively. There is negligible effect on the net
loss per share for the periods presented. The deficit as at the beginning of
the six-month periods ended June 30, 2004 and 2003 has increased $0.8 million
and $0.3 million, respectively, to reflect the retroactive adoption of the fair value
based method of accounting for stock options granted to employees and directors
after January 1, 2002. Additionally, 0.3 million options granted to employees
and directors after January 1, 2002 were exercised during the third and fourth
quarters of 2003 resulting in a $0.3 million increase in share capital as at
December 31, 2003 with a corresponding reduction in contributed surplus. The fair values were calculated in accordance with the Black-Scholes option
pricing model, using the following data and assumptions: 72% to 109% price
volatility, using the prior two years weekly average prices of the Companys
common shares; expected dividend yield of 0%; option terms to expiry of 5
years, as defined by the option agreements; risk-free rate of return as of the
date of the grant of 3.5% to 5.6%, based on five year Canada Bond yields.  8.
    
    NOTE PAYABLE In February 2003, the Company obtained a bank facility for up to $5.0 million
to drill 30 new oil wells and upgrade surface transmission and steam injection
facilities in the southern expansion of South Midway. Interest only is payable
until July 15, 2004 at 0.25% above the banks prime rate or 2.75% over the
London Inter-Bank Offered Rate (LIBOR), at the option of the Company. After
July 15, 2004, the loan is repayable over three years plus interest at 0.50%
above the banks prime rate or 3.0% over LIBOR, at the option of the Company.
The loan is secured by all the Companys rights and interests in the South
Midway properties. The loan balance as at June 30, 2004 is $3.0 million with a
blended interest rate of 4.375%. The Company borrowed the final $2.0 million in
July 2004.  9.
    
    ADVANCE PAYABLE In March 2004, the Company received a $10.0 million advance as part of the
$20.0 million up-front payment due from Richfirst for their farm-in to the
Dagang oil project (See Note 3). Upon finalization of the farm-in agreement in
June 2004, Richfirst elected to apply $10.0 million of the up-front payment due
to the Company against the advance.  10.
    
    ASSET RETIREMENT OBLIGATION The undiscounted amount of expected cash flows required to settle the Companys
asset retirement obligations is estimated at $1.1 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%.  11.
    
    COMMITMENTS AND CONTINGENCIES 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 at least
$10.9 million as at June 30, 2004. 10




---



##### 



The Company has temporarily abandoned Northwest Lost Hills #1-22 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 contingent
obligation.  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 below: Consolidated Balance Sheets As discussed under Stock Based Compensation in Note 7, the Company changed
its accounting policy, for Canadian GAAP, to recognize compensation costs using
the fair value based method of accounting for stock options granted to
employees and directors after January 1, 2002. 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. Accordingly, for U.S. GAAP purposes, share capital
would be reduced by $0.3 million as at June 30, 2004 and December 31, 2003
related to the employees and directors exercise of options in the third and
fourth quarters of 2003; contributed surplus would be reduced by $1.0 million
and $0.5 million as at June 30, 2004 and December 31, 2003, respectively, for
stock options issued to employees and directors, but not yet exercised; and the
deficits as at June 30, 2004 and December 31, 2003 would be reduced by $1.2
million and $0.8 million, respectively, for the amount of stock based
compensation expense recognized for Canadian GAAP. The application of U.S. GAAP has the following effect on oil and gas properties
and shareholders equity: As at June 30, 2004
    
    As at December 31, 2003Oil and Gas
    
    Shareholders'
    
    Oil and Gas
    
    Shareholders'Properties
    
    Equity
    
    Properties
    
    EquityCanadian GAAP
    
    $
    96,577
    
    
    $
    120,577
    
    
    $
    87,956
    
    
    $
    100,537Adjustment to ascribed value of shares
issued for royalty interests
    
    
    1,358
    
    
    
    1,358
    
    
    
    1,358
    
    
    
    1,358Impairment provision for China properties, net
    
    
    (9,755
    )
    
    
    (9,755
    )
    
    
    (9,834
    )
    
    
    (9,834
    )GTL and EOR development costs written off
    
    
    (5,004
    )
    
    
    (5,004
    )
    
    
    (4,074
    )
    
    
    (4,074
    )Adjustment for change in accounting for
stock based compensation:Share capital
    
    
    
    
    
    
    (271
    )
    
    
    
    
    
    
    (271
    )Contributed surplus
    
    
    
    
    
    
    (977
    )
    
    
    
    
    
    
    (516
    )Deficit
    
    
    
    
    
    
    1,248
    
    
    
    
    
    
    
    787U.S. GAAP
    
    $
    83,176
    
    
    $
    107,176
    
    
    $
    75,406
    
    
    $
    87,987
 Under U.S. GAAP, the transfer of deficit to share capital, which occurred in
1999, would not be recognized and shareholders equity would be presented as
follows: June 30,
    
    December 31,2004
    
    2003Share capital (including adjustments above)
    
    $
    258,767
    
    
    $
    236,617Contributed surplus (non-employee stock based compensation)
    
    
    19
    
    
    
    Deficit (Including adjustments above)
    
    
    (151,610
    )
    
    
    (148,630
    )$
    107,176
    
    
    $
    87,987
 11




---



##### 



Consolidated Statements of Loss and Deficit As discussed under Oil and Gas Properties in Note 20 of the Companys
December 31, 2003 consolidated financial statements, there is a difference in
performing the ceiling test evaluation under full cost accounting between U.S.
and Canadian GAAP. Application of the ceiling test evaluation under U.S. GAAP
as at December 31, 2001 required an additional $10.0 million provision for
impairment with respect to the Companys China properties. This
difference results in a lower depletion rate for U.S. GAAP. The capitalization of development costs permitted under Canadian GAAP in
connection with our GTL and EOR prospects is not permitted under U.S. GAAP. The application of U.S. GAAP has the following effect on net loss and net loss
per share: Three Month Periods Ended June 30,2004
    
    2003Net
    
    Net Loss
    
    Net
    
    Net LossLoss
    
    Per Share
    
    Loss
    
    Per ShareCanadian GAAP
    
    $
    1,298
    
    
    $
    0.01
    
    
    $
    4,587
    
    
    $
    0.03Stock based compensation expense
    
    $
    (232
    )
    
    
    
    
    
    
    (122
    )
    
    
    Depletion
adjustment  China
    
    
    (57
    )
    
    
    
    
    
    
    (22
    )
    
    
    GTL development costs written off, net
    
    
    501
    
    
    
    
    
    
    
    (3,118
    )
    
    
    (0.02
    )U.S. GAAP
    
    $
    1,510
    
    
    $
    0.01
    
    
    $
    1,325
    
    
    $
    0.01Weighted Average Number of Shares under
U.S. GAAP (in thousands)
    
    
    
    
    
    
    169,116
    
    
    
    
    
    
    
    145,055
 Six Month Periods Ended June 30,2004
    
    2003Net
    
    Net Loss
    
    Net
    
    Net LossLoss
    
    Per Share
    
    Loss
    
    Per ShareCanadian GAAP
    
    $
    2,590
    
    
    $
    0.02
    
    
    $
    5,695
    
    
    $
    0.04Stock based compensation expense
    
    
    (461
    )
    
    
    
    
    
    
    (232
    )
    
    
    Depletion
adjustment  China
    
    
    (80
    )
    
    
    
    
    
    
    (45
    )
    
    
    GTL development costs written off, net
    
    
    931
    
    
    
    
    
    
    
    (2,908
    )
    
    
    (0.02
    )U.S. GAAP
    
    $
    2,980
    
    
    $
    0.02
    
    
    $
    2,510
    
    
    $
    0.02Weighted Average Number of Shares under
U.S. GAAP (in thousands)
    
    
    
    
    
    
    165,622
    
    
    
    
    
    
    
    144,832
 Stock Based Compensation Had compensation expense been determined based on the fair value of options
issued to employees and directors at the stock option grant date, including
those granted prior to January 1, 2002, 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 as follows: 12




---



##### 



Three Month Periods
    
    Six Month PeriodsEnded June 30,
    
    Ended June 30,2004
    
    2003
    
    2004
    
    2003Net loss under U.S. GAAP
    
    $
    1,510
    
    
    $
    1,325
    
    
    $
    2,980
    
    
    $
    2,510Stock-based compensation expense determined under the
fair value based method for employee and director
awards
    
    
    498
    
    
    
    409
    
    
    
    992
    
    
    
    807Pro forma net loss under U.S. GAAP
    
    $
    2,008
    
    
    $
    1,734
    
    
    $
    3,972
    
    
    $
    3,317Basic and diluted loss per common share under U.S. GAAP:As reported
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.02
    
    
    $
    0.02Pro forma
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.02
    
    
    $
    0.02Weighted Average Number of Shares under U.S. GAAP (in
thousands)
    
    
    169,116
    
    
    
    145,055
    
    
    
    165,622
    
    
    
    144,832
 Impact of New and Pending U.S. GAAP Accounting Standards In March 2004, the FASB issued an exposure draft Share-Based Payment. This
exposure draft proposes to revoke the alternative of accounting for employee
stock based compensation under the intrinsic value method. As the Company is
currently using the provision under SFAS 123 that allow the use of the
intrinsic method of accounting for share-based payments, it is anticipated that
the adoption of this exposure draft may have a material impact on the Companys
results of operations or financial position. However, at this time the exposure
draft has neither been accepted nor rejected by the FASB. If adopted the
application of this policy is expected to be for fiscal years beginning after
December 2004. In June 2004, the 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.  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 13




---



##### 



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, 2003, 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. Results of Operations For the three-month period ended June 30, 2004, the net loss was $1.3 million
($0.01 per share) compared to a net loss of $4.6 million ($0.03 per share) for
the same period in 2003. The net loss for the six-month period ended June 30,
2004 was $2.6 million ($0.02 per share) compared to a net loss of $5.7 million
($0.04 per share) for the same period in 2003. The net loss for the
three-month and six-month periods ended June 30, 2003 include a $3.3 million
($0.02 per share) write down of our investment in the Qatar gas-to-liquids
(GTL) project as a result of the termination of contract negotiations in May
2003. Cash from operating activities for the three-month and six-month periods ended
June 30, 2004 was $1.3 million compared to cash from operating activities of
$0.9 million and $1.2 million for the same periods in 2003. Our cash position
increased $15.9 million for the first six months of 2004 primarily due to net
proceeds of $20.4 million received from private placements in the first quarter
of 2004, $20.0 million from Richfirst related to its farm-in to the Dagang oil
project development program, $2.0 million in proceeds from the Wells Fargo loan
related to the development of our South Midway field and $1.4 million from the
exercise of stock options. This is partially offset by $25.4 million for
capital spending for the first six months of 2004 and $2.5 million paid to
Ensyn under our agreements with that company. Our cash position decreased $1.1
million for the comparable period in 2003 primarily due to $4.1 million of net
cash required for capital spending partially offset by $1.2 million in cash
from operating activities and an increase in notes payable of $1.8 million. Production and Operations Oil and gas revenues for the three-month and six-month periods ended June 30,
2004 were $3.5 million and $6.8 million, respectively. This represents
increases of $1.1 million and $1.9 million from the comparable periods in 2003.
Half of the increase in revenue for the three-month period ended June 30, 2004
is due to a 21% or $5.68 per boe increase in oil and gas prices from the
comparable period in 2003. Increases in production volumes account for the
remaining 50% increase in revenues as a result of additional development
programs initiated in 2003 at the South Midway and Daqing fields and the start
up of production in 2004 at our Citrus and Knights Landing fields. Production
volumes from the Dagang field development, initiated at the end of 2003,
increased 44% from the comparable period in 2003 but these increases are mostly
offset by CITICs participation in its 40% share of production related to
finalizing the farm-out agreement in the second quarter of 2004. The increase
in revenues for the six-month period ended June 30, 2004 was mainly due to more
than a four-fold increase in production volumes from the Daqing field, in which
we own a royalty interest, in addition to increases in production from the
southern expansion of our South Midway field and the start up of production
operations at our Citrus and Knights Landing fields in 2004. Additionally, a
16% or $4.36 per boe increase in oil and gas prices contributed to a 45%
increase in revenues for the six-month period ended June 30, 2004. 14




---



##### 



Operating costs decreased 5% or $0.37 per boe for the three-month period ended
June 30, 2004 compared to the same period in 2003. Operating costs in China
decreased 17% or $1.51 per boe for the second quarter of 2004 due mainly to a
reduction in well workovers and decreased power costs in 2004. Operating costs
in the U.S. increased 6% or $0.47 per boe for the second quarter of 2004 as
compared to the same period in 2003 due mainly to the start up of production
operations at our Knights Landing and Sledge Hamar fields partially offset by a
reduction in workover costs at our Spraberry field. For the six-month period
ended June 30, 2004, operating costs increased 10% or $0.75 per boe compared to
the same period in 2003. Operating costs in China decreased 8% or $0.59 per boe
due mainly to a reduction in well workovers and decreased power costs during
the second quarter of 2004. Operating costs in the U.S. increased 26% or $1.76
per boe for the six-month period ended June 30, 2004 due mainly to an increase
in costs incurred for the cyclic steam operations in the southern expansion of
South Midway in the first quarter of 2004 and the start up of production
operations at our Citrus, Knights Landing and Sledge Hamar fields during 2004.
This is partially offset by a reduction in workover costs at our Spraberry
field from the comparable period in 2003. Our depletion rate increased $5.39 and $4.33 per boe for the three-month and
six-month periods ended June 30, 2004, respectively, compared to the same
periods in 2003. The depletion rate in China increased $2.07 and $1.96 per boe
for the three-month and six-month periods ended June 30, 2004, respectively,
due mainly to anticipated increases in Dagang future development costs. The
depletion rate in the U.S. increased $7.86 and $6.22 per boe for the
three-month and six-month periods ended June 30, 2004, respectively, due mainly
to an increase in the carrying costs of our evaluated U.S. oil and gas assets
during the fourth quarter of 2003 primarily in Northwest Lost Hills, East Texas
and North South Forty. In addition, the increase in the U.S. depletion rate for
the three-month period ended June 30, 2004 is due to an increase in Knights
Landing exploration costs and a decrease in estimated reserves for Knights
Landing a result of reduced success in the current exploration drilling program
as five dry holes had been drilled as at June 30, 2004. Production and operating information are detailed below: Three-Month Periods Ended June 30,2004
    
    2003U.S.
    
    China
    
    Total
    
    U.S.
    
    China
    
    TotalNet Production:BOE
    
    
    60,848
    
    
    
    45,502
    
    
    
    106,350
    
    
    
    49,806
    
    
    
    36,698
    
    
    
    86,504BOE/day for the year
    
    
    669
    
    
    
    500
    
    
    
    1,169
    
    
    
    547
    
    
    
    403
    
    
    
    950
 Per BOE
    
    Per BOEOil and gas revenue
    
    $
    32.97
    
    
    $
    32.21
    
    
    $
    32.65
    
    
    $
    25.04
    
    
    $
    29.55
    
    
    $
    26.96Operating costs
    
    
    7.87
    
    
    
    7.17
    
    
    
    7.57
    
    
    
    7.40
    
    
    
    8.68
    
    
    
    7.94Production taxes
    
    
    1.12
    
    
    
    
    
    
    
    0.64
    
    
    
    0.98
    
    
    
    
    
    
    
    0.57Engineering support
    
    
    2.12
    
    
    
    3.38
    
    
    
    2.66
    
    
    
    1.87
    
    
    
    3.22
    
    
    
    2.4411.11
    
    
    
    10.55
    
    
    
    10.87
    
    
    
    10.25
    
    
    
    11.90
    
    
    
    10.95Net Revenue before depletion
    
    
    21.86
    
    
    
    21.66
    
    
    
    21.78
    
    
    
    14.79
    
    
    
    17.65
    
    
    
    16.01Depletion
    
    
    15.85
    
    
    
    11.01
    
    
    
    13.78
    
    
    
    7.99
    
    
    
    8.94
    
    
    
    8.39Net Revenue from operations
    
    $
    6.01
    
    
    $
    10.65
    
    
    $
    8.00
    
    
    $
    6.80
    
    
    $
    8.71
    
    
    $
    7.62
 15




---



##### 



Six-Month Periods Ended June 30,2004
    
    2003U.S.
    
    China
    
    Total
    
    U.S.
    
    China
    
    TotalNet Production:BOE
    
    
    119,214
    
    
    
    95,864
    
    
    
    215,078
    
    
    
    105,783
    
    
    
    73,757
    
    
    
    179,540BOE/day for the year
    
    
    655
    
    
    
    527
    
    
    
    1,182
    
    
    
    584
    
    
    
    407
    
    
    
    991
 Per BOE
    
    Per BOEOil and gas revenue
    
    $
    31.88
    
    
    $
    30.92
    
    
    $
    31.45
    
    
    $
    25.42
    
    
    $
    29.48
    
    
    $
    27.09Operating costs
    
    
    8.51
    
    
    
    7.28
    
    
    
    7.96
    
    
    
    6.75
    
    
    
    7.87
    
    
    
    7.21Production taxes
    
    
    1.15
    
    
    
    
    
    
    
    0.64
    
    
    
    0.95
    
    
    
    
    
    
    
    0.56Engineering support
    
    
    2.34
    
    
    
    3.15
    
    
    
    2.70
    
    
    
    1.87
    
    
    
    3.40
    
    
    
    2.5012.00
    
    
    
    10.43
    
    
    
    11.30
    
    
    
    9.57
    
    
    
    11.27
    
    
    
    10.27Net Revenue before depletion
    
    
    19.88
    
    
    
    20.49
    
    
    
    20.15
    
    
    
    15.85
    
    
    
    18.21
    
    
    
    16.82Depletion
    
    
    15.11
    
    
    
    11.22
    
    
    
    13.37
    
    
    
    8.89
    
    
    
    9.26
    
    
    
    9.04Net Revenue from operations
    
    $
    4.77
    
    
    $
    9.27
    
    
    $
    6.78
    
    
    $
    6.96
    
    
    $
    8.95
    
    
    $
    7.78
 Changes in Non-Cash Working Capital Non-cash working capital increased $6.2 million and $5.4 million for the
three-month and six-month periods ended June 20, 2004, respectively, compared
to increases of $1.8 million and $2.4 million for the same periods in 2003. The
increases in non-cash working capital for investing activities for the
three-month and six-month periods ended June 20, 2004 are mainly due to
increases of $6.4 million and $6.3 million, respectively, in our payables and
accruals as a result of our capital programs in China and the U.S. The increase
in non-cash working capital for investing activities for the three-month and
six-month periods ended June 30, 2004 is partially offset by increases of $0.8
million and $1.1 million, respectively, in accounts receivable primarily as a
result of advances made to our joint venture partners to fund our U.S.
development and Iraq EOR activities. Exploration and Development Activities Capital spending on exploration and development activities for the three-month
and six-month periods ended June 30, 2004 was $14.1 million and $24.2 million,
respectively, an increase of $11.5 million and $19.8 million from the amounts
spent during the comparable periods in 2003. This increase is due mainly to our
development programs in our Dagang, Citrus and Knights Landing fields and our
Zitong seismic acquisition program in China. Capital spending at Dagang increased $3.3 million and $7.1 million during the
three-month and six-month periods ended June 30, 2004, respectively, compared
to the same periods in 2003. By the end of the second quarter of 2004, we had
drilled seven development wells in Dagang, four of which are on production and
the remaining three wells are in various stages of completion or testing. Three
drilling rigs are now under contract for the Dagang project and the development
program is on schedule for a year-end 2004 gross production target of 2,500
bopd. Over the next three years, we expect to drill 115 new wells and work
over 28 existing wells. During the second quarter of 2004, we completed phase one of our
1,100-kilometer seismic acquisition program in the Zitong project, which
increased our capital spending for the three-month and six-month periods ended
June 30, 2004 by $3.0 million and $5.0 million, respectively, compared to the
same periods in 2003. In our Zitong project we are continuing with the
interpretation of the seismic and plan to drill one exploration well in late
2004. 16




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##### 



We farmed into the Knights Landing gas project in northern California in
February 2004, which resulted in increases of $2.9 million and $4.4 million in
our capital spending program for the first three-month and six-month periods
ended June 30, 2004, respectively, compared to the same periods in 2003. We
acquired a 50% non-operating interest in four gas wells in that area and agreed
to fund the cost of a gas gathering and surface facilities system to the four
wells at a combined cost of $1.6 million. We also hold a 50% interest in 14,000
acres of leases in the surrounding area for further exploration drilling. In
May 2004, the pipeline gathering system and facilities were completed and the
four gas wells were placed on production. In late May 2004, the 10 well
drilling program commenced. Nine of the 10 wells have been drilled resulting in
three gas discoveries and 6 dry holes. The three gas discoveries have been
tested and are now being tied in to the gathering system. The final well
remains to be drilled under the initial drilling program, and we are evaluating
drilling additional follow up wells to develop the three discoveries drilled
thus far. Development of our Citrus field increased our capital spending program $1.6
million and $2.4 million during the three-month and six-month periods ended
June 30, 2004, respectively, compared to the same periods in 2003. After having
placed Citrus #1 on production in January 2004, additional work was conducted
on the well in the second quarter of 2004 to add the Lower Reef Ridge zone to
the existing horizontal Antelope zone. Both zones are currently flowing about
50 barrels of oil per day. A downhole pump will be installed in the near
future to increase total rates. The Citrus #2 well is currently being
completed in four combined oil zones with fracture stimulation of each
interval. The Citrus #3 well has finished drilling and should be completed by
mid-August. We plan to observe production for a few months prior to resuming
development of this area to determine the best drilling and completion methods. In January 2004, we farmed into the LAK Ranch Field, a thermal
recovery/horizontal well oil project in Weston County, Wyoming. Facility
modifications for the pilot phase were completed in the second quarter of 2004
increasing our capital spending program $0.3 million and $0.8 million for the
three-month and six-month periods ended June 30, 2004, respectively, compared
to the same periods in 2003. The first cycle of steam injection into the
horizontal producer was completed by the end of May 2004. Approximately 70% of
the steam has been recovered to date and oil cuts are improving as anticipated.
The oil is high-quality, 19-degree API gravity, and contains high levels of
naphtha. Plans are underway to commence a second steam cycle in the third
quarter of 2004, using a larger quantity of steam at a higher pressure to
further stimulate oil production. Progress continues with the planned
ultra-high resolution 3D seismic survey scheduled for the last quarter of 2004.
The survey is designed to provide the necessary detail for targeting future
horizontal well development at LAK Ranch. After completion of the 3D seismic
survey we plan to drill additional delineation wells to prove up oil-in-place
reserves and commerciality of a full steam injection project. Following
completion of the pilot phase, the development program is scheduled to include
additional horizontal producing wells, new steam injection wells and the
extension of surface facilities. We estimate that, at the low end of the
recovery range, the initial development program could grow to more than 20
producing wells. During the pilot phase, we will have an initial 30% working
interest. Should we decide to enter the next two phases of the contract, our
working interest will increase to a maximum of 60%. Should we elect not to
proceed beyond the pilot phase, our working interest will be reduced to 15% and
we would no longer be the operator. Capital spending in South Midway decreased $0.2 million and $0.6 million during
the three-month and six-month periods ended June 30, 2004, respectively,
compared to the same periods in 2003 due mainly to the completion of the
construction of our facilities for the first phase of the southern expansion in
the third quarter of 2003. We drilled five delineation wells in South Midway in
the second quarter of 2003 compared to six delineation wells and one
exploratory well in the second quarter of 2004, resulting in the completion of
four producing oil wells. The production from the southern expansion area is
showing more favorable response to steam with total South Midway production
currently averaging about 600 barrels of oil per 17




---



##### 



day compared to an average of 530 barrels of oil per day for the second quarter
of 2004. We will monitor production from the southern expansion area to
determine optimum well locations before resuming development. We have 55
producing wells in South Midway, with a working interest of 100%. Exploration and development of Sledge Hamar increased our capital spending
program $0.3 million and $0.4 million during the three-month and six-month
periods ended June 30, 2004, respectively, compared to the same periods in
2003. We have one producing discovery well, the Sledge Hamar 1-7 with a working
interest of 40%. A second appraisal well, the Sledge Hamar 2-7, was drilled in
May 2004 and was unsuccessful in establishing production from the Stevens sand
that produces in the Sledge Hamar 1-7 well. We are evaluating a test program
for shallower Diatomite zones where shows were encountered in the Sledge Hamar
2-7 well. The Diatomite is a producing formation in the adjacent South Belridge
field. Follow up wells may be drilled in the latter part of 2004 to further
develop both the Stevens and the Diatomite zones. Our capital spending program for the remainder of 2004 also includes additional
North South Forty wells in the San Joaquin Valley of California and Malakoff
and Catfish Creek wells in East Texas as follows: We hold a 50% working interest in two shallow gas prospects that have been
defined in the North South Forty seismic area as a result of an extensive 3-D
seismic acquisition program conducted on lands west of the Belridge oil field.
In May 2004, we drilled the first prospect to 1,500 feet resulting in increase
in capital spending of $0.1 million for the three-month and six-month periods
ended June 30, 2004. The well was a dry hole and was abandoned. The second of
the two prospects will be drilled in the third quarter of 2004. In addition, we
hold a 100% working interest in a third oil and gas prospect in the North South
Forty seismic area. We plan to drill a 3,500 foot well late in 2004. We are
currently seeking a partner to participate with us in the latter prospect. In East Texas, we plan to farm-out the drilling of one well each in the
Malakoff and Catfish Creek prospects in which we have a 25% carried interest.
The Malakoff well is planned to be drilled to a depth of 8,700 feet and the
Catfish Creek well to a depth of 11,000 feet. Heavy-to-Light Activities In January 2004, we signed a Stock Purchase and Shareholders Agreement with
Ensyn Group Inc. (Ensyn Group) and its subsidiary, Ensyn Petroleum
International Ltd. (Ensyn), pursuant to which, for a total payment of $2
million, we acquired a 10% equity interest in Ensyn and exclusive rights to use
the proprietary Ensyn RTPTM Process in several key international markets. In April 2004, we signed an agreement with Ensyn Group and Ensyn pursuant to
which we advanced Ensyn an additional $1.0 million in consideration for the
right to elect to either take an additional 5% equity interest in Ensyn or
consider the advance as a loan to be repaid with interest over a period of 90
days commencing on July 31, 2005. Ensyn is currently installing a commercial demonstration facility in the South
Belridge field near Bakersfield, California to demonstrate the commercial
viability of the Ensyn RTPTM Process at the facility in mid-September, 2004. The Ensyn RTPTM Process upgrades the quality of heavy oil by producing lighter,
more valuable crude oil. Ensyn reports that this process yields up to a
three-fold economic improvement in heavy-oil projects. The heaviest hydrocarbon
fraction is consumed as fuel to 18




---



##### 



generate the steam used to enhance recovery of
heavy crude. This lowers costs by reducing
or eliminating the need to purchase high-priced natural gas for steam
generation and improves revenue since the higher quality light-crude fraction
can be sold at higher prices. The lighter crude has improved viscosity that
permits more efficient pumping through pipeline networks and significantly
reduces transportation costs to marketing points. The Ensyn RTPTM Process uses
readily available plant and process components. The technology already has been
successfully applied to continuous wood/biomass processing, with several
commercial plants in operation in Canada and the U.S. An Ensyn pilot plant in
Ontario, Canada, has completed more than 90 test runs on heavy oil. We have exclusive rights to use the Ensyn RTPTM Process in China, Mongolia,
Iraq, Oman and all countries in South America except Venezuela. In these
countries, our rights will be exclusive for an initial term of five years
subject to extension if and when commercial plants are constructed. We have
non-exclusive rights to the process in other countries. For each project we
develop using the Ensyn RTPTM Process, Ensyn may elect to receive an equity
participation in the project for the same proportionate cost as paid by the
Company. The participation that may be obtained by Ensyn is no more than 10%,
except for each such project that we develop in South America, other than in
Venezuela and Peru, where Ensyn may elect to receive an equity interest equal
to 25% of our interest. Ensyns equity position will offset and eliminate the
payment of license fees for use of the Process in the project. Gas-to-Liquids Activities There was no additional capital spending on GTL projects for the three-month
period ended June 30, 2004. In the second quarter of 2004, we wrote down our $0.3 million investment in the
Oman GTL project as our opportunity to build a 45,000 bpd GTL fuels plant in
Oman failed to materialize due to a lack of sufficient uncommitted gas volumes
to support a 45,000 bpd GTL plant in Oman. Although our proposal for a 45,000-barrels per day GTL plant in Egypt is still
under consideration by the government of Egypt, and its agencies responsible
for the development and monetization of its natural gas reserves, the
government is currently evaluating alternatives for monetization of its
uncommitted gas reserves including pipelines to neighboring countries and
liquid natural gas plants. We await the outcome of their evaluations. We have completed the initial phase of the commercialization study for the GTL
plant in Bolivia. The results indicate that under the current tax regulations
pertaining to the Bolivian hydrocarbon sector, a 90,000 barrel-per-day GTL
plant could be commercial in the southern region of Bolivia. However, given
the current political climate and the uncertainty surrounding the impact that
newly proposed tax regulations could have on the viability of a GTL plant, we,
and our partners in the commercialization study, have elected not to proceed
any further until all hydrocarbon legislation has been finalized which is
expected during the third quarter of 2004. EOR Capital spending on EOR related activities for the three-month and six-month
periods ended June 30, 2004 was $0.8 million and $1.2 million, respectively.
Several of our senior executives and technical personnel have had prior
experience working on oil projects at various fields in Iraq. We are utilizing
this prior experience and the experience of consultants with extensive
knowledge of, and background in, Iraq to plan and pursue development 19




---



##### 



activities that, if successful, would result in increased oil production and
reserves in that country. Liquidity and Capital Resources As at June 30, 2004, our cash position was $30.4 million as a result of closing
two special warrant financings in the first quarter of 2004, which generated
net proceeds of $20.4 million, we received $20.0 million from Richfirst related
to their 40% farm-in to the Dagang oil project development program and $2.0
million in proceeds from the Wells Fargo loan related to the development of our
South Midway field. We borrowed the final $2.0 million on the Wells Fargo loan
in July 2004 bringing the total loan amount to $5.0 million. The budget for our capital program for the remainder of 2004, is estimated to
be $28.5 million. Our current cash position, expected cash flows, bank credit
facility and funding from third-party agreements will enable us to complete our
2004 capital program. We continue to pursue acquisitions of proven and probable
reserves and technologies that enhance the recovery of oil and gas reserves as
a means of supplementing our growth strategy. However, to complete the
development of our fields and to execute our medium and long-term growth
strategies we will require additional funding. We plan to seek such financing
through a combination of equity, convertible debentures, debt, mezzanine
financing and joint venture partner participation. The Company and its 40%
joint venture partner, CITIC, are currently in active discussions with leading
European and Chinese lenders for a project bank loan to provide funding for the
development of the Dagang oil field in China. We cannot assure you that we
will be successful in raising the additional funds necessary or securing joint
venture partners to complete our expansion and capital programs. If we are
unsuccessful, we will have to prioritize such 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 Consolidated Balance Sheet as at June 30, 2004 and/or disclosed
in the accompanying Notes: Payments Due by Year(stated in thousands of U.S. dollars)AfterTotal
    
    2004
    
    2005
    
    2006
    
    2007
    
    2007Purchase Agreements:
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Consolidated Balance Sheets:Note payable
 current portion (Note 8)
    
    
    917
    
    
    
    417
    
    
    
    500
    
    
    
    
    
    
    
    
    
    
    
    Note payable
 long term portion (Note 8)
    
    
    2,083
    
    
    
    
    
    
    
    500
    
    
    
    1,000
    
    
    
    583
    
    
    
    Other Commitments:
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Operating leases
    
    
    1,926
    
    
    
    292
    
    
    
    520
    
    
    
    488
    
    
    
    338
    
    
    
    287Exploration commitment (a)
    
    
    10,900
    
    
    
    1,600
    
    
    
    9,300
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    $
    15,826
    
    
    $
    2,309
    
    
    $
    10,820
    
    
    $
    1,488
    
    
    $
    921
    
    
    $
    287
  a)
    
    This represents our estimate of the remaining expenditure commitment for the
minimum work program during the first phase of Zitong. This is a total spending
commitment and not a commitment per year. The amounts per year are based on our
current estimate. Off Balance Sheet Arrangements As at June 30, 2004 and December 31, 2003, 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 20




---



##### 



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 of July 30, 2004, there were 169,534,911 common shares of the Company issued
and outstanding, 17,451,826 share purchase warrants outstanding and exercisable
to purchase 9,350,913 common shares and incentive stock options outstanding to
purchase 8,048,343 common shares. Quarterly Financial Data In Accordance With Canadian and U.S. GAAP (Unaudited) Quarter Ended(stated in thousands of U.S. Dollars except per share amounts)2004
    
    2003
    
    2002Q2
    
    Q1
    
    Q4
    
    Q3
    
    Q2
    
    Q1
    
    Q4
    
    Q3
    
    Q2Total revenue
    
    $
    3,521
    
    
    $
    3,332
    
    
    $
    2,330
    
    
    $
    2,423
    
    
    $
    2,338
    
    
    $
    2,568
    
    
    $
    2,371
    
    
    $
    2,350
    
    
    $
    2,024Net loss  Canadian
GAAP
    
    $
    1,298
    
    
    $
    1,292
    
    
    $
    23,154
    
    
    $
    1,330
    
    
    $
    4,587
    
    
    $
    1,108
    
    
    $
    1,227
    
    
    $
    3,164
    
    
    $
    1,204Net loss  U.S. GAAP
    
    $
    1,510
    
    
    $
    1,470
    
    
    $
    23,270
    
    
    $
    1,306
    
    
    $
    1,325
    
    
    $
    1,185
    
    
    $
    1,287
    
    
    $
    2,976
    
    
    $
    1,808Net loss per share
 Canadian GAAP
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.15
    
    
    $
    0.01
    
    
    $
    0.03
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.02
    
    
    $
    0.01Net loss per share
 U.S. GAAP
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.15
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.01
    
    
    $
    0.02
    
    
    $
    0.02
 The 2003 and 2002 quarterly earnings have been adjusted to give effect to the
retroactive application of the new Canadian Institute of Chartered Accountants
Handbook Section 3870  Stock Based Compensation, which is described in Note 2
to the unaudited consolidated financial statements. The net loss in the fourth
quarter of 2003 includes an impairment charge of $20.0 million for U.S. oil and
gas assets. The net loss under Canadian GAAP for the second quarter of 2003
includes 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 were
written off as they were incurred. The net loss for the third quarter of 2002
includes a $2.4 million write down of the Sweetwater, Australia GTL assets. Item 3.     Quantitative and Qualitative Disclosures About Market Risk No material changes since December 31, 2003. Item 4.     Controls and Procedures The Company carried out an evaluation, under the supervision and with the
participation of the Companys management, including the Companys CEO and CFO,
of the effectiveness of the design and operation of the Companys disclosure
controls and procedures pursuant to the Securities Exchange Act of 1934. Based
upon that evaluation, the CEO and CFO concluded that, as of June 30, 2004, the
Companys disclosure controls and procedures are effective in timely alerting
them to material information required to be included in the Companys periodic
SEC filings relating to the Company (including its consolidated subsidiaries).
There were no significant changes in the Companys internal control over 21




---



##### 



financial reporting or in other factors that could significantly affect its
internal control over financial reporting during the period ended June 30, 2004
nor any significant deficiencies or material weaknesses in such internal
control over financial reporting requiring corrective actions. As a result, no
corrective actions were taken. Part II  Other Information Item 1.     Legal Proceedings: None Item 2.     Changes in Securities and Use of Proceeds: None 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
    
    DESCRIPTION
  31.1
    
    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(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: August 3, 2004 22




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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
 23