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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

IVANHOE ENERGY INC.
(Exact name of registrant as specified in its charter)

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.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)

The number of shares of the registrant’s capital stock outstanding as of June 30, 2003 was 146,995,527 Common Shares, no par value.

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TABLE OF CONTENTS

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Part I — Financial Information

Item 1 Financial Statements

IVANHOE ENERGY INC.
Consolidated Balance Sheets
(stated in thousands of U.S. Dollars)

(see accompanying notes)

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IVANHOE ENERGY INC.
Unaudited Consolidated Statements of Loss and Deficit
(stated in thousands of U.S. Dollars except share and per share data)

(see accompanying notes)

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IVANHOE ENERGY INC.
Unaudited Consolidated Statements of Cash Flow
(stated in thousands of U.S. Dollars)

(see accompanying notes)

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Notes to the Consolidated Financial Statements
June 30, 2003
(all tabular amounts are expressed in thousands of U.S. dollars except per share data)
(Unaudited)

1. GENERAL

The unaudited consolidated financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2002 consolidated financial statements, except for a change in the policy of accounting for asset retirement obligations, and should be read in conjunction therewith. The December 31, 2002 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. All adjustments which are, in the opinion of management, necessary for a fair presentation of the Company’s financial position as at June 30, 2003 and December 31, 2002 and the results of operations and cash flows for the three-month and six-month periods ended June 30, 2003 and 2002 have been included. 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. SIGNIFICANT ACCOUNTING POLICIES

Asset Retirement

Prior to January 2003, the Company had estimated its future site restoration and abandonment costs associated with its oil and gas properties and amortized this estimate to operations using the unit-of-production method based upon estimated proved reserves. The provision was included with depletion and depreciation expense.

For fiscal years beginning after January 1, 2004, Canadian GAAP requires that asset retirement costs and liabilities associated with site restoration and abandonment of tangible long-lived assets be initially measured at a fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements at the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations.

The Company has elected early implementation of this accounting policy. Accordingly, effective January 1, 2003, the Company changed its accounting policy to capitalize asset retirement costs as part of the carrying value of its oil and gas properties and adjusted the amount of its site restoration liability to the present value of the liability for the corresponding asset retirement obligation as of this date. The Company has adopted the policy without retroactive adjustment of prior years because implementation of this change had an immaterial effect on the Company’s financial position and results of operations in prior years or in the current period (See notes 3 and 10).

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U.S. GAAP for asset retirement obligations conforms in all material respects to Canadian GAAP. Implementation for U.S. GAAP is required for fiscal years beginning after June 2002.

The asset retirement costs are being amortized using the unit of production method based on estimated proved reserves. The amortization expenses and accretion of the liability for the asset retirement obligation are included with depletion and depreciation expense.

3. OIL AND GAS PROPERTIES

Oil and gas properties, equipment and gas-to-liquids (“GTL”) investments are net of accumulated depletion and depreciation of $8.4 million and $6.6 million as well as provision for impairments of oil and gas properties of $14.0 million as at June 30, 2003 and December 31, 2002, respectively.

Effective January 2003, the Company capitalized $0.3 million as a result of implementation of a new accounting policy on asset retirement obligations. No additional asset retirement costs were incurred for the three-month and six-month periods ended June 30, 2003.

In May 2003, discussions were terminated between Qatar Petroleum and the Company in the negotiation of an agreement to develop a block in Qatar’s North Field to produce natural gas liquids and GTL products. As a result, the Company has taken a charge to income of $3.3 million for the write down of its investment in Qatar.

4. DERIVATIVE ACTIVITIES

The Company’s results of operations are sensitive mainly to fluctuations in oil and natural gas prices. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows.

The Company entered into a costless collar derivative to hedge its cash flow from the sale of 500 barrels of oil production per day over two six-month periods starting October 2002 and June 2003. The derivatives have ceiling prices of $30.45 and $28.95 per barrel for the June 2003 and October 2002 contracts, respectively, and a floor price of $24.00 per barrel using WTI as the index traded on the NYMEX. Gains and losses on derivatives are recognized in earnings as they are realized. For the six-month period ended June 30, 2003, the Company had realized losses of $0.2 million on derivative transactions. The Company had no realized derivative losses for the three-month period ended June 30, 2003. The derivative losses are included in oil and gas revenue.

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5. SEGMENT INFORMATION

The following tables present the Company’s interim segment information for the three-month and six-month periods ended June 30:

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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, 2003:

In July 2003, the Company closed a special warrant financing to advance the Company’s operations in California’s San Joaquin Basin and for general working capital purposes. The financing consisted of 3.0 million special warrants at US$1.00 per special warrant. Each special warrant entitles the holder to acquire one common share and one purchase warrant at no additional cost. Two purchase warrants are exercisable to purchase an additional common share at U.S.$1.00 until the first anniversary of closing and at U.S.$1.10 until the second anniversary of closing.

7. STOCK BASED COMPENSATION

The Company accounts for its stock-based compensation plans using the intrinsic-value of the options. Under this method, compensation costs are not recognized in the financial statements for share options granted to employees and directors when issued at market value. Had stock based compensation expense been determined based on the fair value at the option grant date, the Company’s net loss and net loss per share for the three-month and six-month periods ended June 30 would have been as follows:

The foregoing is calculated in accordance with the Black-Scholes options pricing model, using the following data and assumptions: 72% 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

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the date of the grant of 4.4% to 5.6%, based on one and five year Government of Canada Bond yields.

8. NOTES PAYABLE

As at June 30, 2003 the Company borrowed $1.25 million from a related party to finance China operations and $1.0 million in bank financing for the southern expansion of South Midway. The related party loans are unsecured and due 90 days after written demand, on the closing date of obtaining equity financing or December 31, 2005 whichever occurs earliest. The related party loans bear interest at U.S. prime plus 3%. Interest only is payable on the secured bank loan until January 15, 2004 after which the loan is repayable over three years plus interest at 0.50% above the bank’s prime rate or 3.0% over the London Inter-Bank offered rate (“LIBOR”), at the option of the Company. The $1.0 million secured bank loan has a six-month fixed LIBOR rate of 3.87%.

9. CONVERTIBLE DEBENTURE

In June 2003, the lender elected to convert the $1.0 million unsecured convertible debenture into 2 million of the Company’s common shares at $0.50 per share. All accrued interest on the debenture has been paid as of the conversion date.

10. ASSET RETIREMENT OBLIGATION

Effective January 2003, the Company changed its policy on accounting for liabilities associated with site restoration and abandonment of its oil and gas properties. The undiscounted amount of expected cash flows required to settle the asset retirement obligations is estimated at $0.8 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 7%. Implementation of the policy resulted in an additional provision for asset retirement of $0.2 million.

11. CLAIMS AND CONTINGENCIES

The Company and Aera Energy LLC (“Aera”) are in a dispute concerning certain costs incurred during the drilling of the Northwest Lost Hills # 1-22 well. The Company’s position is that gross cost overruns, incurred by Aera in its capacity as the operator of the well, were not previously approved by the Company under the terms of the joint operating agreement. Aera’s position is that the Company is in breach of the joint operating agreement for failing to pay its share of the disputed cost overruns in the amount of $2.7 million. The parties are attempting to negotiate a settlement of the dispute failing which the matter will be referred to binding arbitration. The amounts owed to Aera for the cost overruns, which are in dispute, are fully provided for in accounts payable and accrued liabilities.

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: