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

FORM 10-Q

		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. For the quarterly period ended June 30, 2002
or
		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

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 Change Since Last Report:

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            No            

The number of shares of the registrant’s capital stock outstanding as of June 30, 2002 was 144,630,818 Common Shares, no par value.

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Part I — Financial Information

Item 1 Financial Statements

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

     (see accompanying notes)

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

(see accompanying notes)

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

(see accompanying notes)

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Notes to the Consolidated Condensed Financial Statements June 30, 2002

(all tabular amounts are expressed in thousands of United States
dollars except per share data) (Unaudited)

1.		The unaudited consolidated condensed financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2001 consolidated financial statements, except for a change in the policy of accounting for stock based compensation plan (see note 4), and should be read in conjunction therewith. The December 31, 2001 balance sheet was derived from the audited consolidated financial statements, but does not include all disclosures required by accounting principles generally accepted in Canada and in 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, 2002 and December 31, 2001 and the results of operations and cash flows for the three month and six month periods ended June 30, 2002 and 2001 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 disclosure in these condensed consolidated financial statements. Actual results may differ from those estimates.
2.		The consolidated condensed financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in Canada which conform to U.S. GAAP except as below:

Consolidated Condensed Balance Sheets

Under U.S. GAAP, the transfer of deficit to share capital, which occurred during the year ended December 31, 1999, would not be recognized and would comprise the following Shareholders’ Equity:

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Consolidated Condensed Statements of Loss and Deficit

3.     The following tables present the Company’s interim segment information:

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4.

Share Capital

Following is a summary of the changes in share capital and stock options outstanding for the six month period ended June 30, 2002:

		On June 20, 2002, the Company granted a service provider a six month stock option for the purchase of 250,000 shares at US$4.00 per share.
		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.
		Effective January 1, 2002, Canadian accounting standards require disclosure on a pro forma basis of the impact on net income of using the fair value method for stock options issued on or after January 1, 2002. Had compensation expense been determined based on the fair value at the stock option grant date, computed in accordance with the Black-Scholes option pricing model, the Company’s net loss and net loss per share for the six month period ended June 30, 2002 would have been $2.8 million and $.02 per share, respectively.

Item 2.     Management’s Discussion and Analysis of Financial Condition and Results of Operations

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, 2001, 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.

Operations

Oil and gas revenues for the three month and six month periods ended June 30, 2002 were $2.0 million and $3.6 million, respectively. This is a decrease in revenues of $0.3 million and $0.8 million, respectively, for the comparable periods in 2001 primarily as a result of a decline in oil and gas prices. For the quarter ended June 30, 2002 the loss was $1.1 million ($.01 per share) compared to a loss of $7.0 million ($.05 per share) for the second quarter of 2001. Our net loss for the six months ended June 30, 2002 was

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$2.6 million ($.02 per share) compared to a net loss of $7.9 million ($.06 per share) during the same period of 2001. The loss for the three months and six month periods ended June 30, 2001 include a $5.0 million provision for impairment resulting from a comparison of depletable capitalized oil and gas costs, which include exploration costs, with a standardized measure of future net cash flows for our U.S. properties.

Production

During the first six months of 2002, net production in the U.S. increased approximately 16% over the same period in 2001. This increase is primarily attributed to a 50% increase in production at South Midway Sunset, as a result of drilling additional wells and execution of our pilot steam program undertaken late in 2001 offset by a natural decline at Spraberry in addition to an increase in downtime for routine maintenance and the workover of wells. The full-scale cycle steam facilities for South Midway Sunset were completed as scheduled in the second quarter of 2002 and to date we have cycle steamed five wells. The wells are in various stages of response and we expect to realize significantly higher production rates in the third quarter. By the end of the third quarter we plan to have at least 11 wells responding to cycle steam injection.

The overall decrease in production in China, for the first six months of 2002 compared to the same period in 2001, is primarily as a result of the sale of our interest in the Daqing project in January 2002. We also regained an additional 20% interest in the Dagang field from Nippon Oil in mid-2001. However, net production from Dagang decreased 2%, due to a shut in of wells for routine maintenance and workovers during the second quarter.

Operating costs in the U.S. are down 4% per barrel for the first six months of 2002 compared to the same period in 2001. Operating costs per barrel in the South Midway Sunset have decreased 54% as a result of having installed permanent production and electrical facilities during 2001. This decrease is mostly offset by an increase in routine maintenance and workover costs in Spraberry. Depletion costs per barrel in the U.S. have decreased 8% primarily due to the impairment write-offs recorded in 2001.

During 2002 operating costs per barrel in China have decreased 40% compared to the first six months of 2001 as a result of having installed electrical facilities on certain wells in the Dagang field in late 2001. In addition, we have benefited by operating efficiencies as the wells mature. For each of the quarters presented in 2001 future development costs for China were inadvertently excluded from the depletion calculation. Depletion for the first six months of 2002 of $8.38 has increased $1.59 per barrel, compared to 2001, primarily as a result of anticipated increases in Dagang future development costs.

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Production and operating information are detailed below: