UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

IVANHOE ENERGY INC.

Suite 654 – 999 Canada Place
Vancouver, British Columbia, Canada
V6C 3E1

(604) 688-8323

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, 2004 was 169,419,911 Common Shares, no par value.

TABLE OF CONTENTS

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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)

(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 per share amounts)

(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, 2004
(all tabular amounts are expressed in thousands of U.S. dollars except per share data)
(Unaudited)

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.

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).

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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.

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 RTP^TM 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 RTP^TM 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.

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:

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Following is a summary of the changes in share capital and stock options outstanding for the six-month period ended June 30, 2004:

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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:

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

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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.

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.

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.

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%.

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.

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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.

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:

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:

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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:

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:

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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.

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

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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.

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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:

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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.

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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

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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 RTP^TM 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 RTP^TM Process at the facility in mid-September, 2004.

The Ensyn RTP^TM 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

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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 RTP^TM 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 RTP^TM 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 RTP^TM 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

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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: