Edgar Filing: IVANHOE ENERGY INC

Quarterly Report Period Ended June 30, 2003

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

FORM 10-Q


[X]		Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
		For the quarterly period ended June 30, 2003
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

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 [X]		No [ ]

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


Yes [X]		No [ ]

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.

TABLE OF CONTENTS


Part I — Financial Information
	Item 1 Financial Statements
	Consolidated Balance Sheets
	Unaudited Consolidated Statements of Loss and Deficit
	Unaudited Consolidated Statements of Cash Flow
	Notes to the Consolidated Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
Part II — Other Information
	Item 1. Legal Proceedings:
	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
	Item 5. Other Information: None
	Item 6. Exhibits and Reports on Form 8-K
INDEX TO EXHIBITS
Certification CEO Internal Disclosure Controls
Certification CFO Internal Disclosure Controls
Certification CEO Report of Financial Statements
Certification CFO Report of Financial Statements

TABLE OF CONTENTS


		Page

PART I	Financial Information

Item 1	Financial Statements

	Consolidated Balance Sheets at June 30, 2003 (unaudited) and December 31, 2002	3

	Unaudited Consolidated Statements of Loss and Deficit for the Three-Month and Six-Month Periods Ended June 30, 2003 and 2002	4

	Unaudited Consolidated Statements of Cash Flow for the Three-Month and Six-Month Periods Ended June 30, 2003 and 2002	5

	Notes to the Unaudited Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3.	Quantitative and Qualitative Disclosures About Market Risks	17

Item 4.	Controls and Procedures	17

PART II	Other Information

Item 1.	Legal Proceedings	18

Item 2.	Changes in Securities and Use of Proceeds	18

Item 3.	Defaults Upon Senior Securities	18

Item 4.	Submission of Matters To a Vote of Securityholders	18

Item 5.	Other Information	18

Item 6.	Exhibits and Reports on Form 8-K	18

Part I — Financial Information

Item 1 Financial Statements

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


	June 30, 2003			December 31, 2002

	(unaudited)
Assets
Current Assets
Cash and cash equivalents	$	2,845		$	3,980
Accounts receivable		2,139			2,519
Other		179			691

		5,163			7,190
Long term assets		603			462
Oil and gas properties, equipment and GTL investments, net		99,246			99,436

	$	105,012		$	107,088

Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities	$	5,791		$	4,797
Notes payable		2,250			500
Convertible debenture		—			1,000

		8,041			6,297

Asset retirement obligation		412			243

Shareholders’ Equity
Share capital, issued 146,996,000 common shares; December 31, 2002 144,466,000		132,586			131,112
Deficit		(36,027	)		(30,564	)

		96,559			100,548

	$	105,012		$	107,088

(see accompanying notes)

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


	Three Months				Six Months
	Ended June 30,				Ended June 30,

	2003		2002		2003		2002

Revenue
Oil and gas revenue	$	2,332	$	1,981	$	4,864	$	3,644
Interest income		6		43		42		72

		2,338		2,024		4,906		3,716

Expenses
Operating costs		948		1,012		1,845		1,868
General and administrative		1,783		1,401		3,532		2,988
Depletion and depreciation		751		718		1,671		1,488
Write down of GTL investments		3,321		—		3,321		—

		6,803		3,131		10,369		6,344

Net Loss		4,465		1,107		5,463		2,628
Deficit, beginning of period		31,562		25,016		30,564		23,495

Deficit, end of period	$	36,027	$	26,123	$	36,027	$	26,123

Net Loss per share	$	0.03	$	0.01	$	0.04	$	0.02

Weighted Average Number of Shares (in thousands)		145,055		140,493		144,832		139,979

(see accompanying notes)

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


	Three Months						Six Months
	Ended June 30,						Ended June 30,

	2003			2002			2003			2002

Operating Activities
Net (loss)	$	(4,465	)	$	(1,107	)	$	(5,463	)	$	(2,628	)
Items not requiring use of cash:
Depletion and depreciation		751			718			1,671			1,488
Write down of GTL investments		3,321			—			3,321			—
Changes in non-cash working capital items		1,811			(2,252	)		2,360			(2,376	)

		1,418			(2,641	)		1,889			(3,516	)

Investing Activities
Capital spending		(2,856	)		(5,144	)		(4,774	)		(11,832	)
Proceeds from sale of assets		—			—			—			1,200

		(2,856	)		(5,144	)		(4,774	)		(10,632	)

Financing Activities
Shares issued on private placement		—			9,964			—			9,964
Shares issued on exercise of options		—			50			—			119
Proceeds from notes		1,500			—			1,750			—

		1,500			10,014			1,750			10,083

Increase (decrease) in cash and cash equivalents, for the period		62			2,229			(1,135	)		(4,065	)
Cash and cash equivalents, beginning of period		2,783			3,403			3,980			9,697

Cash and cash equivalents, end of period	$	2,845		$	5,632		$	2,845		$	5,632

Included in the above are the following:
Taxes paid	$	—		$	—		$	6		$	—

Interest paid	$	23		$	18		$	42		$	35

Decrease (increase) in non-cash working capital items:
Accounts receivable	$	495		$	(378	)	$	380		$	(107	)
Other current assets		575			141			512			147
Accounts payable and accrued liabilities		741			(2,015	)		1,468			(2,416	)

	$	1,811		$	(2,252	)	$	2,360		$	(2,376	)

(see accompanying notes)

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).

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.

5. SEGMENT INFORMATION

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


		Six Month Periods Ended June 30,

		2003						2002

		U.S.		China		Total		U.S.		China		Total

Oil and gas revenue		$	2,689	$	2,175	$	4,864	$	2,305	$	1,339	$	3,644
Interest income			42		—		42		72		—		72

			2,731		2,175		4,906		2,377		1,339		3,716

Operating costs			1,013		832		1,845		1,170		698		1,868
Depletion and depreciation			988		683		1,671		897		591		1,488

			2,001		1,515		3,516		2,067		1,289		3,356

Segment income before the following		$	730	$	660		1,390	$	310	$	50		360

Write down of GTL investments							3,321						—
General and administrative							3,532						2,988

Net loss						$	5,463					$	2,628

Capital Expenditures:
	Oil and gas	$	2,670	$	1,691	$	4,361	$	8,755	$	1,728	$	10,483

	Gas-to-liquids						413						1,349

						$	4,774					$	11,832


		As at June 30, 2003						As at December 31, 2002

Identifiable Assets:
	Oil & gas	$	64,334	$	26,409	$	90,744	$	64,448	$	25,281	$	89,729

	Gas-to-liquids						14,268						17,359

						$	105,012					$	107,088


		Three Month Periods Ended June 30,

		2003						2002

		U.S.		China		Total		U.S.		China		Total

Oil and gas revenue		$	1,247	$	1,085	$	2,332	$	1,273	$	708	$	1,981
Interest income			6		—		6		43		—		43

			1,253		1,085		2,338		1,316		708		2,024

Operating costs			511		437		948		640		372		1,012
Depletion and depreciation			423		328		751		439		279		718

			934		765		1,699		1,079		651		1,730

Segment income before the following		$	319	$	320		639	$	237	$	57		294

Write down of GTL investments							3,321						—
General and administrative							1,783						1,401

Net loss						$	4,465					$	1,107

Capital Expenditures:
	Oil and gas	$	1,556	$	1,097	$	2,653	$	3,648	$	777	$	4,425

	Gas-to-liquids						203						719

						$	2,856					$	5,144

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:


		Common Shares				Stock Options

									Weighted Average
		Number				Number			Exercise Price
		(thousands)		Amount		(thousands)			Cdn.$

Balance December 31, 2002			144,466	$	131,112		10,265		$	2.69
	Shares issued for service		530		474
	Shares issued for convertible debenture		2,000		1,000
	Options issued						150		$	1.42
	Options cancelled/forfeited						(584	)	$	4.48

Balance June 30, 2003			146,996	$	132,586		9,831		$	2.57

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:


	Three Months				Six Months
	Ended June 30,				Ended June 30,

	2003		2002		2003		2002

Pro forma net loss	$	4,569	$	1,276	$	5,683	$	2,797

Pro forma net loss per share	$	0.03	$	0.01	$	0.04	$	0.02

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

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:


	As at June 30, 2003						As at December 31, 2002

	Oil and Gas			Shareholders'			Oil and Gas			Shareholders'
Consolidated Balance Sheets	Properties			Equity			Properties			Equity

Canadian GAAP	$	99,246		$	96,559		$	99,436		$	100,548
Adjustment to ascribed value of shares issued for royalty interests		1,358			1,358			1,358			1,358
Impairment provision for China properties, net		(9,877	)		(9,877	)		(9,922	)		(9,922	)
Write off of GTL development costs		(3,695	)		(3,695	)		(6,603	)		(6,603	)
OCI — derivative mark-to-market adjustment		—			(59	)		—			(102	)

U.S. GAAP	$	87,032		$	84,286		$	84,269		$	85,279

Under U.S. GAAP, changes in the fair value of derivative instruments that meet specific cash-flow hedge accounting criteria are reported in other comprehensive income (OCI). The gains and losses on cash-flow derivative transactions that are reported in OCI are reclassified to earnings in the period in which earnings are affected by changes in the cash flow of the underlying hedged item. The Company’s derivative contracts qualify for hedge accounting treatment. The mark-to-market value of these derivatives as at June 30, 2003 and December 31, 2002 are losses of $0.1 million, which comprises the balance of OCI for those periods then ended.

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,
	2003			2002

Share capital (including adjustments above)	$	208,399		$	206,925
Deficit (Including adjustments above)		(124,054	)		(121,544	)
Accumulated other comprehensive income		(59	)		(102	)

	$	84,286		$	85,279


	Six Month Periods Ended June 30

	2003						2002

	Net			Net Loss			Net			Net Loss
Consolidated Statements of Loss and Deficit	Loss			Per Share			Loss			Per Share

Canadian GAAP	$	5,463		$	0.04		$	2,628		$	0.02
Depletion adjustment — China		(45	)		—			(38	)		—
GTL development costs written off, net		(2,908	)		(0.02	)		1,349			0.01

U.S. GAAP	$	2,510		$	0.02		$	3,939		$	0.03

Weighted Average Number of Shares under U.S. GAAP (in thousands)					144,832						139,979


	Three Month Periods Ended June 30

	2003						2002

	Net			Net Loss			Net			Net Loss
	Loss			Per Share			Loss			Per Share

Canadian GAAP	$	4,465		$	0.03		$	1,107		$	0.01
Depletion adjustment — China		(22	)		—			(18	)		—
GTL development costs written off, net		(3,118	)		(0.02	)		719			0.01

U.S. GAAP	$	1,325		$	0.01		$	1,808		$	0.02

Weighted Average Number of Shares under U.S. GAAP (in thousands)					145,055						140,493

Stock Based Compensation

Had compensation expense been determined based on fair value of options issued to employees and directors at the stock option grant date, consistent with the method of SFAS No. 123, Accounting for Stock-Based Compensation, the Company’s net loss and net loss per share would have been as follows:


	Three Months				Six Months
	Ended June 30,				Ended June 30,

	2003		2002		2003		2002

Net loss under U.S. GAAP	$	1,325	$	1,808	$	2,510	$	3,939
Stock -based compensation expense determined under fair-value method for employee awards		409		465		807		935

Pro forma net loss under U.S. GAAP	$	1,734	$	2,273	$	3,317	$	4,874

Basic loss per common share under U.S. GAAP:
As reported	$	0.01	$	0.02	$	0.02	$	0.03
Pro forma	$	0.01	$	0.02	$	0.02	$	0.03
Weighted Average Number of Shares under U.S. GAAP (in thousands)		145,055		140,493		144,832		139,979

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

Forward-Looking Statements

With the exception of historical information, certain matters discussed in this Form 10-Q are forward looking statements that involve risks and uncertainties. Certain statements contained in this Form 10-Q, including statements which may contain words such as “could”, “should”, “expect”, “believe”, “will” and similar expressions and statements relating to matters that are not historical facts are forward-looking statements. Such statements involve known and unknown risks and uncertainties which may cause our actual results, performances or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, our ability to raise capital as and when required, the timing and extent of changes in prices for oil and gas, competition, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and the potential success of gas-to-liquids development technology, 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, 2002, 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, 2003, the net loss was $4.5 million ($0.03 per share) compared to a net loss of $1.1 million ($0.01 per share) for the same period in 2002. The net loss for the six-month period ended June 30, 2003 was $5.5 million ($0.04 per share) compared to a net loss of $2.6 million ($0.02 per share) for the same period in 2002. The net loss for the three-month and six-month periods ended June 30, 2003 includes 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, 2003 was $1.4 million and $1.9 million, respectively, compared to a cash deficit from operating activities of $2.6 million and $3.5 million for the same periods in 2002. The cash from operating activities for the three-month and six-month periods ended June 30, 2003 includes $0.6 million for the return of funds from a derivative margin account. Our cash position decreased $1.1 million for the first six months of 2003 primarily due to $4.8 million of capital spending, partially offset by cash from operating activities of $1.9 million and an increase in notes payable of $1.8 million. Cash for the comparable period in 2002 decreased $4.1 million primarily due to $11.8 million of capital spending and $3.5 million cash deficit from operating activities, partially offset by the $1.2 million proceeds from the sale of our Daqing assets and the proceeds from a private placement of $10.0 million.

Production and Operations

Oil and gas revenues for the three-month and six-month periods ended June 30, 2003 were $2.3 million and $4.9 million, respectively. This represents an increase of $0.4 million and $1.2 million from the comparable periods in 2002 primarily as a result of an increase in oil and gas prices. Oil and gas prices were up $4.47/boe and $7.14/boe for the three-month and six-month periods ended June 30, 2003, respectively, compared to the same periods in 2002.

For the three-month and six-month periods ended June 30, 2003, net production from the U.S. was down compared to the same periods in 2002 due to the loss in production from Spraberry as a result of the sale of certain Spraberry interests in the second half of 2002. This loss was partially offset by increased production from South Midway as a result of the success of the cyclic steaming operations and increased drilling in 2002 and the second quarter of 2003. Production levels in China are up 10% for the quarter ended June 30, 2003 primarily due to an increase in producing wells in the Daqing block, which we sold in 2002 but retain a royalty interest.

Operating costs per boe in the U.S. are up slightly for the three-month and six-month periods ended June 30, 2003 compared to the same periods in 2002. Operating costs per boe in the South Midway increased as a result of additional costs associated with the full scale cyclic steaming program initiated in May 2002. This increase was mostly offset by a decrease in operating costs per boe at Spraberry due to a maturing of those operations and continuing cost controls. U.S. depletion costs per boe increased 17% for the first six months of 2003 compared to the same period in 2002 primarily due to the partial impairment of Northwest Lost Hills and other California properties in the second half of 2002. This increase in depletion costs has been partially offset as a result of an increase in proved reserves at South Midway.

Operating costs per boe in China increased 29% and 37% for the three-month and six-month periods ended June 30, 2003, respectively, compared to the same periods in 2002 as a result of increased workover, routine maintenance and utility costs in 2003. Depletion per boe in China increased 11% for the first six months of 2003 primarily due to a downward revision of our proved reserves at Dagang as a result of increased oil prices.

Production and operating information are detailed below:


		Six Month Periods Ended June 30,

		2003						2002

		U.S.		China		Total		U.S.		China		Total

Net Production:
	BOE		105,783		73,757		179,540		112,208		70,445		182,653
	BOE/day for the year		584		407		991		620		389		1,009






				Per BOE						Per BOE

Oil and gas revenue		$	25.42	$	29.48	$	27.09	$	20.54	$	19.01	$	19.95

Operating costs			6.75		7.87		7.21		6.61		5.74		6.27
Production taxes			0.95		—		0.56		1.23		—		0.76
Engineering support			1.87		3.40		2.50		2.59		4.17		3.20

			9.57		11.27		10.27		10.43		9.91		10.23

Net Revenue before depletion			15.85		18.21		16.82		10.11		9.10		9.72
Depletion			8.89		9.26		9.04		7.57		8.38		7.88

Net Revenue from operations		$	6.96	$	8.95	$	7.78	$	2.54	$	0.72	$	1.84


		Three Month Periods Ended June 30,

		2003						2002

		U.S.		China		Total		U.S.		China		Total

Net Production:
	BOE		49,806		36,698		86,504		54,587		33,487		88,074
	BOE/day for the year		547		403		950		600		368		968






				Per BOE						Per BOE

Oil and gas revenue		$	25.04	$	29.55	$	26.96	$	23.32	$	21.14	$	22.49

Operating costs			7.40		8.68		7.94		7.30		6.72		7.08
Production taxes			0.98		—		0.57		1.81		—		1.12
Engineering support			1.87		3.22		2.44		2.62		4.39		3.29

			10.25		11.90		10.95		11.73		11.11		11.49

Net Revenue before depletion			14.79		17.65		16.01		11.59		10.03		11.00
Depletion			7.99		8.94		8.39		7.60		8.34		7.88

Net Revenue from operations		$	6.80	$	8.71	$	7.62	$	3.99	$	1.69	$	3.12

General and Administrative

For the three-month and six-month periods ended June 30, 2003 general and administrative costs declined by $0.1 million and $0.5 million, respectively, compared to the same periods in 2002 due to staff reductions and cost cutting measures implemented in 2002. However, such costs allocated to our exploration and development activities declined by $0.5 million and $1.0 million for the same periods primarily due to a reduction in those activities in 2003. As a result we expensed a net of $0.4 million and $0.5 million more in general and administrative costs for the three-month and six-month periods ended June 30, 2003 compared to the same periods in 2002.

Exploration and Development Activities

Spending on these activities for the three-month and six-month periods ended June 30, 2003 was $2.7 million and $4.4 million a decrease of $1.8 million and $6.1 million, respectively, over the amounts spent during the comparable periods in 2002. These decreases are primarily due to the completion of our exploration drilling at Northwest Lost Hills #1-22 and a cessation of our Spraberry drilling program.

In the South Midway expansion project, drilling of the first five wells, which included three wells in new pools, commenced in late April 2003. The reserve limits have been extended based on the new well information and the development program will include a total of 30 wells versus the originally planned 20 well program. By the end of the first quarter of 2004, it is anticipated that all thirty wells will be drilled and completed. Peak production for the expansion project is expected to occur in the second quarter of 2004.

A contract has been signed with Ensyn Petroleum International (“Ensyn”), to test their Rapid Thermal Processing (RPT™) technology to upgrade the quality of heavy oil by producing lighter, more valuable crude oil. The process has the potential of supplying heat to generate steam for the cyclic process being used in South Midway. We have the rights to test our crude oil in a 250 barrel per day demonstration plant, which is currently under construction and the test should be completed before the end of the year. The contract also gives us exclusive rights to apply this technology in two prospective foreign countries where heavy oil fields have been proven but not fully developed.

Northwest Lost Hills # 1-22 continues to be suspended until we can identify one or more partners to share the costs of the testing program. Aera and Ivanhoe have elected to temporarily abandon the well, which would permit reentering the well at a later date for testing. Until it is tested, the well’s commercial potential, if any, cannot be determined.

In the Bossier trend, testing of the shallow zones at Creslenn Ranch has begun. We continue our search for farm-out partners in our other Bossier prospects in return for an exploration drilling commitment.

Final approval of our Overall Development Program in Dagang was received in the second quarter 2003. Commencement of activities to implement the development of the Dagang project has begun. At our Zitong project we continue seismic reprocessing activities as part of the first three-year exploration period. These activities and commencement of a new geophysical survey will continue through year-end 2003.

Gas-to-Liquids Activities

Spending on GTL projects for the three-month and six-month periods ended June 30, 2003 was $0.2 million and $0.4 million a decrease of $0.5 million and $0.9 million, respectively, over the amounts spent during the comparable periods in 2002. These decreases are due to the completion of technical and commercial feasibility studies for both the Qatar and Egypt projects.

In May 2003, advanced negotiations with Qatar Petroleum and the Qatari government to construct and operate a major GTL production facility in Qatar terminated without an agreement being reached. During the quarter ended June 30, 2003 we wrote down $3.3 million of our GTL investments for expenditures incurred in connection with these negotiations.

With our master license to use Syntroleum’s proprietary GTL technology, we are currently pursuing several opportunities throughout the world to obtain rights to stranded natural gas deposits to use as feedstock for GTL projects. We have agreed with Syntroleum to cooperate more closely on the identification and development of GTL project opportunities. Certain territorial restrictions to our master license are to be removed, which will enable us to pursue GTL project opportunities worldwide, particularly in China. Syntroleum has also agreed that, in respect of GTL projects in which both companies participate, no additional license fees or royalties will be payable and that Syntroleum will also contribute to any such project the right to manufacture specialty and lubricant products. Both companies have the right to pursue GTL projects independently, but we would be required to pay the normal license fees and royalties in such projects.

In July 2003, we signed an agreement with Repsol-YPF Bolivia S.A. (“Repsol”) and Syntroleum that brings us into a study to build a 90,000-barrel-per-day GTL plant in Bolivia. The commercialization study will include an analysis of alternative plant sites, transportation logistics and screening economics conducted by representatives from Ivanhoe, Repsol and Syntroleum. Upon determination that the project is economically feasible and meets financing requirements, the three parties will enter into discussions regarding a joint-venture agreement prior to undertaking definitive engineering and design work.

Liquidity and Capital Resources:

We continue to achieve progress towards key objectives to improve our liquidity and provide access to capital resources needed to further our short and medium term goals.

As at June 30, 2003 our cash position increased slightly from March 30, 2003 as we drew down $1.0 million in bank financing to fund our development of the southern expansion in South Midway and $0.5 million from a related party to fund our exploration activities in China. In addition, maintaining oil and gas prices at 2003 levels and the benefits realized from the cost reductions initiated in 2002 should continue to generate sufficient cash in the near term to fund our operating activities. To partially protect our cash flow from operations from a significant decline in oil prices, we have hedged approximately half of our current production by entering into a six-month costless collar contract for 500 barrels of oil per day with a ceiling price of $30.45 per barrel and a floor price of $24.00 per barrel.

In June 2003, the $1.0 million unsecured convertible debenture, which had been extended to December 2003, was converted to 2 million of our common shares at $0.50/share thus freeing up cash for capital programs and operations.

In July 2003, we closed a $3.0 million special warrant financing to advance the Company’s operations in California’s San Joaquin Basin and for general working capital purposes. We will continue to take the necessary measures to meet our goals and improve our liquidity including the sale of non-core assets, additional equity financings and loans from related and third parties. However, additional funding will be required to complete future capital programs through a combination of equity, debt, mezzanine financing and joint venture partner participation. We cannot assure you that we will be successful in raising the additional funds necessary or securing joint venture partners to complete our capital programs. If we are unsuccessful, we will have to prioritize our capital programs, which may result in delaying and potentially losing some valuable business opportunities.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

During the quarter ended June 30, 2003 we took steps to mitigate fluctuations in our cash flows as a result of changes in oil prices by entering into a costless collar hedge with a ceiling price of $30.45 per barrel and a floor price of $24.00 per barrel using WTI as the index traded on the NYMEX. The hedge is on the first 500 barrels of oil produced per day for a six-month period starting June 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 1934 Securities Exchange Act. Based upon that evaluation, the CEO and CFO concluded that, as of June 30, 2003, 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 financial reporting or in other factors that could significantly affect its internal controls during the period ended June 30, 2003, nor any significant deficiencies or material weaknesses in such internal controls requiring corrective actions. As a result, no corrective actions were taken.

Part II — Other Information

Item 1. Legal Proceedings:

This item incorporates by reference the information regarding legal proceedings in Note 11 to the consolidated financial statements in Part I of this Form 10-Q.

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

The Annual General Meeting of the shareholders of the Company was held in Vancouver, British Columbia on June 19, 2003.

An election of directors was held with the following individuals being re-elected to the Company’s board of directors:


David R. Martin		(106,308,379 votes for and 176,315 votes withheld)

Robert M. Friedland		(106,308,379 votes for and 176,315 votes withheld)

E. Leon Daniel		(106,308,379 votes for and 176,315 votes withheld)

John A. Carver		(106,308,379 votes for and 176,315 votes withheld)

R. Edward Flood		(106,308,379 votes for and 176,315 votes withheld)

Shun-ichi Shimizu		(106,308,379 votes for and 176,315 votes withheld)

Howard Balloch		(106,308,379 votes for and 176,315 votes withheld)

A resolution on amendments to the Employees’ and Directors’ Equity Incentive Plan (the “Plan”) was voted on by disinterested shareholders of the Company as follows:

	•		to increase the maximum number of common shares, which may be allocated for issuance pursuant to the terms and conditions of the Plan from 15,000,000 to 20,000,000 common shares. (24,834,676 votes for, 4,293,097 votes against and 52,065 votes withheld)

	•		to increase the maximum number of common shares that may be issued, from time to time, to eligible employees and directors of the Company and its affiliates as a discretionary bonus in accordance with the terms of the Share Bonus Plan set out in Part 3 of the Plan from 1,000,000 to 2,000,000 common shares. (24,784,971 votes for, 4,292,802 votes against, 57,065 votes withheld)

The only other matter voted upon at the annual meeting was the re-appointment of Deloitte & Touche LLP as the Company’s independent auditors at a remuneration to be fixed by the Company’s board of directors (106,328,527 votes for and 12,265 votes withheld).

Item 5. Other Information: None

Item 6. Exhibits and Reports on Form 8-K

(a)

Exhibits


EXHIBIT
NUMBER		DESCRIPTION

31.1		Certification by the Chief Executive Officer Relating to Internal Disclosure Controls and Procedures

31.2		Certification by the Chief Financial Officer Relating to Internal Disclosure Controls and Procedures

32.1		Certification by the Chief Executive Officer Relating to a Periodic Report Containing Financial Statements

32.2		Certification by the Chief Financial Officer Relating to a Periodic Report Containing Financial Statements

(b)		Reports on Form 8-K.

		During the quarter ended June 30, 2003, the Company filed a Current Report on Form 8-K dated May 28, 2003 (date of earliest event reported), filed on May 29, 2003, for the purpose of reporting, under Item 5, termination of negotiations with Qatar Petroleum to develop a block in Qatar’s North Field to produce natural gas liquids and GTL products.

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/ John O’Keefe

Name: Title:		John O’Keefe Executive Vice-President and Chief Financial Officer

Dated: August 5, 2003

INDEX TO EXHIBITS


Exhibit
Number		Description

31.1		Certification by the Chief Executive Officer Relating to Internal Disclosure Controls and Procedures

31.2		Certification by the Chief Financial Officer Relating to Internal Disclosure Controls and Procedures

32.1		Certification by the Chief Executive Officer Relating to a Periodic Report Containing Financial Statements

32.2		Certification by the Chief Financial Officer Relating to a Periodic Report Containing Financial Statements

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