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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

 

	Yukon, Canada (State or other jurisdiction of incorporation or organization)		Not applicable (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 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
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Part II — Other Information
	Item 1. Legal Proceedings: None
	Item 2. Changes in Securities and Use of Proceeds: None
	Item 3. Defaults Upon Senior Securities: None
	Item 4. Submission of Matters To a Vote of Securityholders
	Item 5. Other Information: None
	Item 6. Exhibits and Reports on Form 8-K
Certificate of the CEO and CFO

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TABLE OF CONTENTS

						Page
PART I		Financial Information
Item 1		Financial Statements
		Consolidated Condensed Balance Sheets at June 30, 2002
		(unaudited) and December 31, 2001					3
		Unaudited Consolidated Condensed Statements of Loss and
		Deficit for the Three Month and Six Month Periods Ended June 30,
		2002 and 2001					4
		Unaudited Consolidated Condensed Statements of Cash Flow
		for the Three Month and Six Month Periods Ended June 30,
		2002 and 2001					5
		Notes to the Unaudited Consolidated Condensed Financial
		Statements					6
Item 2		Management's Discussion and Analysis of Financial Condition
		and Results of Operations					8
PART II		Other Information
Item 1		Legal Proceedings					13
Item 2		Changes in Securities and Use of Proceeds					13
Item 3		Defaults Upon Senior Securities					13
Item 4		Submission of Matters To a Vote of Securityholders					13
Item 5		Other Information					13
Item 6		Exhibits and Reports on Form 8-K					13

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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)

		June 30, 2002				December 31, 2001
		(unaudited)				(audited)
Assets
Current Assets
Cash		$	5,632			$	9,697
Accounts receivable			3,245				1,938
Other			228				375
			9,105				12,010
Long Term Assets			462				397
Oil and gas properties, equipment and GTL investments			99,523				91,596
		$	109,090			$	104,003
Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable and accrued liabilities		$	3,171			$	5,974
Convertible debenture			1,000				1,000
			4,171				6,974
Provision for site restoration			180				132
Shareholders’ Equity
Share capital, issued 144,631,000 common shares;
December 31, 2001 139,267,000			130,862				120,392
Deficit			(26,123	)			(23,495	)
			104,739				96,897
		$	109,090			$	104,003

     (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)

		Three Months								Six Months
		Ended June 30,								Ended June 30,
		2002				2001				2002				2001
Revenue
Oil and gas revenue		$	1,981			$	2,278			$	3,644			$	4,433
Interest income			43				138				72				486
			2,024				2,416				3,716				4,919
Expenses
Operating costs			1,012				1,073				1,868				2,015
General and administrative (including Project Identification)			1,401				2,870				2,988				4,841
Depletion and depreciation			718				436				1,488				919
Provision for impairment			—				5,000				—				5,000
			3,131				9,379				6,344				12,775
Net loss			1,107				6,963				2,628				7,856
Deficit, beginning of period			25,016				3,266				23,495				2,373
Deficit, end of period		$	26,123			$	10,229			$	26,123			$	10,229
Net Loss per share		$	0.01			$	0.05			$	0.02			$	0.06
Weighted Average Number of Shares (in thousands)			140,493				127,319				139,979				127,159

(see accompanying notes)

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

		Three Months								Six Months
		Ended June 30,								Ended June 30,
		2002				2001				2002				2001
Operating Activities
Net loss		$	(1,107	)		$	(6,963	)		$	(2,628	)		$	(7,856	)
Items not requiring use of cash
Depletion and depreciation			718				436				1,488				919
Provision for impairment			—				5,000				—				5,000
			(389	)			(1,527	)			(1,140	)			(1,937	)
Changes in non-cash working capital items			(2,252	)			3,455				(2,376	)			3,192
			(2,641	)			1,928				(3,516	)			1,255
Investing Activities
Capital spending			(5,144	)			(13,627	)			(11,832	)			(25,735	)
Proceeds from sale of Daqing project			—				—				1,200				—
			(5,144	)			(13,627	)			(10,632	)			(25,735	)
Financing Activities
Shares issued on private placement			9,964				—				9,964				—
Shares issued on exercise of options			50				41				119				228
			10,014				41				10,083				228
Increase (Decrease) in cash for the period			2,229				(11,658	)			(4,065	)			(24,252	)
Cash, beginning of period			3,403				17,100				9,697				29,694
Cash, end of period		$	5,632			$	5,442			$	5,632			$	5,442
Supplementary Information Regarding Non-Cash Transactions
Investing activities, net assets acquired:
Oil and gas properties		$	—			$	2,978			$	—			$	2,978
Accounts receivable			—				200				—				200
		$	—			$	3,178			$	—			$	3,178
Financing activities, non-cash:
Shares issued as consideration		$	—			$	3,178			$	—			$	3,178
Included in the above are the following:
Interest paid		$	18			$	8			$	35			$	16
Decrease (increase) in non-cash working capital items
Accounts receivable		$	(378	)		$	(9	)		$	(107	)		$	1,595
Other current assets			141				1,073				147				51
Accounts and note payable			(2,015	)			2,391				(2,416	)			1,546
		$	(2,252	)		$	3,455			$	(2,376	)		$	3,192

(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

		As at June 30, 2002								As at December 31, 2001
		Oil and Gas				Shareholders'				Oil and Gas				Shareholders'
		Properties				Equity				Properties				Equity
As reported under Canadian GAAP			$	99,523			$	104,739			$	91,596			$	96,897
	Adjustment to ascribed value of shares issued for royalty interests			1,358				1,358				1,358				1,358
	Impairment provision for China properties			(10,000	)			(10,000	)			(10,000	)			(10,000	)
	Depletion adjustment — China			38				38				—				—
	GTL development costs written off			(6,491	)			(6,491	)			(5,142	)			(5,142	)
U.S. GAAP			$	84,428			$	89,644			$	77,812			$	83,113

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:

		June 30				December 31
		2002				2001
Share capital (including adjustments above)		$	206,675			$	196,205
Deficit (Including adjustments above)			(117,031	)			(113,092	)
		$	89,644			$	83,113

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Consolidated Condensed Statements of Loss and Deficit

		Six Month Periods Ended June 30
		2002								2001
		Net				Net Loss				Net				Net Loss
		Loss				Per Share				Loss				Per Share
As reported under Canadian GAAP		$	2,628			$	0.02			$	7,856			$	0.06
Depletion adjustment — China			(38	)			—				—				—
GTL development costs written off			1,349				0.01				1,960				0.02
U.S. GAAP		$	3,939			$	0.03			$	9,816			$	0.08

		Three Month Periods Ended June 30
		2002								2001
		Net				Net Loss				Net				Net Loss
		Loss				Per Share				Loss				Per Share
As reported under Canadian GAAP		$	1,107			$	0.01			$	6,963			$	0.05
Depletion adjustment — China			(18	)			—				—				—
GTL development costs written off			719				0.01				927				0.01
U.S. GAAP		$	1,808			$	0.02			$	7,890			$	0.06

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

		Six Month Periods Ended June 30:
		2002												2001
		U.S.				China				Total				U.S.				China				Total
Oil and gas revenue		$	2,305			$	1,339			$	3,644			$	2,517			$	1,916			$	4,433
Interest income			72				—				72				486				—				486
			2,377				1,339				3,716				3,003				1,916				4,919
Operating costs			1,170				698				1,868				1,013				1,002				2,015
Depletion and depreciation			897				591				1,488				851				68				919
Provision for impairment															5,000								5,000
			2,067				1,289				3,356				6,864				1,070				7,934
Segmented (income) loss before the following		$	(310	)		$	(50	)			(360	)		$	3,861			$	(846	)			3,015
General and administrative (including Project Identification)											2,988												4,841
Net loss										$	2,628											$	7,856

		Three Month Periods Ended June 30:
		2002												2001
		U.S.				China				Total				U.S.				China				Total
Oil and gas revenue		$	1,273			$	708			$	1,981			$	1,256			$	1,022			$	2,278
Interest income			43				—				43				138								138
			1,316				708				2,024				1,394				1,022				2,416
Operating costs			640				372				1,012				524				549				1,073
Depletion and depreciation			439				279				718				409				27				436
Provision for impairment			—				—								5,000				—				5,000
			1,079				651				1,730				5,933				576				6,509
Segmented (income) loss before the following		$	(237	)		$	(57	)			(294	)		$	4,539			$	(446	)			4,093
General and administrative (including Project Identification)											1,401												2,870
Net loss										$	1,107											$	6,963

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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:

		Common Shares								Stock Options
														Weighted
														Average
		Number								Number				Exercise Price
		(thousands)				Amount				(thousands)				Cdn.$
Balance December 31, 2001			139,267			$	120,392				8,635			$	2.66
Shares issued on private placement			5,000				9,964
Shares issued on exercise of options			163				119				(163	)			1.57
Shares issued for service			201				387
Options granted											1,735				3.12
Options cancelled/forfeited											(162	)			3.15
Balance June 30, 2002			144,631			$	130,862				10,045			$	2.75

		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:

		Six Month Periods Ended June 30,
		2002												2001
		U.S.				China				Total				U.S.				China				Total
Net Production:
BOE			112,208				70,445				182,653				97,100				76,341				173,441
BOE/day during period			620				389				1,009				536				422				958

		Per BOE												Per BOE
Oil and gas revenue		$	20.54			$	19.01			$	19.95			$	25.92			$	25.09			$	25.56
Operating costs			6.61				5.74				6.27				6.85				9.62				8.06
Production taxes			1.23				—				0.76				1.39				—				0.78
Engineering support			2.59				4.17				3.20				2.19				3.51				2.77
			10.43				9.91				10.23				10.43				13.13				11.62
Net Revenue before depletion			10.11				9.10				9.72				15.49				11.97				13.94
Depletion			7.57				8.38				7.88				8.26				0.89				5.02
Net Revenue from operations		$	2.54			$	0.72			$	1.84			$	7.23			$	11.08			$	8.92

General and Administrative Costs

General and administrative costs include project identification costs, which are costs associated with pursuing and investigating new international projects and the cost of investment banking services. General and administrative costs for the first six months of 2002 were $3.0 million, down $1.8 million from the same period in 2001, as a result of a reduction in project identification activities.

Exploration and Development Activities

Spending on exploration and development activities during the first six months of 2002 was $10.5 million, a decrease of $13.3 million over the $23.8 million spent during the same period in 2001. U.S. spending was down $11.3 million in the first six months of 2002, primarily due to a reduction in the drilling program in Spraberry and the completion of our significant acreage acquisition program in the Bossier Trend at the end of 2001. This is partially offset by an increase in spending in California with the drilling of our deep gas well, Northwest Lost Hills #1-22. Spending in China was down $2.0 million for the first six months of 2002 as a result of the pilot test in Dagang being completed in February 2001 and the sale of Daqing in January 2002.

We drilled one well in the Lone Star prospect of the Bossier Trend in the second quarter of 2002 to a total depth of 11,800 feet. To date we have drilled three wells to the Bossier sands, which were tested with disappointing results. We plan to refocus our attention in the future on the shallower Cotton Valley, Travis Peak, Pettet and Rodessa zones some of which had encouraging shows of oil and gas while drilling. These zones are known to be prolific producers in the East Texas area.

The Northwest Hills # 1-22 deep gas well has been drilled to a depth of 20,458 vertical feet through the Phacoides section of the objective Temblor formation. It now appears that the entire formation has been drilled. The well reached the top of the Temblor in mid-April 2002 at approximately 17,000 vertical feet. While drilling through the Temblor, several drilling breaks and natural gas shows have been encountered indicating that the

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well could potentially be completed as a producer. We are now waiting on the recommendations of the Operator as to specific completion and testing operations. Ivanhoe owns a 42% working interest in this well and may plan to seek a partner to fund its share of the costs for completion and testing.

It is anticipated the final analysis of the three wells drilled in Kentucky during 2001 will be completed in the third quarter. A decision will be made at that time whether to further test one or more of the wells, seek farm-out opportunities or to relinquish our interests.

At Dagang, we anticipate final approval of our overall development program in the third quarter. The development program, as submitted, involves drilling 115 new wells and reworking approximately 29 of the 82 existing wells.

We continue our assessment of the Zitong and Yudong blocks within the Sichuan Basin of China, under the joint feasibility studies entered into in 2001 with PetroChina. We anticipate that a petroleum sharing agreement for the Zitong block will be concluded by the end of the third quarter and the Yudong block subsequently. These blocks, located in Sichuan Province approximately 930 miles southwest of Beijing, cover an area of approximately 2.2 million acres.

Gas-to-Liquids Activities

Spending on GTL projects during the first six months of 2002 was $1.3 million, a decrease of $0.6 million over the $1.9 million spent during the comparable period in 2001. This decrease is due to the completion of technical and commercial feasibility studies for both the Qatar and Egypt projects.

Negotiations in Qatar for an agreement to build a 185,000 barrels per day GTL plant and 118,000 barrel per day natural gas liquids (NGL) plant have been ongoing throughout the second quarter and are currently at an advanced and detailed stage. We cannot guarantee, however, that such an agreement will be realized.

In Egypt, we are currently reviewing and analyzing our proposal to the Ministry of Petroleum for a 90,000 barrels per day plant. In Oman, we have made preliminary proposals to the Ministry of Oil and Gas for plant sizes ranging from 45,000 — 90,000 barrels per day.

We continue to work with the Mitsui, Inpex and other companies on a commercialization study to investigate the optimum commercial structure for utilization of GTL and NGL products produced in our planned Qatar project. The study includes an in-depth market analysis in the Asia/Pacific region and the development of a project financing plan utilizing Japanese resources. Additionally, the study will include identifying the role that the Japanese companies can play as purchasers of products, and suppliers of equipment, materials and services.

In June 2002 we amended our Master License Agreement with Syntroleum, which would reschedule payment of a portion of upfront site license fees on specific milestone dates and the balance over the future revenues generated from the Qatar GTL project, when realized.

Also, in June 2002 we signed a letter of intent with Syntroleum to participate in the Syntroleum — U.S. Department of Energy Fuels Project at a cost of $5 million. The goal of the project is to establish GTL diesel and naphtha production from a demonstration plant in such volumes so as to supply adequate quantities to various GTL fuel field trials.

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Our participation in the study allows us sufficient supplies of GTL diesel and naphtha to provide samples to potential buyers as part of our worldwide marketing plan. Additionally, we will have access to the demonstration plant for the purpose of gaining operational experience and training future operations personnel. The DOE project cost is to be reduced by the amount of our $2 million investment in Syntroleum’s Sweetwater project in Australia, in which we have decided not to participate.

Liquidity and Capital Resources:

Our 2002 capital expenditure budget is currently $45.0 million, of which $25.0 million is allocated to our exploration and development activities and an additional $20.0 million is allocated to furthering our GTL activities. Actual exploration and development expenditures in California and Texas will be contingent upon our drilling success at Northwest Lost Hills and Bossier as well as the approval of our overall development program in Dagang and finalizing a petroleum sharing contract in Sichuan. GTL expenditures will be primarily contingent upon the successful outcome of our negotiations in Qatar. We may also elect to sell or farm out part of the participation levels we currently are funding in our E&P and GTL programs or sell assets when opportunities arise.

During the six months ended 2002 we raised $10.0 million through the issuance of common shares. Additional funding will be required to complete our planned 2002 capital program through a combination of equity, debt 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.

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. Although the company believes that its expectations are based on reasonable assumptions, it can give no assurance that its 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, the timing and extent of changes in commodity prices for oil, gas and electricity, competition, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and the potential success of gas-to-liquids technology, the prices of goods and services, the availability of drilling rigs and other support services, legislative and/or California Public Utilities Commission decisions and government regulations.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

There have been no material changes in our market risk exposure during the six months ended June 30, 2002 that would require an update to the disclosure in our Annual Report on Form 10-K, as filed with the SEC in March 2002.

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Part II — Other Information

Item 1.     Legal Proceedings: None

Item 2.     Changes in Securities and Use of Proceeds: None

Item 3.     Defaults Upon Senior Securities: None

Item 4.     Submission of Matters To a Vote of Securityholders

On May 16, 2002 the annual meeting of the shareholders of the Company was held in Vancouver, British Columbia.

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

David R. Martin		(100,850,492 votes for and 54,495 votes withheld)
Robert M. Friedland		(100,850,492 votes for and 54,495 votes withheld)
E. Leon Daniel		(100,850,492 votes for and 54,495 votes withheld)
John A. Carver		(100,850,492 votes for and 54,495 votes withheld)
R. Edward Flood		(100,850,492 votes for and 54,495 votes withheld)
Shun-ichi Shimizu		(100,850,492 votes for and 54,495 votes withheld)
Howard Balloch		(100,850,492 votes for and 54,495 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 remuneration to be fixed by the Company’s board of directors (100,854,193 votes for and 10,669 votes withheld).

Item 5.     Other Information: None

Item 6.     Exhibits and Reports on Form 8-K

(a)      Exhibits

EXHIBIT NUMBER		DESCRIPTION
99.1		Certification by the Chief Executive Officer and Chief Financial Officer
		Relating to a Periodic Report Containing Financial Statements
(b)		Reports on Form 8-K.
		None

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IVANHOE ENERGY INC
By: /s/ John O’Keefe Name: John O’Keefe Title: Executive Vice-President and          Chief Financial Officer
Dated: August 12, 2002

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INDEX TO EXHIBITS

EXHIBIT NUMBER		DESCRIPTION
99.1		Certification by the Chief Executive Officer and Chief Financial Officer

 

 

 

 

 

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