IVANHOE ENERGY INC - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - IVANHOE ENERGY INC	c00622exv32w1.htm
EX-31.2 - EXHIBIT 31.2 - IVANHOE ENERGY INC	c00622exv31w2.htm
EX-32.2 - EXHIBIT 32.2 - IVANHOE ENERGY INC	c00622exv32w2.htm
EX-31.1 - EXHIBIT 31.1 - IVANHOE ENERGY INC	c00622exv31w1.htm
EX-10.22 - EXHIBIT 10.22 - IVANHOE ENERGY INC	c00622exv10w22.htm
EX-10.21 - EXHIBIT 10.21 - IVANHOE ENERGY INC	c00622exv10w21.htm
EX-10.24 - EXHIBIT 10.24 - IVANHOE ENERGY INC	c00622exv10w24.htm
EX-10.23 - EXHIBIT 10.23 - IVANHOE ENERGY INC	c00622exv10w23.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2010


o		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 (Address of principal executive office)		V6C 3E1 (zip code)

(604) 688-8323
(registrant’s telephone number, including area code)

No Changes
(Former name, former address and former fiscal year, if changed 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. þ Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes þ No

The number of shares of the registrant’s capital stock outstanding as of May 10, 2010 was 333,840,188 Common Shares, no par value.

TABLE OF CONTENTS


	Page
PART I Financial Information

Item 1. Financial Statements

Unaudited Condensed Consolidated Balance Sheets as at March 31, 2010 and December 31, 2009		3

Unaudited Condensed Consolidated Statements of Operations, Comprehensive Income (Loss) and Accumulated Deficit for the Three-Months Ended March 31, 2010 and 2009		4

Unaudited Condensed Consolidated Statements of Cash Flows for the Three-Months Ended March 31, 2010 and 2009		5

Notes to the Unaudited Condensed Consolidated Financial Statements		6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3. Quantitative and Qualitative Disclosures About Market Risk		36

Item 4. Controls and Procedures		36

PART II Other Information

Item 1. Legal Proceedings		37

Item 1A. Risk Factors		37

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		37

Item 3. Defaults Upon Senior Securities		37

Item 4. Submission of Matters to a Vote of Security Holders		37

Item 5. Other Information		37

Item 6. Exhibits		38

Exhibit 10.21
Exhibit 10.22
Exhibit 10.23
Exhibit 10.24
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

Part I — Financial Information

Item 1 Financial Statements

IVANHOE ENERGY INC.

Consolidated Balance Sheets

(stated in thousands of U.S. Dollars, except share amounts)


	March 31, 2010			December 31, 2009

Assets
Current Assets:
Cash and cash equivalents	$	136,385		$	21,512
Accounts receivable		4,802			5,021
Note receivable		261			225
Prepaid and other current assets		565			771
Restricted cash		2,850			2,850

		144,863			30,379

Oil and gas properties and development costs, net (Note 2)		182,219			158,392
Intangible assets — HTL^TM technology (Note 3)		92,153			92,153
Long term assets		1,183			839

	$	420,418		$	281,763

Liabilities and Shareholders’ Equity
Current Liabilities:
Accounts payable and accrued liabilities	$	11,638		$	10,779
Income tax payable (Note 12)		180			530
Asset retirement obligations (Note 5)		330			753

		12,148			12,062

Long term debt (Note 4)		38,449			36,934
Asset retirement obligations (Note 5)		349			195
Long term obligation (Note 6)		1,900			1,900
Future income tax liability (Note 12)		22,817			22,643

		75,663			73,734


Commitments and contingencies (Note 6)

Going concern and basis of presentation (Note 1)

Shareholders’ Equity:
Share capital, issued 333,752,664 common shares December 31, 2009 282,558,593 common shares		549,075			422,322
Purchase warrants (Note 7)		33,423			19,427
Contributed surplus		18,573			20,029
Convertible note		2,086			2,086
Accumulated deficit		(258,402	)		(255,835	)

		344,755			208,029

	$	420,418		$	281,763

(See accompanying Notes to the Consolidated Financial Statements)

IVANHOE ENERGY INC.

Consolidated Statements of Operations and Comprehensive Loss

(stated in thousands of U.S. Dollars, except per share amounts)


	Three Months
	Ended March 31,
	2010			2009
				(Note 13)
Revenue
Oil revenue	$	5,330		$	5,733
Gain on derivative instruments		—			82
Interest income		19			11

		5,349			5,826

Expenses
Operating costs		2,275			2,701
General and administrative (Note 2)		4,977			5,879
Business and technology development		2,511			2,037
Depletion and depreciation		2,083			5,955
Foreign exchange gain		(4,187	)		(993	)
Interest expense and financing costs		4			177

		7,663			15,756


Loss from continuing operations before income taxes		(2,314	)		(9,930	)


Provision for income taxes
Current		(79	)		(1,645	)
Future		(174	)		—

		(253	)		(1,645	)


Net loss from continuing operations		(2,567	)		(11,575	)

Net loss from discontinued operations (Note 13)		—			(698	)


Net Loss and Comprehensive Loss	$	(2,567	)	$	(12,273	)


Accumulated deficit, beginning of period		(255,835	)		(194,183	)

Accumulated deficit, end of period	$	(258,402	)	$	(206,456	)


Net loss per share
Net loss from continuing operations, basic and diluted	$	(0.01	)	$	(0.04	)
Net income (loss) from discontinued operations, basic and diluted		—			—

Net loss per share, basic and diluted	$	(0.01	)	$	(0.04	)


Weighted average number of Shares (in thousands)
Basic		307,233			279,381

Diluted		307,233			279,381

(See accompanying Notes to the Consolidated Financial Statements)

IVANHOE ENERGY INC.

Unaudited Condensed Consolidated Statements of Cash Flows
(stated in thousands of U.S. Dollars)


	Three Months
	Ended March 31,
	2010			2009

Operating Activities
Net loss	$	(2,567	)	$	(12,273	)
Net loss from discontinued operations		—			698
Items not requiring use of cash:
Depletion and depreciation		2,083			5,955
Stock based compensation		537			450
Unrealized loss on derivative instruments		—			455
Unrealized foreign exchange gain		(4,373	)		(974	)
Future income tax expense		174			—
Other		192			91
Abandonment costs settled (Note 5)		(58	)		—
Changes in non-cash working capital items (Note 11)		18			613

Net cash provided by (used in) operating activities from continuing operations		(3,994	)		(4,985	)
Net cash provided by (used in) operating activities from discontinued operations		—			897

Net cash provided by (used in) operating activities		(3,994	)		(4,088	)

Investing Activities
Capital investments		(25,337	)		(5,209	)
Other		(348	)		28
Changes in non-cash working capital items (Note 11)		880			(611	)

Net cash used in investing activities from continuing operations		(24,805	)		(5,792	)
Net cash provided by (used in) investing activities from discontinued operations		—			(476	)

Net cash provided by (used in) investing activities		(24,805	)		(6,268	)

Financing Activities
Shares issued on private placements, net of share issue costs		136,321			—
Proceeds from exercise of options and warrants		1,636			—
Payments of debt obligations		—			(416	)
Other		—			479
Changes in non-cash working capital items (Note 11)		—			(23	)

Net cash provided by (used in) financing activities from continuing operations		137,957			40
Net cash provided by (used in) financing activities from discontinued operations		—			(554	)

Net cash provided by (used in) financing activities		137,957			(514	)


Foreign Exchange gain on Cash and Cash Equivalents Held in a Foreign Currency		5,715			(31	)


Increase in Cash and Cash Equivalents, for the period		114,873			(10,901	)
Cash and cash equivalents, beginning of period		21,512			39,265

Cash and Cash Equivalents, end of period	$	136,385		$	28,364


Cash and cash equivalents, end of period — continuing operations	$	136,385		$	26,115

Cash and cash equivalents, end of period — discontinued operations	$	—		$	2,249

(See accompanying Notes to the Consolidated Financial Statements)

Notes to the Unaudited Condensed Consolidated Financial Statements
March 31, 2010
(all tabular amounts are expressed in thousands of U.S. dollars except per share amounts)

1. GOING CONCERN AND BASIS OF PRESENTATION

Ivanhoe Energy Inc.’s (the “Company” or “Ivanhoe Energy”) accounting policies are in accordance with accounting principles generally accepted in Canada. These policies are consistent with accounting principles generally accepted in the United States (U.S.), except as outlined in Note 14. These interim condensed consolidated financial statements do not include all disclosures normally provided in annual consolidated financial statements and should be read in conjunction with the Company’s most recent annual consolidated financial statements. 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 Company’s financial statements as at and for the three-month period ended March 31, 2010 have been prepared in accordance with generally accepted accounting principles (GAAP) as applied in Canada for a going concern, which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities in the normal course of operations. The Company incurred a net loss of $2.6 million for the three-month period ended March 31, 2010, and as of March 31, 2010, had an accumulated deficit of $258.4 million. Cash flow consumed in operating activities for the first quarter of 2010 was $4 million. The Company currently anticipates incurring substantial expenditures to further its capital development programs, particularly those related to the development of exploration opportunities in China and Mongolia, the development of an oil sands project in Alberta and the development of a heavy oil field in Ecuador. The Company’s cash flow from operating activities will not be sufficient to both satisfy its current obligations and meet the requirements of these capital investment programs. Completion of these projects by the Company is dependent upon its ability to obtain capital to fund further development of these projects and others in the portfolio and also to meet ongoing obligations. The Company intends to finance its future funding requirements primarily through a combination of strategic private investors and/or public equity markets. Given the expectation of rising interest rates and tighter credit markets, public and/or private debt issuance will be a secondary source of funds. Without access to financing, there is a chance that the Company may not be able to continue as a going concern. These consolidated financial statements do not include any adjustments to the amounts and classification of assets and liabilities that would be necessary should the Company be unable to continue as a going concern.

2. OIL AND GAS PROPERTIES AND DEVELOPMENT COSTS

In July 2009, the Company sold its U.S. operating segment (see Note 13); consequently, the segment historical comparative information has been revised to reflect this sale. Capital assets categorized by segment are as follows:


	As at March 31, 2010
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			Asia			Corporate			Development			Total
Oil and Gas Properties:
Proved	$	—		$	—		$	149,491		$	—		$	—		$	149,491
Unproved		112,343			11,274			15,833			—			—			139,900

		112,343			11,274			165,324			—			—			289,391
Accumulated depletion		—			—			(102,002	)		—			—			(102,002	)
Accumulated provision for impairment		—			—			(16,550	)		—			—			(16,550	)

		112,343			11,274			46,772			—			—			170,839

Development Costs:
Feasibility studies and other deferred costs:
Iraq and Libya — HTL^TM		—			—			—			—			834			834
Egypt — GTL		—			—			—			—			5,054			5,054
Accumulated provision for impairment		—			—			—			—			(5,888	)		(5,888	)
Feedstock test facility		—			—			—			—			11,187			11,187
Accumulated depreciation and impairment		—			—			—			—			(526	)		(526	)

		—			—			—			—			10,661			10,661

Furniture and equipment		24			169			135			1,203			22			1,553
Accumulated depreciation		(8	)		(53	)		(92	)		(670	)		(11	)		(834	)

		16			116			43			533			11			719

	$	112,359		$	11,390		$	46,815		$	533		$	10,672		$	182,219


	As at December 31, 2009
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			Asia			Corporate			Development			Total
Oil and Gas Properties:
Proved	$	—		$	—		$	148,110		$	—		$	—		$	148,110
Unproved		94,431			6,755			14,411			—			—			115,597

		94,431			6,755			162,521			—			—			263,707
Accumulated depletion		—			—			(99,744	)		—			—			(99,744	)
Accumulated provision for impairment		—			—			(16,550	)		—			—			(16,550	)

		94,431			6,755			46,227			—			—			147,413

Development Costs:
Feasibility studies and other deferred costs:
Iraq and Libya — HTL^TM		—			—			—			—			834			834
Egypt — GTL		—			—			—			—			5,054			5,054
Accumulated provision for impairment		—			—			—			—			(5,888	)		(5,888	)
Feedstock test facility		—			—			—			—			10,868			10,868
Accumulated depreciation and impairment		—			—			—			—			(393	)		(393	)

		—			—			—			—			10,475			10,475

Furniture and equipment		24			169			135			968			22			1,318
Accumulated depreciation		(8	)		(53	)		(92	)		(650	)		(11	)		(814	)

		16			116			43			318			11			504

	$	94,447		$	6,871		$	46,270		$	318		$	10,486		$	158,392

Costs as at March 31, 2010 of $139.9 million ($93.4 million at March 31, 2009), related to unproved oil and gas properties, are excluded from costs subject to depletion and depreciation. For the three-month period ended March 31, 2010, general and administrative expenses related directly to oil and gas acquisition, exploration and development activities of $1.1 million ($0.9 million for the first quarter of 2009) were capitalized. For the three-month period, ended March 31, 2010, interest on debt related to oil and gas acquisition activities of $0.6 million ($0.5 million for the same period in 2009) was capitalized.

3. INTANGIBLE ASSETS — HTL^TM TECHNOLOGY

In the 2005 merger with the Ensyn Group, Inc. (“Ensyn”), the Company acquired an exclusive, irrevocable license to deploy, worldwide, the RTP^TM Process for petroleum applications as well as the exclusive right to deploy the RTP^TM Process in all applications other than biomass. The Company’s carrying value of the HTL^TM Technology as at March 31, 2010 is $92.2 million. Since the Company acquired the technology, it has continued to expand its patent coverage to protect innovations to the HTL^TM Technology as they are developed and to significantly extend the Company’s portfolio of HTL^TM intellectual property. The Company is the assignee of three granted patents and currently has five patent applications pending in the U.S. The Company also has multiple patents in other countries. This intangible asset was not amortized and its carrying value was not impaired during the first quarter of 2010.

4. LONG TERM DEBT

Notes payable consisted of the following as at:


	March 31,			December 31,
	2010			2009

Convertible note (4.25% at March 31, 2010) due July 2011	$	39,386		$	38,005
Less:
Unamortized discount		(937	)		(1,071	)

	$	38,449		$	36,934

5. ASSET RETIREMENT OBLIGATIONS

The Company provides for the expected costs required to abandon its oil and gas assets. Historically, this provision has encompassed only the Commercial Demonstration Facility (CDF) and the Feedstock Test Facility (FTF). However, during the first quarter of 2010, these estimates were expanded to include costs attributed to the abandonment of eight delineation wells associated with the Tamarack project that were completed but not abandoned during the first quarter of 2010. The undiscounted value of expected future costs required to settle the Company’s asset retirement obligation are $1.0 million at March 31, 2010. To calculate the present value of these obligations, the Company used inflation rates of 1 to 2% and discounted the expected future costs at credit-adjusted rates of 3.5% and 5.3%, respectively, for Tamarack and the FTF. Expected future costs were derived by estimating current costs and escalating based on expected inflation. Inflation rates applied for Tamarack were 1.8%, whereas future abandonment costs for the FTF are expected to be consistent with current day costs. A reconciliation of the beginning and ending aggregate carrying amount of the Company’s various asset retirement obligations is as follows:


	As at			As at
	March 31,			December 31,
	2010			2009

Carrying balance, beginning of year	$	948		$	1,928
Liabilities incurred		150			185
Liabilities settled		(58	)		(118	)
Liabilities transferred		—			—
Accretion expense		4			79
Revisions in estimated cash flows		(365	)		(1,126	)

Carrying balance, end of period		679			948
Less: current portion		330			753

Carrying balance, end of period	$	349		$	195

6. COMMITMENTS AND CONTINGENCIES

Zitong Block Exploration Commitment

At December 31, 2005, the Company held a 100% working interest in a thirty-year production-sharing contract with China National Petroleum Corporation (“CNPC”) in a contract area, known as the Zitong Block located in the northwestern portion of the Sichuan Basin. In January 2006, the Company farmed-out 10% of its working interest in the Zitong block to Mitsubishi Gas Chemical Company Inc. of Japan (“Mitsubishi”) for $4.0 million.

Under this production-sharing contract, the Company was obligated to conduct a minimum exploration program during the first three years ending December 1, 2005 (“Phase I”). The Company completed Phase I with a drilling shortfall of approximately 700 feet. In December 2007, the Company and Mitsubishi (the “Zitong Partners”) made a decision to enter into the next three-year exploration phase (“Phase II”). The shortfall in Phase I drilling was carried over into Phase II.

By electing to participate in Phase II the Zitong Partners had to relinquish 30%, plus or minus 5%, of the Zitong block acreage and complete a minimum work program involving the acquisition of approximately 200 miles of new seismic lines and approximately 23,700 feet of drilling (including the Phase I shortfall), with total gross remaining estimated minimum expenditures for this program of $ 27.5 million. The Zitong Partners have relinquished 25% of the Block to complete the Phase I relinquishment requirement. The Phase II seismic line acquisition commitment was fulfilled in the Phase I exploration program. Drilling at the first of two locations is planned to commence in the second quarter of 2010, with expected completed drilling, completion and evaluation of both prospects finalized in late 2010. The Zitong Partners must complete the minimum work program by the end of the Phase II period, December 31, 2010, or pay to CNPC the cash equivalent of the deficiency in the work program for that exploration phase. The cash equivalent of the deficiency in the drilling program is defined as the actual average unit cost of the last well drilled multiplied by the footage shortfall. Based on our historical drilling costs, we estimate this deficiency to be $12.5 million at March 31, 2010. Following the completion of Phase II, the Zitong Partners must relinquish all of the remaining property except any areas identified for development and future production.

Nyalga Block Exploration Commitment

The exploration period for the Nyalga Block XVI in Mongolia is for five years in duration and consists of three phases of two years, one year and two years respectively, with the ability to nominate a two-year extension following the first or second phase. The minimum work obligations consist of $2.7 million for the first phase, with the majority of that commitment in the second year of the phase, $1.0 million for the second phase and $2.5 million for the third phase, with the majority of that commitment in the second year of that phase. If, in one year, more than the minimum is expended, the excess can be applied to reduce the minimum expenditure in the next year of that phase. During the initial seismic program, a portion of the block, representing approximately 16% of the total, was declared by the Mongolian government to be an historical site and operations on that portion of the block, the Delgerkhaan area, were suspended. A letter from the Mineral Resources and Petroleum Authority of Mongolia (the “MRPAM”) was received in May 2008 that stated that the obligations under year one of the first phase would be extended for one year from the time the Company is allowed access to the suspended area. To date, access has not been allowed and discussions with MRPAM are still ongoing as to the possibility of entering into this suspended area. As at March 31, 2010, the Company has spent in excess of the commitments for the first phase. The minimum work obligation as at March 31, 2010 is $ 1.9 million.

Long Term Obligation

As part of its acquisition of the HTL^TM Technology license, the Company assumed an obligation to pay $1.9 million in the event, and at such time that, the sale of units incorporating the HTL^TM Technology for petroleum applications reach a total of $100.0 million. This obligation is recorded in the Company’s consolidated balance sheet.

Income Taxes

The Company’s income tax filings are subject to audit by taxation authorities, which may result in the payment of income taxes and/or a decrease in its net operating losses available for carry-forward in the various jurisdictions in which the Company operates. While the Company believes its tax filings do not include uncertain tax positions, except as noted below, the results of potential audits or the effect of changes in tax law cannot be ascertained at this time.

The Company has an uncertain tax position in China related to when its entitlement to take tax deductions associated with development costs commenced. In March 2007, the Company received a preliminary indication from local Chinese tax authorities as to a potential change in the rule under which development costs are deducted from taxable income effective for the 2006 tax year. The Company discussed this matter with Chinese tax authorities and subsequently filed its 2006 tax return for Sunwing’s wholly-owned subsidiary Pan-China Resources Ltd. (“Pan-China”) taking a new filing position in which development costs are capitalized and amortized on a straight line basis over six years starting in the year the development costs are incurred rather than deducted in their entirety in the year incurred. This change resulted in a $50.3 million reduction in tax loss carry-forwards in 2007 with an equivalent increase in the tax basis of development costs available for application against future Chinese income. The Company has received no formal notification of this rule change; however, it will continue to file tax returns under this new approach. To the extent that there is a different interpretation in the timing of the deductibility of development costs, this could potentially result in an increase of $1.1 million to the current tax provision.

The Company has an uncertain tax position related to the calculation of a gain on the consideration received from two farm-out transactions and the designation of whether the taxable gains may be subject to a withholding tax of 10% pursuant to Chinese tax law for income derived by a foreign entity. The Company is waiting for the Chinese tax authorities to reply to its request to validate in writing that its current treatment of such tax position is appropriate. To the extent that the calculation of a gain is interpreted differently and the amounts are subject to withholding tax, there would be an additional current tax provision of approximately $0.7 million.

No amounts have been recorded in the financial statements related to the above mentioned uncertain tax positions as management has determined the likelihood of an unfavorable outcome to the Company to be low.

Other Commitments

From time to time the Company enters into consulting agreements whereby a success fee may be payable if and when a definitive agreement is signed or certain other contractual milestones are met. Under the agreements, the consultant may receive cash, Company shares, stock options or some combination thereof. These fees are not considered to be material in relation to the overall capital costs and funding requirements of the individual projects.

The Company may provide indemnities to third parties, in the ordinary course of business, that are customary in certain commercial transactions such as purchase and sale agreements. The terms of these indemnities will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may need to be paid. The Company’s management is of the opinion that any resulting settlements relating to potential litigation matters or indemnities would not materially affect the financial position of the Company.

Lease Commitments

For the period ended March 31, 2010 the Company expended $0.5 million ($1.2 million for all of 2009) on operating leases relating to the rental of office space, which expire between July 2010 and September 2013. Such leases frequently provide for renewal options and require the Company to pay for utilities, taxes, insurance and maintenance expenses.

As at March 31, 2010, future net minimum payments for operating leases (excluding oil and gas and other mineral leases) were the following:


	Payments Due by Year
	(stated in thousands of U.S. dollars)
	Total		2010		2011		2012		2013		After 2013
Lease commitments		3,193		1,480		1,141		446		126		—

7. SHARE CAPITAL AND WARRANTS

Following is a summary of the changes in shareholder’s equity (excluding accumulated deficit) and stock options outstanding for the three-month period ended March 31, 2010:


													Stock Options
																Wtd. Avg
	Common Shares															Exercise
	Number				Purchase			Contributed			Convertible		Number			Price
	(thousands)		Amount		Warrants			Surplus			Note		(thousands)			Cdn.$
Balance December 31, 2009		282,559	$	422,322	$	19,427		$	20,029		$	2,086		15,013		$	2.27
Shares issued for:
Private placement, net of share issue costs		50,000		122,322		13,999			—			—		—			—
Services		280		799		—			—			—		(280	)	$	2.44
Exercise of options		912		3,623		—			(1,993	)		—		(1,461	)	$	3.01
Exercise of purchase warrants		2		9		(3	)		—			—		—			—
Options:
Granted		—		—		—			—			—		182		$	3.16
Forfeited		—		—		—			—			—		—			—
Cancelled		—		—		—			—			—		—			—
Compensation calculated for stock option grants*		—		—		—			537			—		—			—

Balance March 31, 2010		333,753	$	549,075	$	33,423		$	18,573		$	2,086		13,454		$	2.23


*		- includes stock based compensation charged to continuing operations as well as discontinued operations

As at March 31, 2010, the following purchase warrants were exercisable to purchase common shares of the Company until the expiry date at the price per share as indicated below:


			Purchase Warrants
	Price per						Common					Exercise			Cash
Year of	Special						Shares					Price per			Value on
Issue	Warrant		Issued		Exercisable		Issuable		Value		Expiry Date	Share			Exercise
					(thousands)				($U.S. 000)						($U.S. 000)
2006	U.S. $	2.23		11,400		11,398		11,398		18,802	May 2011	Cdn. $	2.93	(1)		32,883
2009	NA			735		735		735		622	February 2011	Cdn. $	4.05			2,931
2010	Cdn. $	3.00		10,417		10,417		10,417		11,419	February 2011	Cdn. $	3.16			32,411
2010	Cdn. $	3.00		2,083		2,083		2,083		2,580	March 2011	Cdn. $	3.16			6,482

				24,635		24,633		24,633	$	33,423					$	74,707


(1)		Each common share purchase warrant originally entitled the holder to purchase one common share at a price of $2.63 per share until the fifth anniversary date of the closing of the transaction. In September 2006, these warrants were listed on the Toronto Stock Exchange and the exercise price was changed to Cdn.$2.93.

In January 2010, the Company’s Asia subsidiary signed an agreement that granted a private investor an option to acquire 833,334 shares of the subsidiary for Cdn $25 million. The investors right to exercise the option is contingent upon the occurrence of specific trigger events that are specified in the contract, and the share purchase option does not become exercisable, if at all, until the first quarter of 2011. The exercise period runs for a period of one year. Given the specific terms and conditions contained in the contract, Management believes the option has no current value at March 31, 2010.

8. SEGMENT INFORMATION

The Company has four reportable business segments: Oil and Gas — Integrated, Oil and Gas — Conventional, Business and Technology Development and Corporate. In July 2009, the Company sold its U.S. operating segment (see Note 13); consequently, reported segment information has been revised to reflect this sale.

Oil and Gas

Integrated

Projects in this segment have two primary attributes. The first attribute consists of conventional exploration and production activities together with enhanced oil recovery techniques such as steam assisted gravity drainage. The second attribute consists of the deployment of our HTL^TM Technology that will be used to upgrade heavy oil at facilities located in the field to produce lighter, more valuable crude. The Company currently has two such projects currently reported in this segment — a heavy oil project in Alberta and a heavy oil project in Ecuador.

Conventional

The Company explores for, develops and produces crude oil and natural gas in China, and recently acquired an exploration block in Mongolia. In China, the Company’s development and production activities are conducted at the Dagang oil field located in Hebei Province and its exploration activities are conducted on the Zitong block located in Sichuan Province. In Mongolia, the exploration activity is being conducted in Block XVI in the Nyalga Basin. Prior to July 2009, (see Note 13) the Company conducted U.S. exploration, development and production activities primarily in California and Texas.

Business and Technology Development

The Company incurs various costs in the pursuit of projects throughout the world. Such costs incurred prior to signing a memorandum of understanding (“MOU”) or similar agreement, are considered to be business and technology development and are expensed as incurred. Upon executing a MOU to determine the technical and commercial feasibility of a project, including studies for the marketability for the project’s products, the Company assesses whether the feasibility and related costs incurred have potential future value, are likely to lead to a definitive agreement for the exploitation of proved reserves and therefore should be capitalized.

Additionally, the Company incurs costs to develop, enhance and identify improvements in the application of the technologies it owns or licenses. The cost of equipment and facilities acquired, or construction costs for such purposes, are capitalized as development costs and amortized over the expected economic life of the equipment or facilities, commencing with the start up of commercial operations for which the equipment or facilities are intended.

Corporate

The Company’s corporate segment consists of costs associated with the board of directors, executive officers, corporate debt, financings and other corporate activities.

The following tables present the Company’s segment information for the three-month period ended March 31, 2010 and identifiable assets as at March 31, 2010 and December 31, 2009:

Segment Information


	Three Months Ended March 31, 2010
	Oil and Gas											Business and
	Integrated						Conventional					Technology
	Canada			Ecuador			Asia			U.S.		Development			Corporate			Total
Revenue
Oil revenue	$	—		$	—		$	5,330		$	—	$	—		$	—		$	5,330
Interest income		—			—			2			—		—			17			19

		—			—			5,332			—		—			17			5,349

Expenses
Operating costs		—			—			2,275			—		—			—			2,275
General and administrative		414			500			687			—		—			3,376			4,977
Business and technology development		23			2			—			—		2,486			—			2,511
Depletion and depreciation		2			7			2,258			—		(232	)		48			2,083
Foreign exchange loss		(8	)		—			9			—		—			(4,188	)		(4,187	)
Interest expense and financing costs		1			—			—			—		3			—			4

		432			509			5,229			—		2,257			(764	)		7,663


Income (loss) from continuing operations before income taxes		(432	)		(509	)		103			—		(2,257	)		781			(2,314	)


(Provision for) recovery of income taxes
Current		—			—			(78	)		—		—			(1	)		(79	)
Future		—			—			—			—		(174	)		—			(174	)

		—			—			(78	)		—		(174	)		(1	)		(253	)


Net income (loss) from continuing operations		(432	)		(509	)		25			—		(2,431	)		780			(2,567	)
Net loss from discontinued operations		—			—			—			—		—			—			—

Net income (loss) and comprehensive income (loss)	$	(432	)	$	(509	)	$	25		$	—	$	(2,431	)	$	780		$	(2,567	)


Capital Investments	$	17,912		$	4,175		$	2,803		$	—	$	225		$	222		$	25,337


Identifiable Assets:
As at March 31, 2010	$	112,638		$	12,788		$	57,536		$	—	$	102,917		$	134,539		$	420,418


As at December 31, 2009	$	94,594		$	7,597		$	57,528		$	—	$	102,878		$	19,166		$	281,763

Segment Information


	Three Months Ended March 31, 2009
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			Asia			U.S.			Development			Corporate			Total
Revenue
Oil revenue	$	—		$	—		$	5,733		$	—		$	—		$	—		$	5,733
Gain on derivative instruments		—			—			82			—			—			—			82
Interest income		—			—			1			—			—			10			11

		—			—			5,816			—			—			10			5,826

Expenses
Operating costs		—			—			2,701			—			—			—			2,701
General and administrative		138			518			396			—			—			4,827			5,879
Business and technology development		294			—			—			—			1,743			—			2,037
Depletion and depreciation		1			14			5,274			—			629			37			5,955
Foreign exchange loss		1			—			22			—			—			(1,016	)		(993	)
Interest expense and financing costs		—			—			148			—			25			4			177

		434			532			8,541			—			2,397			3,851			15,755


Loss from continuing operations before income taxes		(434	)		(532	)		(2,725	)		—			(2,397	)		(3,841	)		(9,929	)


(Provision for) recovery of income taxes
Current		—			—			(1,636	)		—			—			(9	)		(1,645	)

Future		—			—			—			—			—			—			—

		—			—			(1,636	)		—			—			(9	)		(1,645	)


Net loss from continuing operations		(434	)		(532	)		(4,361	)		—			(2,397	)		(3,851	)		(11,575	)
Net loss from discontinued operations		—			—			—			(698	)		—			—			(698	)

Net loss and comprehensive loss	$	(434	)	$	(532	)	$	(4,361	)	$	(698	)	$	(2,397	)	$	(3,851	)	$	(12,273	)


Capital Investments	$	2,068		$	656		$	1,156		$	55		$	1,274		$	—		$	5,209

9. FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

The accounting classification of each category of financial instruments, and their carrying amounts, are set out below. Carrying amounts approximate fair value except for long-term debt. After taking into account its own credit risk, the Company calculated the fair value of its long-term debt to be $37.3 million as at March 31, 2010.


	As at March 31, 2010
							Financial
			Available-for-				liabilities
	Loans and		sale financial		Held-for-		measured at			Total carrying
	receivables		assets		trading		amortized cost			amount
Financial Assets:
Cash and cash equivalents	$	—	$	—	$	136,385	$	—		$	136,385
Accounts receivable		4,802		—		—		—			4,802
Note receivable		261		—		—		—			261
Restricted cash		—		—		2,850		—			2,850

Financial Liabilities:
Accounts payable and accrued liabilities		—		—		—		(11,638	)		(11,638	)
Long term debt		—		—		—		(38,449	)		(38,449	)
Long term obligation		—		—		—		(1,900	)		(1,900	)

	$	5,063	$	—	$	139,235	$	(51,987	)	$	92,311

Financial Risk Factors

The Company is exposed to a number of different financial risks arising from its normal business operations. These risks include, but are not limited to, exposure to commodity prices, foreign currency exchange rates and interest rates, credit risk and liquidity risk. There have been no significant changes to the Company’s exposure to risks or to management’s objectives, policies and processes to manage risks from those stated in the Company’s 2009 Form 10-K.

10. CAPITAL MANAGEMENT

The Company continues to manage its capital as a going concern by enabling its subsidiaries to capture, develop and operate opportunities from the project portfolio that maximize the value returned to shareholders. There have been no changes in management’s objectives, policies and processes regarding capital management from prior periods.

11. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information for the three-month period ended March 31, 2010:


	Three Months
	Ended March 31,
	2010			2009
Supplemental Cash Flow Information

Cash paid during the period for
Income taxes	$	427		$	—

Interest	$	805		$	1,865


Shares issued for services and capitalized	$	799		$	—


Changes in non-cash working capital items
Operating Activities
Accounts receivable	$	244		$	(658	)
Note receivable		(36	)		—
Prepaid and other current assets		123			(42	)
Accounts payable and accrued liabilities		37			(323	)
Income tax payable		(350	)		1,636

		18			613


Investing Activities
Accounts receivable		(25	)		32
Prepaid and other current assets		83			69
Accounts payable and accrued liabilities		822			(710	)

		880			(611	)


Financing Activities
Accounts payable and accrued liabilities		—			(23	)

	$	898		$	(19	)


	2010		2009
Cash and cash equivalents
Bank accounts	$	7,397	$	28,364
Term deposit		128,988		—

	$	136,385	$	28,364

Cash and cash equivalents at March 31, 2010 and December 31, 2009, are composed of bank balances in checking accounts with excess cash in money market accounts which invest primarily in government securities with less than 90 day original maturities.

12. INCOME TAXES

Prior to the Company selling its U.S. operating segment in July 2009, as further described in Note 13, the Company had future tax assets arising from net operating losses carry-forwards generated by this business segment. These future income tax assets were partially offset by certain future income tax liabilities in the U.S. and by a valuation allowance. As at June 30, 2009, as a result of the sale of the business segment, the Company was no longer able to offset these tax assets and liabilities but was required to present these future income tax assets as “assets from discontinued operations” and a future income tax liability both in the amount of $29.6 million in the accompanying balance sheet. The future income tax assets classified as “Assets from discontinued operations” were ultimately included in the $23.4 million loss on disposition as described in Note 13. Since this time, revisions were made to the future income tax liability based on the Company’s ongoing projections for taxable income and its ability to utilize net operating loss carryforwards to reduce associated future income tax liabilities. Based on these assessments at March 31, 2010, the Company’s future income tax liability is $22.8 million in the accompanying balance sheet.

13. DISCONTINUED OPERATIONS

In June of 2009, management commenced a process to sell all of the Company’s United States’ oil and gas exploration and production operations. On July 17, 2009, the Company completed the sale of its wholly owned subsidiary Ivanhoe Energy (USA) Inc. for a purchase price of $39.2 million. The purchaser acquired all of the Company’s oil and gas exploration and production operations in California and Texas and additional exploration acreage in California. An escrow deposit in the amount of $2.0 million, which has been set aside from the sales proceeds, will be available to the purchaser for a period of one year to satisfy any indemnification obligations of the Company. The Company used approximately $5.2 million of the sales proceeds to repay an outstanding loan to a third party financial institution holding a security interest in the subsidiary company’s assets. The Company applied the balance of the sales proceeds in the ongoing development of its heavy oil projects in Canada and Ecuador and for general corporate purposes.

In conjunction with the disposition of the US assets and the Company’s focus on heavy oil opportunities, the Company has decided to close its support office in Bakersfield, California and transfer its Accounting operations to Calgary, Alberta. This transition will be completed early in the third quarter of 2010. Total costs associated with this closure, including severance and retention payments, are expected to be $0.5 million.

The operating results for this discontinued operation for the periods noted were as follows:


	Three Months
	Ended March 31,
	2010		2009
Revenue
Oil and gas revenue	$	—	$	1,966
Gain (loss) on derivative instruments		—		186
Interest income		—		3

		—		2,155

Expenses
Operating costs		—		1,026
General and administrative		—		68
Depletion and depreciation		—		1,677
Interest expense and financing costs		—		82

		—		2,853


Net Loss		—		(698	)

14. ADDITIONAL DISCLOSURE REQUIRED UNDER U.S. GAAP

The Company’s consolidated financial statements have been prepared in accordance with GAAP as applied in Canada. In the case of the Company, Canadian GAAP conforms in all material respects with U.S. GAAP except for certain matters, the details of which are as follows:

Condensed Consolidated Balance Sheets

The application of U.S. GAAP has the following effects on consolidated balance sheet items as reported under Canadian GAAP:


	As at March 31, 2010										As at December 31, 2009
	Canadian			Increase				U.S.			Canadian			Increase				U.S.
	GAAP			(Decrease)			Notes	GAAP			GAAP			(Decrease)			Notes	GAAP

Assets
Current Assets:
Cash and cash equivalents	$	136,385		$	—			$	136,385		$	21,512		$	—			$	21,512
Accounts receivable		4,802			—				4,802			5,021			—				5,021
Note receivable		261			—				261			225			—				225
Prepaid and other current assets		565			—				565			771			—				771
Restricted cash		2,850			—				2,850			2,850			—				2,850

Total Current Assets		144,863			—				144,863			30,379			—				30,379

Oil and gas properties and development costs, net		182,219			(38,500	)	(i)		164,098			158,392			(38,500	)	(i)		139,346
					21,408		(ii)								20,315		(ii)
					(1,029	)	(iii)								(861	)	(iii)
Intangible assets — technology		92,153			—				92,153			92,153			—				92,153
Long term assets		1,183			—				1,183			839			—				839

Total Assets	$	420,418		$	(18,121	)		$	402,297		$	281,763		$	(19,046	)		$	262,717

Liabilities and Shareholders’ Equity
Current Liabilities:
Accounts payable and accrued liabilities	$	11,638		$	—			$	11,638		$	10,779		$	—			$	10,779
Income tax payable		180			—				180			530			—				530
Derivative instruments		—			22,372		(vi)		22,372			—			8,249		(vi)		8,249
Asset retirement obligation		330			—				330			753			—				753

Total Current Liabilities		12,148			22,372				34,520			12,062			8,249				20,311

Long term debt		38,449			1,057		(iii)		39,472			36,934			1,225		(iii)		38,005
					(34	)	(iii)								(154	)	(iii)

Asset retirement obligations		349			—				349			195			—				195
Long term obligation		1,900			—				1,900			1,900			—				1,900
Future income tax liability		22,817			—				22,817			22,643			—				22,643

Total Liabilities		75,663			23,395				99,058			73,734			9,320				83,054


Shareholders’ Equity:
Share capital		549,075			74,455		(iv)		637,094			422,322			74,455		(iv)		510,784
					(994	)	(v)								(551	)	(v)
					1,358		(vii)								1,358		(vii)
					13,200		(vi)								13,200		(vi)
Purchase warrants		33,423			(33,423	)	(vi)		—			19,427			(19,427	)	(vi)		—
Contributed surplus		18,573			(2,754	)	(v)		12,872			20,029			(3,197	)	(v)		13,885
					(2,947	)	(vi)								(2,947	)	(vi)
Convertible note		2,086			(2,086	)	(iii)		—			2,086			(2,086	)	(iii)		—
Accumulated deficit		(258,402	)		(88,325	)			(346,727	)		(255,835	)		(89,171	)			(345,006	)

Total Shareholders’ Equity		344,755			(41,516	)			303,239			208,029			(28,366	)			179,663

Total Liabilities and Shareholders’ Equity	$	420,418		$	(18,121	)		$	402,297		$	281,763		$	(19,046	)		$	262,717

Oil and Gas Properties and Development Costs

(i) There are certain differences between the full cost method of accounting for oil and gas properties as applied in Canada and as applied in the U.S. The principal difference is in the method of performing ceiling test evaluations under the full cost method of accounting rules. In the ceiling test evaluation for U.S. GAAP purposes, the Company limits, on a country-by-country basis, the capitalized costs of oil and gas properties, net of accumulated depletion, depreciation and amortization and deferred income taxes, to (a) the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus (b) the cost of properties not being amortized (e.g. major development projects) and (c) the lower of cost or fair value of unproved properties included in the costs being amortized less (d) income tax effects related to the difference between the book and tax basis of the properties referred to in (b) and (c) above. If capitalized costs exceed this limit, the excess is charged as a provision for impairment. Unproved properties and major development projects are assessed on a quarterly basis for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to the carrying value of proved oil and gas properties. The Company performed the ceiling test in accordance with U.S. GAAP and determined that for the three-months ended March 31, 2010 no impairment provision was required, nor was an impairment provision required under Canadian GAAP. The cumulative differences in the amount of impairment provisions between U.S. and Canadian GAAP were $38.5 million at March 31, 2010 and December 31, 2009.

(ii) The cumulative differences in the amount of impairment provisions between U.S. and Canadian GAAP resulted in a reduction in accumulated depletion.

(iii) As more fully described in Note 5 of our financial statements and in Item 8 of our 2009 Annual Report filed on Form 10-K, we were required, under Canadian GAAP, to bifurcate the value of a convertible note, allocating a portion to long-term debt and a portion to equity. Under U.S. GAAP, the convertible debt securities are classified in their entirety as debt. Under Canadian GAAP this discount accretion was capitalized. To reconcile to U.S. GAAP the entire $2.1 million recorded in equity is reversed as well as the unamortized discount of $1.1 million and the accreted discount that was capitalized in the amount of $1.0 million. In addition, because the convertible note is not denominated in U.S. currency the remeasurement of the different carrying value for U.S. GAAP results in an increase to net income. The foreign exchange loss of $0.1 million is shown as a separate amount in the U.S. GAAP reconciliation of the Company’s balance sheet shown above and is adjusted to the Foreign Exchange Loss line item in the U.S. GAAP reconciliation of the statement of operations below.

Shareholders’ Equity

(iv) In June 1999, the shareholders approved a reduction of stated capital in respect of the common shares by an amount of $74.5 million being equal to the accumulated deficit as at December 31, 1998. Under U.S. GAAP, a reduction of the accumulated deficit such as this is not recognized except in the case of a quasi reorganization.

(v) Under Canadian GAAP, the Company accounts for all stock options granted to employees and directors since January 1, 2002 using the fair value based method of accounting. Under this method, compensation costs are recognized in the financial statements over the stock options’ vesting period using an option-pricing model for determining the fair value of the stock options at the grant date. Under U.S. GAAP, prior to January 1, 2006 the Company applied Accounting Principles Board (“APB”) Opinion No. 25, as interpreted by the Financial Accounting Standards Board (“FASB”) Interpretation No. 44, in accounting for its stock option plan and did not recognize compensation costs in its financial statements for stock options issued to employees and directors. Beginning January 1, 2006 the Company applied the revision to FASB’s Accounting Standards Codification (“ASC”) Topic 718 “Stock Compensation” (formerly SFAS 123R) which supersedes APB No. 25, “Accounting for Stock Issued to Employees”. The Company elected to implement this statement on a modified prospective basis starting in the first quarter of 2006 whereby the Company began recognizing stock based compensation in its U.S. GAAP results of operations for the unvested portion of awards outstanding as at January 1, 2006 and for all awards granted after January 1, 2006. There are no significant differences between the accounting for stock options under Canadian GAAP and U.S. GAAP subsequent to January 1, 2006.

(vi) The Company accounts for purchase warrants as equity under Canadian GAAP. As more fully described in our financial statements in Item 8 of our 2009 Annual Report filed on Form 10-K, the accounting treatment of warrants under U.S. GAAP reflects the application of ASC Topic 815 “Derivatives and Hedging” (formerly SFAS 133). Under Topic 815, share purchase warrants with an exercise price denominated in a currency other than a company’s functional currency are accounted for as derivative liabilities. Changes in the fair value of the warrants are required to be recognized in the statement of operations each reporting period for U.S. GAAP purposes. At the time that the Company’s share purchase warrants are exercised, the value of the warrants will be reclassified to shareholders’ equity for U.S. GAAP purposes. Under Canadian GAAP, the fair value of the warrants on the issue date is recorded as a reduction to the proceeds from the issuance of common shares, with the offset to the warrant component of equity. The warrants are not revalued to fair value under Canadian GAAP.

(vii) Under U.S. GAAP, the aggregate value attributed to the acquisition of royalty rights during 1999 and 2000 was $1.4 million higher, due to the difference between Canadian and U.S. GAAP in the value ascribed to the shares issued, primarily resulting from differences in the recognition of effective dates of the transactions.

Condensed Consolidated Statements of Operations

The application of U.S. GAAP had the following effects on net income (loss) and net income (loss) per share as reported under Canadian GAAP:


	Three Months Ended March 31, 2010										Three Months Ended March 31, 2009
	Canadian			Increase				U.S.			Canadian			Increase				U.S.
	GAAP			(Decrease)			Notes	GAAP			GAAP			(Decrease)			Notes	GAAP
Revenue
Oil revenue	$	5,330		$	—			$	5,330		$	5,733		$	—			$	5,733
Gain (loss) on derivative instruments		—			(127	)	(vi)		(127	)		82			(2,041	)	(vi)		(1,959	)
Interest income		19			—				19			11			—				11

Total Revenue		5,349			(127	)			5,222			5,826			(2,041	)			3,785


Expenses
Operating costs		2,275			—				2,275			2,701			—				2,701
General and administrative		4,977			—				4,977			5,879							5,879
Business and technology development		2,511			—				2,511			2,037			—				2,037
Depletion and depreciation		2,083			(1,093	)	(ix)		990			5,955			(3,213	)	(ix)		2,742
Foreign exchange (gain) loss		(4,187	)		120		(iii)		(4,067	)		(993	)		(392	)	(iii)		(1,385	)
Interest expense and financing costs		4			—				4			177			—				177
Provision for impairment of intangible asset and development		—			—				—			—			146		(viii)		146

Total Expenses		7,663			(973	)			6,690			15,756			(3,459	)			12,297


Loss from continuing operations before income taxes		(2,314	)		846				(1,468	)		(9,930	)		1,418				(8,512	)

Provision for income taxes
Current		(79	)		—				(79	)		(1,645	)		—				(1,645	)
Future		(174	)		—				(174	)		—			—				—

		(253	)		—				(253	)		(1,645	)		—				(1,645	)


Net loss from continuing operations		(2,567	)		846				(1,721	)		(11,575	)		1,418				(10,157	)
Net income (loss) from discontinued operations		—			—				—			(698	)		1,164		(x)		466

Net Loss and Comprehensive Loss		(2,567	)		846				(1,721	)		(12,273	)		2,582				(9,691	)


Net income (loss) per share
Net Loss from continuing operations, basic and diluted	$	(0.01	)	$	0.00			$	(0.01	)	$	(0.04	)	$	0.01				(0.03	)
Net Income (loss) from discontinued operations, basic and diluted		—			—				—			—			0.00				0.00


Net Loss per share, basic and diluted	$	(0.01	)	$	0.00			$	(0.01	)	$	(0.04	)	$	0.01			$	(0.03	)


Weighted Average Number of shares (in thousands)
Basic and Diluted		307,233							307,233			279,381							279,381

Development Costs

(viii) As more fully described under “Oil and Gas Properties and Development Costs” in Item 8 of our 2009 Annual Report filed on Form 10-K, under Canadian GAAP, feasibility, marketing and related costs incurred prior to executing a definitive agreement are capitalized and are subsequently written down upon determination that a project’s future value has been impaired. Under U.S. GAAP, such costs are considered to be research and development and are expensed as incurred.

Depletion and Depreciation

(ix) As discussed under “Oil and Gas Properties and Development Costs” in this note, there is a difference between U.S. and Canadian GAAP in performing the ceiling test evaluation under the full cost method of the accounting rules. Application of the ceiling test evaluation under U.S. GAAP has resulted in an accumulated net increase in impairment provisions on the Company’s U.S. and China oil and gas properties. This net increase in U.S. GAAP impairment provisions has resulted in lower depletion rates for U.S. GAAP purposes and a reduction in the net loss for the three-months ended March 31, 2010 and 2009.

Discontinued Operations

(x) For the three months ended March 31, 2009, a $1.2 million adjustment related to discontinued operations resulting from depletion differences as more fully described in note (ii).

Condensed Consolidated Statement of Cash Flow

There would be no material difference in cash flow presentation between Canadian and U.S. GAAP for the three-months ended March 31, 2010 and 2009.

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, including those within this Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations, 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 “anticipate”, “could”, “propose”, “should”, “intend”, “seeks to”, “is pursuing”, “expect”, “believe”, “will” and similar expressions may be indicative of forward-looking statements. Although the Company believes that its expectations are based on reasonable assumptions, forward-looking statements involve known and unknown risks and uncertainties that may cause the actual future results, performances or achievements to be materially different from management’s current expectations. These known and unknown risks and uncertainties may include, but are not limited to, the 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 heavy-to-light and gas-to-liquids 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 the Company operates and implementation of its capital investment program. Except as required by law, we undertake no obligation to update publicly or revise any forward-looking statements contained in this report. All subsequent forward-looking statements, whether written or oral, attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

The above items and their possible impact are discussed more fully in the section entitled “Risk Factors” in Item 1A and “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of the Company’s 2009 Annual Report on Form 10-K.

The following should be read in conjunction with the Company’s unaudited condensed consolidated financial statements contained herein, and the audited consolidated financial statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations, contained in the Form 10-K for the year ended December 31, 2009. Any terms used but not defined in the following discussion have the same meaning given to them in the Form 10-K. The unaudited condensed consolidated financial statements in this Quarterly Report filed on Form 10-Q have been prepared in accordance with GAAP in Canada. The impact of significant differences between Canadian GAAP and U.S. GAAP on the unaudited condensed consolidated financial statements is disclosed in Note 14.

Special Note to Canadian Investors

The Company is a registrant under the Securities Exchange Act of 1934 and voluntarily files reports with the U.S. Securities and Exchange Commission (“SEC”) on Form 10-K, Form 10-Q and other forms used by registrants that are U.S. domestic issuers. Therefore, the Company’s reserves estimates and securities regulatory disclosures generally follow SEC requirements. In 2004 and amended in 2008, the Canadian Securities Administrators (“CSA”) adopted National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities (NI 51-101), which prescribes certain standards for the preparation, and disclosure of reserves and related information by Canadian issuers. The Company has been granted certain exemptions from NI 51-101. Please refer to the Special Note to Canadian Investors on page 10 of the 2009 Annual Report on Form 10-K.

THE DISCUSSION AND ANALYSIS OF THE COMPANY’S OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED NET OF WORKING INTEREST AFTER ROYALTIES. ALL TABULAR AMOUNTS ARE EXPRESSED IN THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE AND PRODUCTION DATA INCLUDING REVENUES AND COSTS PER BOE.

As generally used in the oil and gas business and throughout this Form 10-Q, the following terms have the following meanings:


Bbl		= barrel
Bbls/d		= barrels per day
Bopd		= barrels of oil per day
Boe		= barrel of oil equivalent
Boe/d		= barrels of oil equivalent per day
MBbl		= thousand barrels
MBbls/d		= thousand barrels per day
Mboe		= thousands of barrels of oil equivalent
Mboe/d		= thousands of barrels of oil equivalent per day
MMBbl		= million barrels
MMBls/d		= million barrels per day
Mcf		= thousand cubic feet
Mcf/d		= thousand cubic feet per day
MMBtu		= million British thermal units
MMcf		= million cubic feet
MMcf/d		= million cubic feet per day

Oil equivalents compare quantities of oil with quantities of gas or express these different commodities in a common unit. In calculating Bbl equivalents (boe), the generally recognized industry standard is one Bbl is equal to six Mcf. boes may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Electronic copies of the Company’s filings with the SEC and the CSA are available, free of charge, through the Company’s web site (www.ivanhoeenergy.com) or, upon request, by contacting its investor relations department at (403) 817-1108. Alternatively, the SEC and the CSA each maintains a website (www.sec.gov and www.sedar.com) from which the Company’s periodic reports and other public filings with the SEC and the CSA can be obtained.

Ivanhoe Energy’s Business

Ivanhoe Energy is an independent international heavy oil development and production company focused on pursuing long-term growth in its reserve base and production. The Company plans to utilize technologically innovative methods designed to significantly improve recovery of heavy oil resources, including the application of HTL^TM Technology and EOR techniques. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production of oil and gas. Our core operations are currently carried out in China, Mongolia, Canada and Ecuador, with business development opportunities worldwide. In late 2009, the Company, through a wholly owned subsidiary, acquired PanAsian Petroleum Inc., and acquired a production—sharing contract covering the 16,839 square kilometer Block XVI exploration area in the Nyalga basin Mongolia.

The Company’s proprietary, patented heavy oil upgrading technology upgrades the quality of heavy oil and bitumen by producing lighter, more valuable crude oil, along with by-product energy that can be used to generate steam or electricity. The HTL^TM Technology has the potential to substantially improve the economics and transportation of heavy oil. There are significant quantities of heavy oil throughout the world that have not been developed, much of it stranded due to the lack of on-site energy, transportation issues, or poor heavy-light price differentials. In remote parts of the world, the considerable reduction in viscosity of the heavy oil through the HTL^TM process will allow the oil to be transported economically by pipelines. In addition to a dramatic improvement in oil quality, an HTL^TM facility can yield large amounts of surplus energy for production of the steam and electricity used in heavy oil production. The thermal energy from the HTL^TM process would provide heavy oil producers with an alternative to increasingly volatile prices for natural gas that now is widely used to generate steam. Yields of the low-viscosity, upgraded product can be greater than 85% by volume, and high conversion of the heavy residual fraction is achieved. In addition to the liquid upgraded oil product, a small amount of valuable by-product gas is produced, and usable excess heat is generated from the by-product coke.

HTL^TM can virtually eliminate cost exposure to natural gas and diluent, solve the transport challenge, and capture a substantial portion of the heavy to light oil price differential for oil producers. HTL^TM accomplishes this at a much smaller scale and at lower per barrel capital costs compared with established competing technologies, using readily available plant and process components. As HTL^TM facilities are designed for installation near the wellhead, they eliminate the need for diluent and make large, dedicated upgrading facilities unnecessary.

Ivanhoe Energy’s Business Segments

The Company is organized into four business segments: Oil and Gas — Integrated, Oil and Gas — Conventional, Business and Technology Development and Corporate. The narrative that follows provides context on the nature of operations conducted in each of these segments.

Oil and Gas

Integrated

Projects in this segment will have two primary components. The first consists of conventional exploration and production activities together with enhanced oil recovery techniques such as steam assisted gravity drainage. The second component consists of the deployment of the HTL^TM Technology that will be used to upgrade heavy oil at facilities located in the field to produce lighter, more valuable crude. The Company’s two flagship projects currently report in this segment - a heavy oil project in Alberta (Tamarack) and a heavy oil property in Ecuador (Pungarayacu).

Conventional

The Company explores for, develops and produces conventional crude oil and natural gas in China and Mongolia, having divested of its U.S. operations. In China, the Company’s development and production activities are conducted at the Dagang oil field located in Hebei Province and its exploration activities are conducted on the Zitong block located in Sichuan Province. In Mongolia the Company is conducting early phase exploration activities in the Nyalga basin, southeast of the capital Ulaanbaatar. The Company’s California and Texas exploration, development and production activities were sold to Seneca South Midway LLC in July, 2009.

Business and Technology Development

The Company’s technology development activities made major strides in 2009. The Feed Stock Test Facility in San Antonio, Texas, which was commissioned early in 2009, has been further optimized to reduce operating costs and improve yields of upgraded crude. During the first quarter, the Feedstock Test Facility played an instrumental role in the advancement of both the Tamarack and Pungarayacu projects through evaluating the upgrading potential of test samples from these fields. The Business Development area of the segment has also continued to move forward in identifying, evaluating and securing new business development opportunities around the world. Additional opportunities in the Middle East, North and South America are currently being pursued.

Corporate

The Company’s corporate segment consists of costs associated with the board of directors, executive officers, corporate debt, financings and related corporate activities.

Ivanhoe Energy’s Corporate Strategy

Importance of the Heavy Oil Segment of the Oil and Gas Industry

The global oil and gas industry is being impacted by the declining availability of low-cost replacement reserves. This has resulted in volatility in oil markets and marked shifts in the global demand and supply balance. Although there continues to be a great deal of volatility in the price of oil and there is growing interest in renewable sources of energy, we believe that oil will retain a predominant position in the overall global energy mix for the foreseeable future. As a result, sustained demand for oil and oil products, coupled with the natural decline of conventional oil production will lead to increasingly favorable economics for higher-cost sources of hydrocarbon resource, including heavy oil.

Production of conventional heavy oil has been steadily increasing worldwide, led by Canada and Latin America but with significant contributions from most other oil basins, including the Middle East and Asia, as producers struggle to replace declines in light oil reserves. Even without the impact of the large non-conventional heavy oil projects in Canada and Venezuela, world heavy oil production has become increasingly more common.

Heavy oil developments can be segregated into two types: conventional heavy oil that flows to the surface without steam enhancement and non-conventional heavy oil and bitumen. While the Company emphasizes non-conventional heavy oil opportunities, both play an important role in Ivanhoe Energy’s corporate strategy.

With regard to non-conventional heavy oil and bitumen, the increased interest and activity has benefited from various key advances in technology, including improved remote sensing, horizontal drilling, and new thermal techniques. This has enabled producers to more effectively access the extensive, heavy oil resources around the world.

While these newer technologies have generated increased access to heavy oil resources, profitable exploitation requires key challenges to be overcome. These challenges include: 1) the need for significant amounts of steam and electrical energy to separate the oil from other sedimentary material, 2) conventional upgrading facilities which require very large scale, high capital cost facilities, 3) the need for diluent blending to flow the oil once it is delivered into the transportation pipeline, and 4) the volatile heavy versus light oil price differentials that the producer is faced with when the product is delivered to market. These challenges can lead to “distressed” assets, where economics are poor, or to “stranded” assets, where the resource cannot be economically produced and delivered to market.

Ivanhoe’s Value Proposition

The Company’s application of the HTL^TM Technology seeks to address the four key heavy oil development challenges outlined above.

Ivanhoe Energy’s HTL™ Technology involves a partial upgrading process that is designed to operate in facilities as small as 20,000 to 30,000 barrels per day. This is substantially smaller than the minimum economic scale for conventional stand-alone upgraders such as delayed cokers, which typically operate at scales of over 100,000 barrels per day. Although the HTL^TM technology provides an economically advantaged solution for smaller upgrading requirements, it is scalable for use in larger applications as well. The Company’s HTL™ Technology is based on carbon rejection, a tried and tested concept in heavy oil processing. The key advantage of HTL™ is that it is a very fast process, as processing times are typically under a few seconds. In addition, the process does not require hydrogen, catalysts or significant pressure. This results in smaller, less costly facilities than conventional upgrading. The Company’s HTL™ Technology has the added advantage of converting the byproducts from the upgrading process into onsite energy, rather than generating large volumes of low value coke.

The HTL™ process provides four key benefits to the producer:

Virtual elimination of external energy requirements for steam generation and/or power for upstream operations.

	2.		Relatively small minimum economic scale of operations suited for field upgrading and for smaller field developments.

	3.		Elimination of the need for diluent or blend oils for transport.

	4.		Capture of the majority of the heavy versus light oil value differential.

The value added for any given project is driven by the advantages that HTL^TM can bring to a particular opportunity. The more stranded the resource and the fewer monetization alternatives that the resource owner has, the greater the opportunity the Company will have to establish the Ivanhoe Energy value proposition.

Implementation Strategy — Heavy Oil

We are an oil and gas company with a unique heavy oil technology that addresses several major problems confronting the oil and gas industry today. This patented technology provides us with a distinctive competitive advantage. In addition, our staff brings years of heavy oil and international experience to enable us to effectively deploy our competitive advantage by working with partners on stranded heavy oil resources around the world.

The Company’s continuing strategy is as follows:

Build a portfolio of major HTL^TM projects. Continue to deploy the personnel and the financial resources in support of our goal to capture additional opportunities for development projects utilizing the Company’s HTL^TM Technology.

Advance the technology. Additional development work will continue to advance the technology through the first commercial application and beyond.

Enhance the Company’s financial position in anticipation of major projects. Implementation of large projects requires significant capital outlays. The Company is working on various financing plans and establishing the relationships required for the development activities of the future.

Build internal capabilities. During 2009, the Company added two key executives; one to take up the role of President and CEO of its Canadian subsidiary and one to fill the Corporate CFO role, vacated through retirement. In addition, the Company continued to build its internal technical capabilities through the addition of senior subsurface engineering talent as well as senior environmental leadership. These new staff will join existing execution teams as they advance the Company’s first HTL^TM projects. The existing upstream teams consist of a number of experienced heavy oil petroleum engineers and geologists complemented by a core team of geotechnical experts. The Houston-based HTL^TM technology team is built on a number of engineers that have an extensive background in chemical and petroleum refining, project engineering and the development and management of intellectual property. The Company expects to continue filling key positions as its projects advance.

Build the relationships needed for the future. Commercialization of the Company’s technologies demands close alignment with partners, suppliers, host governments and financiers.

Executive Overview of First Quarter 2010 Results

In July 2009 the Company disposed of its U.S. operations and used the proceeds for its ongoing projects. To properly reflect this sale in the Company’s first quarter 2010 financial statements, the results of the U.S. operations have been separately identified in comparative disclosures as “Discontinued Operations.”

The Company’s net operating loss before tax improved by $7.6 million in the first quarter of 2010 to ($2.3) million relative to a net operating loss from continuing operations before tax of ($9.9) million in the first quarter of 2009. Although revenues from continuing operations declined slightly between the comparative periods, the Company benefited from lower operating and general and administrative expenses, lower depletion expense and a more favorable foreign exchange position given the denomination of its current and long-term monetary balances and the strengthening of the Canadian dollar relative to the US. Each of these performance drivers is explained in more depth below.

In the first quarter of 2010, the Company’s total revenues from continuing operations declined $0.4 million when compared to the same period of 2009. Although crude realizations increased nearly $30 per barrel, the company’s working interest share of its China production decreased from 82% in the first quarter of 2009 to 49% in the first quarter of 2010. This decrease reflects the Company having reached a point of recovering its development investments in the Dagang field in September 2009 as required by the governing production contracts.

In absolute terms, field operating costs from the Company’s China operations decreased $1.1 million from the first quarter of 2009 to the first quarter of 2010. This improvement is driven primarily by efficiencies in the number of days required to complete well workovers and is also impacted by a lower working interest share of other operating expenses incurred. These overall improvements were offset by a higher windfall gain levy resulting from higher commodity prices in the first quarter of 2010 relative to the same period in 2009. Windfall levy costs increased $0.7 million in the first quarter of 2010 versus the same period in the prior year.

General and administrative expenses are $0.9 million less overall in the first quarter of 2010 when compared to the first quarter of 2009. In 2009, the Company incurred $2.9 million of legal expenses in defending its position in the Grynberg case (see Item 1 to Part II of this Form 10Q). Legal expenses incurred in the first quarter of 2010 are $0.5 million. This $2.4 million reduction in legal costs is offset by higher staff costs in support of the Company’s growing commitments to its projects in Canada, Ecuador and elsewhere around the world. These employee costs increased $1.4 million in the first quarter of 2010 when compared to the same period in 2009.

Depletion expenses associated with the Company’s China operations decreased $3.0 million between the periods ended March 31, 2010 and the comparable period of 2009. This decrease is attributed to the Company’s lower working interest share of Dagang production in the post cost-recovery operating environment (as described above), as well as lower production rates resulting from the natural decline of the reservoir, offset by increased reserves due to improved recoverability factors.

At March 31, 2010, the Company benefited from an unrealized gain of $4.4 million relative to its monetary assets and liabilities held on the balance sheet. For the quarter ended March 31, 2010, the Company also incurred a realized loss of $0.2 million when compared to the same period in 2009. The $4.2 million net benefit of these foreign exchange effects flowed through to the Company’s income statement.

In terms of financing and investing activities, the Company raised $136.3 million net of issuance costs through its private placement of 50,000,000 Special Warrants that were subscribed to and sold during February and March 2010 at price of Cdn $3.00 per Special Warrant. Each Special Warrant was convertible, for no additional consideration, into one common share and one-quarter of a share purchase warrant of the Company upon the filing of a Canadian prospectus. All of the Special Warrants were converted into common shares during the first quarter of 2010. A substantial portion of this funding will be used to advance the Company’s ongoing projects in Tamarack (Canada) and Pungarayacu (Ecuador) and Sunwing development and exploration opportunities in China and Mongolia. To this end, the Company invested $25.3 million in these and other capital investment programs during the first quarter of 2010.

The following table provides particular key financial data for the comparative periods ended March 31, 2010 and 2009.


	Three months ended
	March 31,
	2010			2009
Oil revenues	$	5,330		$	5,733

Net loss from continuing operations	$	(2,567	)	$	(11,575	)
Net loss from continuing operations per share — basic and diluted	$	(0.01	)	$	(0.04	)

Net loss and comprehensive loss	$	(2,567	)	$	(12,273	)
Net loss per share — basic and diluted	$	(0.01	)	$	(0.04	)

Average production (Boe/d)		804			1,456

Net revenue (loss) from operations per Boe	$	(0.05	)	$	(0.09	)

Cash flow provided by (used in) operating activities from continuing operations	$	(3,994	)	$	(4,985	)

Cash flow provided by (used in) operating activities	$	(3,994	)	$	(4,088	)

Capital investments (continuing operations)	$	(25,337	)	$	(5,209	)

The commentary that follows sets forth certain selected consolidated financial data in more detail for the three-month periods ended March 31, 2010 and 2009:

Financial Results — Change in Net Loss

The following provides an analysis of the changes in net losses for the three-month periods ended March 31, 2010 as compared to the same period in 2009:


				*Favorable*
				*(Unfavorable)*
	2010			*Variances*			2009
Summary of Net Loss by Significant Components:
Cash Items:
Net operating revenues:
Oil Revenues:	$	5,330					$	5,733
Production volumes				$	(2,549	)
Oil prices					2,146
Realized gain (loss) on derivative instruments		—			(537	)		537
Operating costs		(2,275	)		426			(2,701	)

General and administrative, less stock based compensation		(4,460	)		1,055			(5,515	)
Business and technology development, less stock based compensation		(2,492	)		(483	)		(2,009	)
Net interest		19			76			(57	)
Current income tax provision		(79	)		1,566			(1,645	)

Total Cash Variances		(3,957	)		1,700			(5,657	)


Non-Cash Items:
Unrealized gain (loss) on derivative instruments		—			455			(455	)
Foreign Exchange Gain		4,187			3,194			993
Depletion and depreciation		(2,083	)		3,872			(5,955	)
Stock based compensation		(537	)		(87	)		(450	)
Future income tax expense		(174	)		(174	)		—
Discontinued operations (net of tax)		—			698			(698	)
Other		(3	)		48			(51	)

Total Non-Cash Variances		1,390			8,006			(6,616	)


Net Loss	$	(2,567	)	$	9,706		$	(12,273	)

Significant individual variances identified above are further explained in the sections that follow.

Revenues and Operating Costs

China

Production and operating information including production, operating costs and depletion are detailed below on a per barrel of oil equivalent (boe) basis:


	Three Month Periods Ended March 31,
	2010		2009
Net Production:
Boe		72,396		131,078
Boe/day for the period		804		1,456
	Per Boe

Revenue	$	73.63	$	43.74

Field operating costs		18.45		18.95
Windfall Levy		11.20		0.95
Engineering and support costs		1.77		0.71

		31.42		20.61

Net operating revenue		42.21		23.13
Depletion		31.05		40.23

Net revenue (loss) from operations	$	11.16	$	(17.10	)

The following is a comparison of changes in production volumes for the three-month period ended March 31, 2010 compared to the same period in 2009:

Production Volumes


	Three-Month Periods Ended March 31,
	Net Boe’s				Percentage
	2010		2009		Change
China:
Dagang		67,794		128,478		-47	%
Daqing		4,602		2,600		77	%

		72,396		131,078		-45	%

Overall net production volumes at the Dagang field during the three-month period ended March 31, 2010 decreased by 60,684 barrels or 674 barrels per day when compared to the same 2009 period. The main reason for the decrease is that the field reached cost recovery in September 2009, reducing the Company’s revenue working interest from 82% to 49%. The exit rate at March 31, 2010 was 1,270 barrels per day from 35 producing wells compared to 1,840 barrels per day from 37 wells at March 31, 2009. The Company was issued a 2010 production quota of 70,000 tones or approximately 506,000 barrels or 1,387 barrels per day. The Company is taking advantage of this quota situation and is performing certain maintenance workovers that normally would have been delayed. This has resulted in reduced barrels per day rates for the first quarter 2010.

Operating Costs

Operating costs in China, including engineering support costs and Windfall Levy, increased 52% or $10.81 per boe for the three-month period ended March 31, 2010 when compared to the same period in 2009. The majority of the increase relates to an increase in the Windfall Levy as oil prices increased substantially from the three-month period ended March 31, 2009 to 2010. Field operating costs decreased $0.50 per boe in the three-month period ended March 31, 2010 compared to same period in 2009. Road and lease maintenance costs, which are weather related, and decreased well maintenance and workover costs were the main contributing factors to the decrease. These decreases were offset by increases in allocated field office costs as capital activity was slightly reduced from the first quarter 2009 and increased engineering support.

In March 2006, the Ministry of Finance of the Peoples Republic of China (“PRC”) issued the “Administrative Measures on Collection of Windfall Gain Levy on Oil Exploitation Business” (the “Windfall Levy Measures”). According to the Windfall Levy Measures, effective as of March 26, 2006, enterprises exploiting and selling crude oil in the PRC are subject to a windfall gain levy if the monthly weighted average price of crude oil is above $40 per barrel. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the weighted average sales price exceeding $40 per barrel. The cost associated with Windfall Levy has been included in operating costs in our financial statements. With oil prices increasing in the first three-month period ended March 31, 2010 when compared to the same period in 2009, the 2010 Windfall Levy increased $10.25 per boe when compared to 2009.

It is important to note that none of the Company’s Sunwing operations or staff were affected by the earthquake in Sichuan province on April 17, 2010.

General and Administrative

Changes in general and administrative expenses for continuing operations by segment for the three-month period ended March 31, 2010 as compared to the same period for 2009 are as follows:


	Three Months Ended
	2010 vs. 2009
Favorable (Unfavorable) Variances:
Oil Activities
Canada	$	(276	)
Ecuador		18
Asia		(291	)
Corporate		1,451

	$	902

Canada

The $0.3 million increase in expenses is attributed to the growth in efforts to develop the Tamarack project.

Ecuador

The slight decrease in general and administrative expenses reflects a lower allocation of corporate overheads to the Pungarayacu project in the first quarter of 2010 when compared with the first quarter of 2009. This is consistent with the overall drop in corporate administrative costs between the comparative periods of 2010 and 2009.

Asia

General and administrative expenses related to operations in Asia increased $0.3 million for the three-month period ended March 31, 2010 compared to the same period in 2009. The increase results from added payroll costs as additional engineering and geological staff was hired in the last quarter of 2009 and the first three months of 2010 and reduced capitalized overhead in 2010 as allowable recoveries in our China projects was decreased. In addition, corporate costs increased in 2010 as 2009 comparative included a write-down of certain payables related to a prior year’s financing process.

Corporate

General and administrative costs related to Corporate activities decreased $1.5 million for the three-month period ended March 31, 2010 when compared to the same period in 2009. This decrease is largely due to $2.4 million lower legal costs resulting from the absence of fees incurred during the first quarter of 2009 related to the Grynberg case (see Item 1 to Part II of this Form 10Q). This benefit is partially offset by increased costs in the areas of office rents and employee costs ($1.2 million in total) associated with increased project activity.

Business and Technology Development

Business and technology development expenses increased $0.5 million for the three-month period ended March 31, 2010 when compared to the same periods in 2009 mainly as a result of higher operating costs attributed to FTF evaluations of Tamarack and Pungarayacu production samples.

Foreign Exchange

At present, the Company holds monetary assets that are principally in the form of a Canadian dollar term deposit and monetary liabilities that are primarily associated with its Canadian dollar denominated debt obligation. Since the Company prepares its period-end balance sheet on a US dollar functional currency basis, it must translate these balances from Canadian currency to a US dollar equivalent basis at the period-end exchange rate. These translations give rise to unrealized foreign exchange gains or losses depending on whether the Canadian dollar strengthened relative to the US dollar between the comparative balance sheet dates or weakened. Similarly, the Company conducts its operations for each quarterly reporting period in a variety of currencies (US dollar, Canadian dollar and Chinese Renmimbi) but it, nevertheless, reports this settlement activity in US dollars. These operational foreign exchange effects give rise to realized foreign exchange gains or losses depending on the relative strengthening or weakening of foreign currencies relative to the US dollar. At March 31, 2010, the Company benefited from an unrealized gain of $4.4 million relative to its monetary assets and liabilities held on the balance sheet. For the quarter ended March 31, 2010, the Company also incurred a realized loss of $0.2 million when compared to the same period in 2009.

Net Interest

Interest expense decreased $0.2 million for the three-month period ended March 31, 2010 when compared to the same period in 2009 as a result of the retirement of loan obligations associated with our China and US operations during the course of 2009.

Unrealized Gain (Loss) on Derivative Instruments

With the repayment of borrowings that required the Company to hedge a substantial portion of its Dagang production, the Company no longer holds derivative positions. The mark-to-market value of the Company’s derivative position at March 31, 2009 was a $455 thousand loss, offset by a $537 thousand gain for a net first quarter 2009 gain of $82 thousand.

Depletion and Depreciation

Depletion and depreciation decreased $3.5 million for the three-month period ended March 31, 2010 when compared to the same period in 2009. This decrease is attributed to our China operations, as described below, and the absence of $0.5 million of depreciation on the Company’s CDF asset that was retired in 2009.

China

China’s depletion decreased $3.0 million in the three-month period ended March 31, 2010 when compared to the same period in 2009. Reduced net production volumes accounted for $2.3 million of the decrease while a rate decrease of $9.17 per boe accounted for the remaining $0.7 million of decrease. The decrease in the rates from period to period was mainly due to an increase in total estimated proved reserves as at January 1, 2010 at our Dagang project due to reduced decline rates and improved recovery rates.

Provision for/Recovery of Income Taxes

China

Provisions for current income taxes decreased by $1.6 million between the first quarter of 2010 and the same period in 2009. This decrease was driven by a one-time retrospective change in the first quarter of 2009 to the minimum depreciation and amortization periods required by Chinese tax law.

Business and Technology Development

Prior to the Company selling its U.S. operating segment in July 2009, as further described in Note 13 to the accompanying financial statements, the Company had future tax assets arising from net operating losses carry-forwards generated by this business segment. These future income tax assets were partially offset by certain future income tax liabilities in the U.S. and by a valuation allowance. As at June 30, 2009, as a result of the pending sale of the business segment, the Company was no longer able to offset these tax assets and liabilities but was required to present these future income tax assets as “assets from discontinued operations” and a future income tax liability both in the amount of $29.6 million in the June 30, 2009 balance sheet. The future income tax assets classified as “Assets from discontinued operations” were ultimately included in the $23.4 million loss on disposition as described in Note 14. Revisions were made to the future income tax liability during the third and fourth quarters of 2009 and the first quarter of 2010 based on revised projections of taxable income and the Company’s utilization of net operating loss carryforwards. As at March 31, 2010, the Company’s future income tax liability is $22.8 million in the accompanying balance sheet.

Discontinued Operations

In June of 2009, management commenced a process to sell all of the Company’s United States’ oil and gas exploration and production operations. The Company completed the sale for total proceeds of $39.2 million in July 2009. The net proceeds from the sale totaled approximately $33.1 million, after repayment of debt in the amount of $5.2 million and transaction expenses estimated at $1.2 million. The net amount of the loss from discontinued operations for the three-month period ended March 31, 2009 is $0.7 million.

Financial Condition, Liquidity and Capital Resources

Sources and Uses of Cash

The following table sets forth a summary of our cash flows from continuing and discontinued operations for the periods indicated:


	For the Three Months Ended March 31,
	2010			2009
Net cash provided by (used in) operating activities from continuing operations	$	(3,994	)	$	(4,985	)

Net cash provided by (used in) investing activities from continuing operations	$	(24,805	)	$	(5,792	)

Net cash provided by (used in) financing activities from continuing operations	$	137,957		$	40

Net increase in cash and cash equivalents	$	114,873		$	(10,901	)

As reflected in the accompanying unaudited condensed consolidated financial statements, we have losses from operations, negative cash flows from operations and have a substantial accumulated deficit. Historically, we have principally used external sources to fund operations, to fund acquisitions of oil and gas properties and projects, to service long-term liabilities and to develop our technology and major projects. The main source of funds historically has been public and private equity and debt markets. The Company’s cash flow from operating activities will not be sufficient to meet its operating and capital obligations, including the Zitong and Nyalga commitments described in Note 6 to these Unaudited Financial Statements, and as such, the Company intends to finance its operating and capital projects from a combination of strategic investors in its projects and/or public and private debt and equity markets, either at a parent company level or at a project level.

Principal factors that could affect our ability to obtain funds from external sources include:

•

Inability to attract strategic investors to our projects,

•

Volatility in the public debt and private and equity markets,

•

Increases in interest rates or credit spreads, as well as limitations on the availability of credit, that affect our ability to borrow under future potential credit facilities on a secured or unsecured basis, and

•

A decrease in the market price for our common stock.

Operating Activities

Operating activities used $3.2 million in cash for the three-month period ended March 31, 2010 compared to $4.1 million cash consumed during the same period in 2009. The decrease in cash from operating activities for the three-month period ended March 31, 2010 was mainly due to a decrease in operating costs and general and administrative expenses when compared to the same periods in 2009.

Investing Activities

Changes in capital investments by country are detailed below:


	Three-Month Periods Ended
	March 31,
					(Increase)
	2010		2009		Decrease
Oil and Gas Activities
Canada	$	17,912	$	2,068	$	(15,844	)
Ecuador		4,175		656		(3,519	)
Asia		2,803		1,156		(1,647	)
US		—		55		55
Business and Technology Development		225		1,274		1,049
Corporate		222		—		(222	)

	$	25,337	$	5,209	$	(20,128	)

Canada

Capital investments during the three-month period ended March 31, 2010 consisted of seismic and other geophysical costs, environmental work, the drilling of 28 delineation wells and completion spend and capitalized interest.

Ecuador

The increase of investment activities in the first quarter of 2010 is due to the continuation of work to develop Ecuador’s Pungarayacu heavy-oil field using our HTL^TM Technology. Work conducted in the first quarter of 2010 focused primarily on the drilling and completion of our first appraisal well.

Asia

Capital asset expenditures increased $1.6 million in the three-month period ended March 31, 2010 as compared to the same periods in 2009. The increase is attributed to seismic expenditures associated with the Company’s Mongolia project and pre-drilling costs at the Sichuan prospect, slightly offset with reduced development expenditures at our Dagang field.

Business and Technology Development

The decrease in capital spending during the three-month period ending March 31, 2010 when compared to same period in 2009 was due to the timing of costs relating to the construction and delivery of the FTF. Additionally, in 2010 there were modifications to the FTF to provide increased efficiency and enhance the facility’s intellectual property development capabilities.

Corporate

Capital expenditures in the Corporate segment for the first quarter of 2010 are attributed to computer equipment, furniture and leasehold improvements associated with the Company’s headquarters in Calgary, Alberta.

Financing Activities

Financing activities for the three-month period ended March 31, 2010 consisted mainly of the recognition of Cdn $150 million in private placement proceeds associated with the issuance of 50,000,000 special warrants (“Special Warrants”) at Cdn $3.00 per Special Warrant (the “Offering”). Each Special Warrant was convertible into one common share and one-quarter purchase warrant exercisable at Cdn $3.16 per share for one year upon the filing of a Canadian prospectus. The status of the Company’s purchase warrant activity is reported in Note 7.

Outlook for 2010

Our 2010 capital program is progressing and will encompass the following: a) continued advancement of the Tamarack and Pungarayacu heavy oil developments, b) exploration drilling in the Zitong prospect in Sichuan province, China, and c) selected engineering and development costs related to the enhancement of our proprietary HTL^TM oil upgrading technology, and d) minor maintenance in the Dagang oil field, Hebei province China. Management’s plans for financing future funding requirements include the potential for alliances or other arrangements with strategic partners as well as traditional project financing, debt and mezzanine financing or the sale of equity securities.

Discussions with potential strategic partners are focused primarily on national oil companies and other sovereign or government entities from Asian and Middle Eastern countries that have approached the Company and expressed interest in participating in the Company’s heavy oil activities in Ecuador, Canada and around the world. However, no assurances can be given that we will be able to enter into one or more alternative business alliances with other parties or raise additional capital. If we are unable to enter into such business alliances or obtain adequate additional financing, we will be required to curtail our operations, which may include the sale of assets.

In addition to Tamarack and Pungarayacu, the Company will continue to pursue ongoing discussions related to other HTL heavy oil and selected conventional oil opportunities in North and South America, the Middle East and North Africa.

Contractual Obligations

The table below summarizes the contractual obligations that are reflected in the Unaudited Condensed Consolidated Balance Sheet as at March 31, 2010 and/or disclosed in the accompanying Notes:


	Payments Due by Year
	(stated in thousands of U.S. dollars)
	Total		2010		2011		2012		2013		After 2013
Consolidated Balance Sheets:
Long term debt	$	38,449	$	—	$	38,449	$	—	$	—	$	—
Asset retirement obligation		990		330		—		160		—		500
Long term obligation		1,900		—		—		—		1,900		—
Other Commitments:
Interest payable		2,209		1,301		908		—		—		—
Lease commitments		3,193		1,480		1,141		446		126		—
Zitong exploration commitment		24,761		24,761		—		—		—		—
Nyalga exploration commitment		1,926		—		—		—		1,926		—

Total	$	73,428	$	27,872	$	40,498	$	606	$	3,952	$	500

Off Balance Sheet Arrangements

As at March 31, 2010, we did not have any relationships with unconsolidated entities or financial partnerships, such as structured finance or special purpose entities, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. In addition, we do not engage in trading activities involving non-exchange traded contracts. As such, we are not materially exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships. We do not have relationships and transactions with persons or entities that derive benefits from their non-independent relationship with us, or our related parties, except as disclosed herein.

Outstanding Share Data

As at May 10, 2010, there were 333,840,188 common shares of the Company issued and outstanding. Additionally, the Company had 24,633,000 share purchase warrants outstanding and exercisable to purchase 24,633,000 common shares. As at May 10, 2010, there were 14,834,625 incentive stock options outstanding to purchase the Company’s common shares.

Quarterly Financial Data In Accordance With Canadian and U.S. GAAP (Unaudited)


	QUARTER ENDED
	2010			2009												2008
	1st Qtr			4th Qtr			3rd Qtr			2nd Qtr			1st Qtr			4th Qtr			3rd Qtr		2nd Qtr
Total revenue
Canadian GAAP	$	5,349		$	4,999		$	7,991		$	4,844		$	5,824		$	19,525		$	26,159	$	(3,249	)
U.S. GAAP	$	5,222		$	2,263		$	6,826		$	4,280		$	3,783		$	24,920		$	40,800	$	(15,453	)
Net income (loss) from continuing operations:
Canadian GAAP	$	(2,567	)	$	(11,915	)	$	(2,795	)	$	(11,444	)	$	(11,577	)	$	(16,321	)	$	4,822	$	(18,547	)
U.S. GAAP	$	(1,721	)	$	(12,385	)	$	(1,151	)	$	(8,985	)	$	(10,158	)	$	(27,188	)	$	20,206	$	(30,201	)
Net income (loss) from discontinued operations: (net of tax):
Canadian GAAP	$	—		$	—		$	(23,290	)	$	66		$	(697	)	$	2,341		$	5,240	$	(3,184	)
U.S. GAAP	$	—		$	41		$	(689	)	$	1,151		$	466		$	(18,212	)	$	5,618	$	(2,780	)
Net income (loss) per share — continuing operations
Canadian GAAP	$	(0.01	)	$	(0.04	)	$	(0.01	)	$	(0.04	)	$	(0.04	)	$	(0.06	)	$	0.02	$	(0.08	)
U.S. GAAP	$	(0.01	)	$	(0.04	)	$	(0.00	)	$	(0.03	)	$	(0.04	)	$	(0.11	)	$	0.08	$	(0.12	)
Net income (loss) per share — discontinued operations
Canadian GAAP	$	—		$	—		$	(0.09	)	$	0.00		$	(0.00	)		0.01			0.02	$	(0.01	)
U.S. GAAP	$	—		$	—		$	(0.00	)	$	0.00		$	0.01			(0.06	)		0.02	$	(0.01	)

The causes of differences between U.S. and Canadian GAAP for the first quarter 2010 revenue, net income and income per share data presented above are consistent with those presented in Note 14.

Transition to International Financial Reporting Standards (“IFRS”)

In April 2009, the CICA published the exposure draft “Adopting IFRSs in Canada”. The exposure draft proposes to incorporate International Financial Reporting Standards (“IFRS”) into the CICA Accounting Handbook effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. At this date, publicly accountable enterprises will be required to prepare financial statements in accordance with IFRS.

While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policy, which must be addressed. The Company’s IFRS changeover plan is in place and resources have been deployed during the first quarter of 2010 to identify key GAAP differences and analyze the presentation and disclosure impacts of these differences. The Company’s effort in this regard has benefited from the International Accounting Standards Board amendments to International Financial Reporting Standards 1, “First Time Adoption of International Financial Reporting Standards”. These amendments address the retrospective application of IFRS to particular situations and are aimed at ensuring that entities applying IFRS will not face undue cost or effort in the transition process. One such exemption relating to full cost oil and gas accounting, exempts entities using the full cost method from retrospective application of IFRS for oil and gas assets.

During the second quarter of 2010, the Company is applying its learnings during the initial evaluation phase to understand the effects on data systems, internal controls over financial reporting and business activities, such as financing and compensation arrangements. By mid-year, 2010, the Company will also have begun the process of restating current year Canadian GAAP financial statements in an IFRS format. This work will enable the Company to present its first set of IFRS-based financial statements in time for the 2011 initial IFRS filing requirement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

There have been no material changes in our quantitative and qualitative disclosure about market risk from December 31, 2009. Further information presented on market risks can be found in our 2009 Form 10-K included under Item 7A.

Item 4. Controls and Procedures

The Company’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 2010. Based upon this evaluation, management concluded that these controls and procedures were (1) designed to ensure that material information relating to the Company is made known to the Company’s Chief Executive Officer and Chief Financial Officer as appropriate to allow timely decisions regarding disclosure and (2) effective, in that they provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

It should be noted that while the Company’s principal executive officer and principal financial officer believe that the Company’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Company’s disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

During the quarter ended March 31, 2010, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to have a material effect on the Company’s internal control over financial reporting.

Part II — Other Information

Item 1. Legal Proceedings:

The Company was a defendant in a lawsuit filed November 20, 2008 in the U.S. District Court for the District of Colorado by Jack J. Grynberg and three affiliated companies. The suit alleged bribery and other misconduct and challenged the propriety of a contract awarded to the Company’s wholly-owned subsidiary Ivanhoe Energy Ecuador Inc. to develop Ecuador’s Pungarayacu heavy oil field. The plaintiff’s claims were for unspecified damages or ownership of the Company’s interest in the Pungarayacu field. All defendants filed motions to dismiss the lawsuit for lack of jurisdiction. The Court granted Mr. Robert Friedland’s request to sanction Plaintiffs and Plaintiffs’ counsel for their conduct related to bringing the suit by awarding Mr. Friedland fees and costs. The Ivanhoe corporate defendants, including the Company, were awarded their costs in defending the suit. All defendants are now in the process of seeking an award for their attorneys’ fees and costs.

On October 16, 2009, the plaintiffs filed a motion requesting that the Court vacate its judgment and allow discovery on jurisdictional issues on the grounds that plaintiffs had discovered new evidence. The defendants have filed their opposition and the plaintiffs have filed their reply, and the motion is now ready for decision by the Court. The Court has not yet announced a hearing date or indicated when the motion will be resolved. The likelihood of loss or gain resulting from the lawsuit, and the estimated amount of ultimate loss or gain, are not determinable or reasonably estimable at this time.

Item 1A. Risk Factors:

The following risk factor is in addition to those risk factors more fully described in Item 1A. of our 2009 Annual Report on Form 10-K.

The Company’s financial statements have been prepared in accordance with Canadian generally accepted accounting principles applicable to a going concern, which assumes that the Company will continue in operation for the near future and will be able to realize its assets and discharge its liabilities in the normal course of operations. The Company has a history of operating losses and currently anticipates incurring substantial expenditures to further its capital development programs. The Company’s cash flow from operating activities will not be sufficient to both satisfy its current obligations and meet the requirements of its capital investment programs. The continued existence of the Company is dependent upon its ability to obtain capital to meet its obligations, to preserve its interests in current projects and to meet the obligations associated with future projects. The Company intends to finance the future payments required for its capital projects from a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level. Public and private debt and equity markets may not be accessible now or in the near future and, as such, the Company’s ability to obtain financing cannot be predicted with certainty at this time. Without access to financing, the Company may not be able to continue as a going concern.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds:

The information required by Item 701 of Regulation S-K regarding the Company’s January 26, 2010 private placement of Special Warrants has been included in the Company’s Current Report on Form 8-K filed with the SEC on January 29, 2010.

Item 3. Defaults Upon Senior Securities:

None

Item 4. Removed and Reserved

Item 5. Other Information:

None

Item 6. Exhibits


EXHIBIT
NUMBER		DESCRIPTION

	10.21	Special Warrant Indenture dated as of January 26, 2010 among the Company, Macquarie Capital Markets Canada Ltd. and Cibc Mellon Trust Company.

	10.22	Share Purchase Warrant Indenture dated as of January 26, 2010 among the Company, Macquarie Capital Markets Canada Ltd. and Cibc Mellon Trust Company.

	10.23	Special Warrant Indenture dated as of February 25, 2010 among the Company, Macquarie Capital Markets Canada Ltd. and Cibc Mellon Trust Company.

	10.24	Share Purchase Warrant Indenture dated as of February 25, 2010 among the Company, Macquarie Capital Markets Canada Ltd. and Cibc Mellon Trust Company.

	31.1	Certification by the Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.1	Certification by the Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	32.2	Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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/ Gerald D. Schiefelbein Name: Gerald D. Schiefelbein Title: Chief Financial Officer

Dated: May 10, 2010

INDEX TO EXHIBITS


Exhibit
Number		Description

	10.21	Special Warrant Indenture dated as of January 26, 2010 among the Company, Macquarie Capital Markets Canada Ltd. and Cibc Mellon Trust Company.

	10.22	Share Purchase Warrant Indenture dated as of January 26, 2010 among the Company, Macquarie Capital Markets Canada Ltd. and Cibc Mellon Trust Company.

	10.23	Special Warrant Indenture dated as of February 25, 2010 among the Company, Macquarie Capital Markets Canada Ltd. and Cibc Mellon Trust Company.

	10.24	Share Purchase Warrant Indenture dated as of February 25, 2010 among the Company, Macquarie Capital Markets Canada Ltd. and Cibc Mellon Trust Company.

	31.1	Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	31.2	Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

	32.1	Certification by the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

	32.2	Certification by the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

IVANHOE ENERGY INC - FORM 10-Q - May 10, 2010

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