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, 2007
or
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.

Yukon, Canada		98-0372413
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
Suite 654 — 999 Canada Place
Vancouver, British Columbia, Canada		V6C 3E1
(Address of principal executive office)		(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.     Yes þ     No o

Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o

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

The number of shares of the registrant’s capital stock outstanding as of March 31, 2007 was 241,364,188 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, 2007 and December 31, 2006			3
Unaudited Condensed Consolidated Statements of Operations and Accumulated Deficit for the Three-Month Periods Ended March 31, 2007 and 2006			4
Unaudited Condensed Consolidated Statements of Cash Flow for the Three-Month Periods Ended March 31, 2007 and 2006			5
Notes to the Unaudited Condensed Consolidated Financial Statements			6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
Item 3. Quantitative and Qualitative Disclosures About Market Risks			29
Item 4. Controls and Procedures			29
PART II Other Information
Item 1. Legal Proceedings			30
Item 1A. Risk Factors			30
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			30
Item 3. Defaults Upon Senior Securities			30
Item 4. Submission of Matters To a Vote of Security Holders			30
Item 5. Other Information			30
Item 6. Exhibits			30

Part I — Financial Information

Item 1 Financial Statements

IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Balance Sheets
(stated in thousands of U.S. Dollars, except share amounts)

		March 31, 2007				December 31, 2006
Assets
Current Assets
Cash and cash equivalents		$	10,793			$	13,879
Accounts receivable (net of allowance for doubtful accounts of $116 as at March 31, 2007 and December 31, 2006)			6,541				7,435
Prepaid and other current assets			548				773
			17,882				22,087
Oil and gas properties and investments, net			119,379				121,918
Intangible assets — technology			102,153				102,153
Long term assets			2,060				2,386
		$	241,474			$	248,544
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		$	7,915			$	9,428
Notes payable — current portion			2,190				2,147
Asset retirement obligations — current portion			600				—
Derivative instruments			1,159				493
			11,864				12,068
Long term debt			3,673				4,237
Asset retirement obligations			1,396				1,953
Long term obligation			1,900				1,900
Commitments and contingencies
Shareholders’ Equity
Share capital, issued 241,364,188 common shares; December 31, 2006 241,215,798 common shares			319,004				318,725
Purchase warrants			23,955				23,955
Contributed surplus			7,012				6,489
Accumulated deficit			(127,330	)			(120,783	)
			222,641				228,386
		$	241,474			$	248,544

(See accompanying notes)

IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Statements of Operations and Accumulated Deficit
Three-Month Periods Ended March 31
(stated in thousands of U.S. Dollars, except per share amounts)

		2007				2006
Revenue
Oil and gas revenue		$	9,596			$	9,826
Loss on derivative instruments			(459	)			—
Interest income			120				38
			9,257				9,864
Expenses
Operating costs			3,685				2,716
General and administrative			2,872				2,000
Business and technology development			2,162				1,662
Depletion and depreciation			6,892				7,847
Interest expense and financing costs			193				265
Provision for impairment			—				750
			15,804				15,240
Net Loss			(6,547	)			(5,376	)
Accumulated Deficit, beginning of period			(120,783	)			(95,291	)
Accumulated Deficit, end of period		$	(127,330	)		$	(100,667	)
Net Loss per share — Basic and Diluted		$	(0.03	)		$	(0.02	)
Weighted Average Number of Shares (in thousands)			241,231				224,547

(See accompanying notes)

IVANHOE ENERGY INC.
Unaudited Condensed Consolidated Statements of Cash Flow
Three-Month Periods Ended March 31
(stated in thousands of U.S. Dollars)

		2007				2006
Operating Activities
Net loss		$	(6,547	)		$	(5,376	)
Items not requiring use of cash:
Depletion and depreciation			6,892				7,847
Provision for impairment			—				750
Stock based compensation			802				353
Unrealized loss on derivative instruments			666				—
Other			169				98
Changes in non-cash working capital items			612				(1,592	)
			2,594				2,080
Investing Activities
Capital investments			(5,334	)			(4,892	)
Merger and acquisition related costs			—				(177	)
Proceeds from sale of assets			1,000				5,350
Repayment of advance			200				—
Other			75				(9	)
Changes in non-cash working capital items			(1,006	)			(1,085	)
			(5,065	)			(813	)
Financing Activities
Proceeds from exercise of options			—				91
Payments of debt obligations			(615	)			(622	)
			(615	)			(531	)
Increase (decrease) in cash and cash equivalents, for the period			(3,086	)			736
Cash and cash equivalents, beginning of period			13,879				6,724
Cash and cash equivalents, end of period		$	10,793			$	7,460

(See accompanying notes)

Notes to the Condensed Consolidated Financial Statements
March 31, 2007
(all tabular amounts are expressed in thousands of U.S. dollars except per share amounts)
(Unaudited)

1. BASIS OF PRESENTATION

The Company’s accounting policies are in accordance with accounting principles generally accepted in Canada. These policies are consistent with accounting principles generally accepted in the U.S., except as outlined in Note 14. The unaudited condensed consolidated financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2006 consolidated financial statements. 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 most recent annual consolidated financial statements. The December 31, 2006 condensed consolidated balance sheet was derived from the audited consolidated financial statements, but does not include all disclosures required by generally accepted accounting principles (“GAAP”) in Canada and the U.S. 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.

2. CHANGES IN ACCOUNTING POLICIES

2007 Accounting Changes

On January 1, 2007 we adopted six new accounting standards that were issued by the Canadian Institute of Chartered Accountants (“CICA”): Handbook Section 1506 “Accounting Changes” (“S.1506”), Handbook Section 1530 “Comprehensive Income” (“S.1530”), Handbook Section 3251 “Equity” (“S.3251”), Handbook Section 3855 “Financial Instruments — Recognition and Measurement” (“S.3855”), Handbook Section 3861 “Financial Instruments — Disclosure and Presentation” (“S.3861”) and Handbook Section 3865 “Hedges” (“S.3865”). The Company has adopted the new standards on January 1, 2007 with the changes in accounting policies applied prospectively, where applicable. Comparative figures have not been restated.

The objective of S.1506 is to prescribe the criteria for changing accounting policies, together with the accounting treatment and disclosure of changes in accounting policies, changes in accounting estimates and corrections of errors. This Section is intended to enhance the relevance and reliability of an entity’s financial statements and the comparability of those financial statements over time and with the financial statements of other entities. There was no material impact on adoption of this Section.

S.1530 introduces Comprehensive Income, which consists of Net Income and Other Comprehensive Income (“OCI”). OCI represents changes in Shareholder’s Equity during a period arising from transactions and other events with non-owner sources. There was no material impact on adoption of this Section; there is no difference between the Net Loss presented in the accompanying statement of operations and accumulated deficit and our comprehensive loss.

S.3251 establishes standards for the presentation of equity and changes in equity during a reporting period. There was no material impact on adoption of this Section.

S.3855 establishes standards for recognizing and measuring financial assets and financial liabilities and non-financial derivatives as required to be disclosed under S.3861. It requires that financial assets and financial liabilities, including derivatives, be recognized on the balance sheet when the Company becomes a party to the contractual provisions of the financial instrument or non-financial derivative contract. Under this standard, all financial instruments are required to be measured at fair value on initial recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held for trading, available for sale, held to maturity, loans and receivables, or other financial liabilities.

     Financial assets

The Company’s financial assets are comprised of cash and cash equivalents, accounts receivable, other long-term assets and derivative financial instruments. These financial assets are classified as loans and receivables or held for trading financial assets as appropriate. The classification of financial assets is determined at initial recognition. When financial assets are recognized initially, they are measured at fair value, normally being the transaction price. Transaction costs for all financial assets are expensed as incurred.

Financial assets are classified as held for trading if they are acquired for sale in the short term. Cash and cash equivalents and derivatives in a positive fair value position are also classified as held for trading. Held for trading assets are carried on the balance

sheet at fair value with gains or losses recognized in the income statement. The estimated fair value of held for trading assets is determined by reference to quoted market prices and, if not available, on estimates from third-party brokers or dealers.

Loans and receivables are non-derivative financial assets with fixed or determinable payments. Accounts receivable and notes receivable have been classified as loans and receivables. Such assets are carried at amortized cost, as the time value of money is not significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired.

The Company assesses at each balance sheet date whether a financial asset carried at cost is impaired. If there is objective evidence that an impairment loss exists, the amount of the loss is measured as the difference between the carrying amount of the asset and its fair value. The carrying amount of the asset is reduced with the amount of the loss recognized in earnings.

     Financial liabilities

Financial liabilities are classified as financial liabilities initially at fair value; held for trading financial liabilities or other financial liabilities as appropriate. Financial liabilities include accounts payable and accrued liabilities, derivative financial instruments, credit facilities, long term debt and notes payable. The classification of financial liabilities is determined at initial recognition.

Held for trading financial liabilities represent financial contracts that were acquired for sale in the short term or derivatives that are in a negative fair market value position.

The estimated fair value of held for trading liabilities is determined by reference to quoted market prices and, if not available, on estimates from third-party brokers or dealers.

Other financial liabilities are non-derivative financial assets with fixed or determinable payments.

Short term other financial liabilities are carried at cost as the time value of money is not significant. Accounts payable and accrued liabilities, notes payable and credit facilities have been classified as short term other financial liabilities. Gains and losses are recognized in income when the short term other financial liability is derecognized or impaired. Transaction costs for short term other financial liabilities are expensed as incurred.

Long term other financial liabilities are measured at amortized cost. Long-term debt has been classified as long term other financial liabilities. Transaction costs for long term other financial liabilities are deducted from the related liability and accounted for using the effective interest rate method.

     Derivative Financial Instruments

The Company may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows. The Company currently uses a costless collar derivative instrument to manage this exposure.

Derivative financial instruments are classified as held for trading and recorded on the consolidated balance sheet at fair value, either as an asset or as a liability under other current financial assets or other current financial liabilities, respectively. Changes in the fair value of these financial instruments, or unrealized gains and losses, are recognized in the statement of operations, classified in revenues in the period in which they occur.

Gains and losses related to the settlement of derivative contracts, or realized gains and losses, are recognized in the statement of operations, classified in revenues.

Contracts to buy or sell non-financial items that are not in accordance with the Company’s expected purchase, sale or usage requirements are accounted for as derivative financial instruments.

There was no material impact on adoption of Section 3855.

S.3861 establishes standards for presentation of financial instruments and non-financial derivatives, and identifies the information that should be disclosed about them. The presentation aspect of this standard deals with the classification of financial instruments, from the perspective of the issuer, between liabilities and equity, the classification of related interest, dividends, losses and gains, and the circumstances in which financial assets and financial liabilities are offset. The disclosure aspect of this standard deals with information about factors that affect the amount, timing and certainty of an entity’s future cash flows relating to financial instruments. This Section also deals with disclosure of information about the nature and extent of an entity’s use of financial instruments, the business purposes

they serve, the risks associated with them and management’s policies for controlling those risks. There was no material impact on adoption of this Section.

S. 3865 specifies the criteria that must be satisfied in order for hedge accounting to be applied and the accounting for each of the permitted hedging strategies: fair value hedges, cash flow hedges and hedges of foreign currency exposure of net investment in self-sustaining foreign operations. The Company has not elected to designate any financial derivatives as accounting hedges at this time.

Impact of New and Pending Canadian GAAP Accounting Standards

In March 2007, the Emerging Issues Committee issued EIC-164 “Convertible and Other Debt Instruments with Embedded Derivatives”. This abstract deals with the accounting treatment for debt instruments that are convertible at any time at the holder’s option into a fixed number of common shares of the issuer, where the issuer is either required or has the option to satisfy all or part of the obligation in cash. As the Company does not have such instruments outstanding at the present time, this standard will not have an impact on our financial statements.

In September 2006, the Emerging Issues Committee issued EIC-163 “Determining the Variability to be Considered in Applying AcG-15”. As there has been diversity in practice in determining the variability that should be considered in applying AcG-15, this abstract concludes that variability should be based on an analysis of the design of the entity. As the Company does not have interests in such entities at the present time, this standard will not have an impact on our financial statements.

In early 2006, Canada’s Accounting Standards Board ratified a strategic plan that will result in Canadian GAAP, as used by public companies, being converged with International Financial Reporting Standards over a transitional period. The Accounting Standards Board has developed and published a detailed implementation plan with an expected changeover to International Financial Reporting Standards on January 1, 2011. Management is in the process of reviewing the impact of this plan on its financial statements.

In December 2006, the CICA approved Handbook Section 1535 “Capital Disclosures” (“S.1535”), Handbook Section 3862 “Financial Instruments — Disclosures” (“S.3862”), and Handbook Section 3863 “Financial Instruments — Presentation” (“S.3863”). S.1535 establishes standards for disclosing information about an entity’s capital and how it is managed. The objective of S.3862 is to require entities to provide disclosures in their financial statements that enable users to evaluate both the significance of financial instruments for the entity’s financial position and performance; and the nature and extent of risks arising from financial instruments to which the entity is exposed during the period and at the balance sheet date, and how the entity manages those risks. The purpose of S.3863 is to enhance financial statement users’ understanding of the significance of financial instruments to an entity’s financial position, performance and cash flows. These Sections apply to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2007 and the latter two will replace S.3861. Management is in the process of reviewing the requirements of these recent Sections.

3. OIL AND GAS PROPERTIES AND INVESTMENTS

Capital assets categorized by geographical location and business segment are as follows:

		As at March 31, 2007
		Oil and Gas
		U.S.				China				HTL				GTL				Total
Oil and Gas Properties:
Proved		$	104,179			$	106,080			$	—			$	—			$	210,259
Unproved			4,297				12,175				—				—				16,472
			108,476				118,255				—				—				226,731
Accumulated depletion			(22,851	)			(44,095	)			—				—				(66,946	)
Accumulated provision for impairment			(50,350	)			(10,420	)			—				—				(60,770	)
			35,275				63,740				—				—				99,015
HTL and GTL Investments:
Feasibility studies and other deferred costs			—				—				7,319				5,054				12,373
Commercial demonstration facility			—				—				12,121				—				12,121
Accumulated depreciation			—				—				(4,330	)			—				(4,330	)
			—				—				15,110				5,054				20,164
Furniture and equipment			531				114				80				—				725
Accumulated depreciation			(427	)			(60	)			(38	)			—				(525	)
			104				54				42				—				200
		$	35,379			$	63,794			$	15,152			$	5,054			$	119,379

		As at December 31, 2006
		Oil and Gas
		U.S.				China				HTL				GTL				Total
Oil and Gas Properties:
Proved		$	102,884			$	106,171			$	—			$	—			$	209,055
Unproved			5,765				8,279				—				—				14,044
			108,649				114,450				—				—				223,099
Accumulated depletion			(21,249	)			(39,372	)			—				—				(60,621	)
Accumulated provision for impairment			(50,350	)			(10,420	)			—				—				(60,770	)
			37,050				64,658				—				—				101,708
HTL and GTL Investments:
Feasibility studies and other deferred costs			—				—				7,020				5,054				12,074
Commercial demonstration facility			—				—				11,700				—				11,700
Accumulated depreciation			—				—				(3,789	)			—				(3,789	)
			—				—				14,931				5,054				19,985
Furniture and equipment			530				115				80				—				725
Accumulated depreciation			(414	)			(56	)			(30	)			—				(500	)
			116				59				50				—				225
		$	37,166			$	64,717			$	14,981			$	5,054			$	121,918

In the first quarter of 2007, the Company disposed of U.S. oil and gas property interests with proceeds totaling $1.0 million. In the first quarter of 2006, the Company disposed of U.S. oil and gas property interests with proceeds totaling $5.4 million. The sales proceeds were credited to the carrying value of its U.S. oil and gas properties as the sales did not significantly alter the depletion rate for the U.S. cost center.

The Company re-acquired a 40% working interest in the Dagang oil project in February of 2006 (See Note 12). The total purchase price was $28.3 million and has been included in China’s proved properties.

Costs as at March 31, 2007 and December 31, 2006 of $16.5 million and $14.0 million, related to unproved oil and gas properties have been excluded from costs subject to depletion and depreciation. The depletion calculation includes $14.7 million for future development costs associated with proven undeveloped reserves as at March 31, 2007 and December 31, 2006.

4. INTANGIBLE ASSETS — TECHNOLOGY

The Company’s intangible assets consist of the following:

HTL Technology

In the merger with Ensyn Group, Inc. (“Ensyn”), the Company acquired an exclusive, irrevocable license to deploy, worldwide, the patented rapid thermal processing process (“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 RTP^TM Process for heavy oil upgrading (“HTL Technology” or “HTL”) as at March 31, 2007 and December 31, 2006 was $92.2 million.

Syntroleum Master License

The Company owns a master license from Syntroleum Corporation (“Syntroleum”) permitting the Company to use Syntroleum’s proprietary gas-to-liquids (“GTL Technology” or “GTL”) process in an unlimited number of projects around the world. The Company’s master license expires on the later of April 2015 or five years from the effective date of the last site license issued to the Company by Syntroleum. In respect of GTL projects in which both the Company and Syntroleum participate no additional license fees or royalties will be payable by the Company and Syntroleum will contribute, to any such project, the right to manufacture specialty and lubricant products. Both companies have the right to pursue GTL projects independently, but the Company would be required to pay the normal license fees and royalties in such projects. The Company’s carrying value of the Syntroleum GTL master license as at March 31, 2007 and December 31, 2006 was $10.0 million.

These intangible assets were not amortized and their carrying values were not impaired for the three-month periods ended March 31, 2007 and 2006.

5. NOTES PAYABLE

Notes payable consisted of the following as at:

		March 31,				December 31,
		2007				2006
Non-interest bearing promissory note, due 2006 through 2009		$	4,721			$	5,336
Variable rate bank note, 8.36%, due 2008			1,500				1,500
			6,221				6,836
Less:
Unamortized discount			(358	)			(452	)
Current maturities			(2,190	)			(2,147	)
			(2,548	)			(2,599	)
		$	3,673			$	4,237

Promissory Notes

In February 2006, the Company re-acquired the 40% working interest in the Dagang oil project not already owned by the Company. Part of the consideration was the issuance by the Company of a non-interest bearing, unsecured promissory note in the principal amount of approximately $7.4 million ($6.5 million after being discounted to net present value). The note is payable in 36 equal monthly installments commencing March 31, 2006 (See Note 12).

Bank Note

In October 2006 the Company obtained a $15 million Senior Secured Revolving/Term Credit Facility with an initial borrowing base of $8 million from an international bank. The facility is for two years, the first 18 months in the form of a revolver and at the end of 18 months, the then outstanding amount will convert into a six-month amortizing loan. Depending on the drawn amount, interest, at the Company’s option, will be either at 1.75% to 2.25%, above the bank’s base rate or 2.75% to 3.25% over the London Inter-Bank Offered Rate (“LIBOR”). The loan terms include the requirement for the Company to enter into two-year commodity derivative contracts (See Note 10) covering approximately 75% of the Company’s estimated production from its South Midway Property in California and Spraberry Property in West Texas. The facility is secured by a mortgage on both of these properties. To date, the Company has drawn $1.5 million of this facility.

In February 2003, the Company obtained a bank facility for up to $5.0 million to develop the southern expansion of its South Midway field. The bank facility was fully drawn in July 2004 and repayment of the principal and interest commenced in August 2004 with interest at 0.5% above the bank’s prime rate or 3.0% over the LIBOR, at the option of the Company. The principal and interest were repayable, monthly, over a three-year period ending July 2007. The note was secured by all the Company’s rights and interests in the South Midway properties. This note was repaid in advance of its scheduled maturity date from the proceeds of the Company’s new credit facility (see above).

The scheduled maturities of the notes payable, excluding unamortized discount, as at March 31, 2007 were as follows:

2007		$	1,845
2008			3,960
2009			416
		$	6,221

6. ASSET RETIREMENT OBLIGATIONS

The Company provides for the expected costs required to abandon its producing U.S. oil and gas properties and the HTL commercial demonstration facility (“CDF”). The undiscounted amount of expected future cash flows required to settle the Company’s asset retirement obligations for these assets as at March 31, 2007 was estimated at $2.5 million. These payments are expected to be made over the next 40 years with the bulk of the payments 2008 to 2014. To calculate the present value of these obligations, the Company used an inflation rate ranging from 3% to 4% and the expected future cash flows have been discounted using a credit-adjusted risk-free rate ranging from 5% to 7%. The changes in the Company’s liability for the three-month period ended March 31, 2007 were as follows:

Carrying balance, beginning of period		$	1,953
Liabilities incurred			20
Liabilities transferred			(3	)
Accretion expense			26
			1,996
Less: current portion			600
Carrying balance, end of period		$	1,396

7. COMMITMENTS AND CONTINGENCIES

Zitong Block Exploration Commitment

Under the production-sharing contract for the Zitong block, the Company was obligated to conduct a minimum exploration program during the first three years ending December 1, 2005 (“Phase 1”). The Phase 1 work program included acquiring approximately 300 miles of new seismic lines, reprocessing approximately 1,250 miles of existing seismic lines and drilling a minimum of approximately 23,000 feet. The Company completed Phase 1 with the exception of drilling approximately 13,800 feet. The first Phase 1 exploration well drilled in 2005 was suspended, having found no commercial quantities of hydrocarbons. Drilling on the second exploration well commenced in October 2006, but it was not expected to be completed and tested by November 30, 2006, the deadline for completing the Phase 1 exploration program. In September 2006 the Company submitted a letter to PetroChina requesting that a further extension be granted to the Phase 1 exploration program. The Company received a letter of approval from PetroChina for an extension of Phase 1 to September 30, 2007.

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. Mitsubishi has the option to increase its participating interest to 20% by paying $0.4 million plus costs per percentage point prior to any discovery, or $8.0 million plus costs for an additional 10% interest after completion and testing of the first well drilled under the farm-out agreement.

The Company and Mitsubishi (the “Zitong Partners”) will await the results of the second exploration well (see above) after which a decision will be made whether or not to enter into the next three-year exploration phase (“Phase 2”). The $4.0 million advance from Mitsubishi was used to pay for the initial well costs in 2006. If the Company elects not to enter into Phase 2, it will be required to pay China National Petroleum Corporation (“CNPC”), within 30 days after its election, a cash equivalent of its share of the deficiency in the work program estimated to be $0.2 million after the drilling of the second Phase 1 well. If the Company elects not to enter Phase 2, costs related to the Zitong block in the approximate amount of $12.2 million will be required to be included in the depletable base of the China full cost pool. This may result in a ceiling test impairment related to the China full cost pool in a future period.

If the Zitong Partners elect to participate in Phase 2, they must complete a minimum work program involving the acquisition of approximately 200 miles of new seismic lines and approximately 23,000 feet of drilling, with estimated minimum expenditures for the program of $21.6 million. Following the completion of Phase 2, the Zitong Partners must relinquish all of the property except any areas identified for development and production. If the Zitong Partners elect to enter into Phase 2, they must complete the minimum work program or will be obligated to pay to CNPC the cash equivalent of the deficiency in the work program for that exploration phase.

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, the results of potential audits or the effect of changes in tax law cannot be ascertained at this time. The Company received an indication from local Chinese tax authorities as to a change in the rule under which development costs may be deducted in arriving at taxable income, effective for the 2006 tax year. Although the Company has received no formal notification of any rule changes, we have reviewed the potential impact of such anticipated rule changes and reviewed our proposed filings for the 2006 tax year with Chinese tax authorities. The Company’s calculations indicate that there are no taxes payable for the 2006 and 2007 tax years, and the Company has confirmed that this position is acceptable to the tax authorities. The Company will continue its discussions with Chinese tax authorities to finalize its future and ongoing filing positions.

Long Term Obligation

As part of the Ensyn merger, 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 Technology for petroleum applications reach a total of $100.0 million. This obligation was recorded in the Company’s consolidated balance sheet.

Other Commitments

As part of the Ensyn merger, the Company assumed an obligation to advance to a former affiliate of Ensyn (the “Former Ensyn Affiliate”) up to approximately $0.4 million if the Former Ensyn Affiliate cannot meet certain debt servicing ratios required under a Canadian municipal government loan agreement. The principal amount of this loan is repayable in nine equal annual installments commencing April 1, 2006 and ending April 1, 2014. The parent corporation of the Former Ensyn Affiliate has agreed to indemnify the Company for any amounts advanced to the Former Ensyn Affiliate under the loan agreement.

The Company may provide indemnifications, in the course of normal operations, that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications 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 be required to be paid. The Company’s management is of the opinion that any resulting settlements relating to potential litigation matters or indemnifications would not materially affect the financial position of the Company.

8. SHARE CAPITAL

Following is a summary of the changes in share capital and stock options outstanding for the three-month period ended March 31, 2007:

		Common Shares												Stock Options
																		Weighted
																		Average
		Number								Contributed				Number				Exercise Price
		(thousands)				Amount				Surplus				(thousands)				Cdn.$
Balance December 31, 2006			241,216			$	318,725			$	6,489				12,370			$	2.34
Shares issued for:
Services			148				279				—				—				—
Options:
Granted			—				—				—				200			$	2.29
Expired			—				—				—				(283	)		$	3.18
Stock based compensation			—				—				523				—				—
Balance March 31, 2007			241,364			$	319,004			$	7,012				12,287			$	2.32

Purchase Warrants

There were no changes to the number of the Company’s purchase warrants and common shares issuable upon the exercise of the purchase warrants for the three-month period ended March 31, 2007.

As at March 31, 2007, 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
Year of		Special										Shares										Price per
Issue		Warrant		Issued				Exercisable				Issuable				Value				Expiry Date		Share
				(thousands)												($U.S. 000)
2005		Cdn. $3.10			4,100				4,100				4,100			$	2,412			(1)		Cdn. $3.50
2005		Cdn. $3.10			1,000				1,000				1,000				534			July 2007		Cdn. $3.50
2005		U.S. $1.63			11,196				11,196				11,196				1,891			November 2007		U.S. $2.50
2005		n/a			2,000				2,000				2,000				313			November 2007		U.S. $2.00
2006		U.S.$2.23			11,400				11,400				11,400				18,805			May 2011		Cdn. $2.93(2)
					29,696				29,696				29,696			$	23,955

The weighted average exercise price of the exercisable purchase warrants, as at March 31, 2007 was U.S. $2.57 per share.

9. SEGMENT INFORMATION

The Company has three reportable business segments: Oil and Gas, HTL and GTL.

Oil and Gas

The Company explores for, develops and produces crude oil and natural gas in the U.S. and in China. The Company seeks projects requiring relatively low initial capital outlays to which it can apply innovative technology and enhanced recovery techniques in developing them. In the U.S., the Company’s exploration, development and production activities are primarily conducted in California and Texas. In China, the Company’s development and production activities are conducted at the Dagang oil field located in Hebei Province and exploration activities in the Zitong block located in Sichuan Province.

HTL

The Company seeks to increase its oil reserves through the deployment of our HTL Technology. The technology is intended to be used to upgrade heavy oil at facilities located in the field to produce lighter, more valuable crude. In addition, an HTL facility can yield surplus energy for producing steam and electricity used in heavy-oil production. The thermal energy from the RTP^TM Process provides heavy-oil producers with an alternative to natural gas that now is widely used to generate steam.

GTL

The Company holds a master license from Syntroleum to use its proprietary GTL Technology to convert natural gas into synthetic fuels. The master license allows the Company to use Syntroleum’s proprietary process in an unlimited number of GTL projects throughout the world to convert natural gas into an unlimited volume of ultra clean transportation fuels and other synthetic petroleum products.

Corporate

The Company’s corporate office is in Canada with its operational office in the U.S. For this note, any amounts for the corporate office in Canada are included in Corporate.

The following tables present the Company’s interim segment information for the three-month periods ended March 31, 2007 and 2006 and identifiable assets as at March 31, 2007 and December 31, 2006:

		Three-Month Period Ended March 31, 2007
		Oil and Gas
		U.S.				China				HTL				GTL				Corporate				Total
Oil and gas revenue		$	2,711			$	6,885			$	—			$	—			$	—			$	9,596
Loss on derivative instruments			(459	)			—				—				—				—				(459	)
Interest income			22				11				—				—				87				120
			2,274				6,896				—				—				87				9,257
Operating costs			1,202				2,483				—				—				—				3,685
General and administrative			388				407				—				—				2,077				2,872
Business and technology development			—				—				2,017				145				—				2,162
Depletion and depreciation			1,614				4,726				548				3				1				6,892
Interest expense and financing costs			87				5				7				—				94				193
			3,291				7,621				2,572				148				2,172				15,804
Net Loss		$	(1,017	)		$	(725	)		$	(2,572	)		$	(148	)		$	(2,085	)		$	(6,547	)
Capital Investments		$	812			$	3,802			$	720			$	—			$	—			$	5,334
Identifiable Assets (As at March 31, 2007)		$	40,996			$	70,883			$	107,369			$	15,076			$	7,150			$	241,474
Identifiable Assets (As at December 31, 2006)		$	42,158			$	72,970			$	107,186			$	15,081			$	11,149			$	248,544

		Three-Month Period Ended March 31, 2006
		Oil and Gas
		U.S.				China				HTL				GTL				Corporate				Total
Oil and gas revenue		$	2,991			$	6,835			$	—			$	—			$	—			$	9,826
Interest income			14				2				—				—				22				38
			3,005				6,837				—				—				22				9,864
Operating costs			1,204				1,512				—				—				—				2,716
General and administrative			373				345				—				—				1,282				2,000
Business and technology development			—				—				1,310				352				—				1,662
Depletion and depreciation			1,188				5,424				1,231				3				1				7,847
Interest expense and financing costs			62				45				1				—				157				265
Provision for impairment			—				750				—				—				—				750
			2,827				8,076				2,542				355				1,440				15,240
Net Income (Loss)		$	178			$	(1,239	)		$	(2,542	)		$	(355	)		$	(1,418	)		$	(5,376	)
Capital Investments		$	1,274			$	2,717			$	683			$	218			$	—			$	4,892

10. DERIVATIVE INSTRUMENTS

The Company’s results of operations are sensitive mainly to fluctuations in oil and natural gas prices. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows.

The Company entered into a costless collar derivative to hedge its cash flow from the sale of approximately 400-500 barrels of its U.S. oil production per day over a two year period starting November 2006. The derivative had a ceiling price of $65.20 per barrel and a floor price of $63.20 per barrel using WTI as the index traded on the NYMEX. For the three-month period ended March 31, 2007, the Company had realized gains of $0.2 million on this derivative transaction, offsetting $0.7 million of unrealized losses. Both realized and unrealized gains and losses on derivatives have been recognized in the results of operations.

For the three-month period ended March 31, 2006 the Company had no derivative activities.

11. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information for the three-month periods ended March 31:

		2007				2006
Cash paid during the period for:
Income taxes		$	5			$	6
Interest		$	34			$	171
Investing and Financing activities, non-cash:
Acquisition of oil and gas assets
Shares issued		$	—			$	20,000
Debt issued			—				6,547
Receivable applied to acquisition			—				1,746
		$	—			$	28,293
Changes in non-cash working capital items
Operating Activities:
Accounts receivable		$	1,009			$	(1,021	)
Prepaid and other current assets			175				(254	)
Accounts payable and accrued liabilities			(572	)			(317	)
			612				(1,592	)
Investing Activities
Accounts receivable			(115	)			2,076
Prepaid and other current assets			50				(15	)
Accounts payable and accrued liabilities			(941	)			(3,146	)
			(1,006	)			(1,085	)
		$	(394	)		$	(2,677	)

12. MERGER AND ACQUISITIONS

The January 2004 Dagang field farm-out agreement between the Company and Richfirst Holdings Limited (“Richfirst”), provided Richfirst with the right to exchange its working interest in the Dagang field for common shares of the Company at any time prior to eighteen months after the closing of the farm-out transaction contemplated by the agreement. Richfirst elected to exchange its 40% working interest in the Dagang field and, in February 2006, the Company re-acquired Richfirst’s 40% working interest for total consideration of $28.3 million consisting of $20.0 million paid by way of the issuance to Richfirst of 8,591,434 common shares of the Company, a non-interest bearing, unsecured promissory note in the principal amount approximately $7.4 million ($6.5 million after being discounted to net present value) and the forgiveness of $1.8 million of unpaid joint venture receivables. The promissory note is payable in 36 equal monthly installments commencing March 31, 2006. The Company has the right, during the three-year loan repayment period, to require Richfirst to convert the remaining unpaid balance of the promissory note into common shares of Sunwing Energy Ltd (“Sunwing”), the Company’s wholly-owned subsidiary, or another company owning all of the outstanding shares of Sunwing, subject to Sunwing or the other company having obtained a listing of its common shares on a prescribed stock exchange. The number of shares issued would be determined by dividing the then outstanding principal balance under the promissory note by the issue price of shares of the newly listed company issued in the transaction that results in the listing, less a 10% discount.

13. SUBSEQUENT EVENTS

The Company and INPEX Corporation (“INPEX”), Japan’s largest oil and gas exploration and production company, have signed an agreement to jointly pursue the opportunity to develop a heavy oil field in Iraq that Ivanhoe believes is a suitable candidate for its patented HTL heavy oil upgrading technology.

In late 2004, the Company signed a memorandum of understanding with the Iraqi Ministry of Oil to evaluate a specific, large heavy oil field and its commercial development potential using Ivanhoe Energy’s HTL Technology. Since that time, the Company has carried out a detailed analysis and has generated data regarding the applicability of its HTL upgrading technology for the development of the field. The necessary approval by the Iraqi Ministry of Oil for INPEX’s participation has been received.

The agreement requires a payment of $9.0 million by INPEX to Ivanhoe Energy towards Ivanhoe’s past costs related to the project and provides INPEX with a 45% interest in the venture, with Ivanhoe Energy retaining a 55% majority interest. Both parties will participate in the pursuit of the opportunity but Ivanhoe shall lead the discussions. Should the Company and INPEX proceed with the development and deploy Ivanhoe Energy’s HTL Technology, certain technology fees would be payable to the Company.

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

     Shareholders’ Equity and Oil and Gas Properties and Investments

		As at March 31, 2007
										Shareholders’ Equity
		Oil and Gas								Share
		Properties and				Derivative				Capital and				Contributed				Accumulated
		Investments				Instruments				Warrants				Surplus				Deficit				Total
Canadian GAAP		$	119,379			$	1,159			$	342,959			$	7,012			$	(127,330	)		$	222,641
Adjustments for:
Reduction in stated capital (i)			—				—				74,455				—				(74,455	)			—
Accounting for stock based compensation (ii)			—				—				(387	)			(3,361	)			3,748				—
Ascribed value of shares issued for U.S. royalty interests, net (iv)			1,358				—				1,358				—				—				1,358
Fair value adjustment of derivative instruments (iii)			—				8,570				(8,552	)			—				(18	)			(8,570	)
Provision for impairment (v)			(26,270	)			—				—				—				(26,270	)			(26,270	)
Depletion adjustments due to differences in provision for impairment (vi)			5,705				—				—				—				5,705				5,705
HTL and GTL development costs expensed (vii)			(11,669	)			—				—				—				(11,669	)			(11,669	)
U.S. GAAP		$	88,503			$	9,729			$	409,833			$	3,651			$	(230,289	)		$	183,195

		As at December 31, 2006
										Shareholders' Equity
		Oil and Gas								Share
		Properties and				Derivative				Capital and				Contributed				Accumulated
		Investments				Instruments				Warrants				Surplus				Deficit				Total
Canadian GAAP		$	121,918			$	493			$	342,680			$	6,489			$	(120,783	)		$	228,386
Adjustments for:
Reduction in stated capital (i)			—				—				74,455				—				(74,455	)			—
Accounting for stock based compensation (ii)			—				—				(387	)			(3,361	)			3,748				—
Ascribed value of shares issued for U.S. royalty interests, net (iv)			1,358				—				1,358				—				—				1,358
Fair value adjustment of derivative instruments (iii)			—				6,378				(8,552	)			—				2,174				(6,378	)
Provision for impairment (v)			(26,270	)			—				—				—				(26,270	)			(26,270	)
Depletion adjustments due to differences in provision for impairment (vi)			4,402				—				—				—				4,402				4,402
HTL and GTL development costs expensed (vii)			(11,669	)			—				—				—				(11,669	)			(11,669	)
U.S. GAAP		$	89,739			$	6,871			$	409,554			$	3,128			$	(222,853	)		$	189,829

     Shareholders’ Equity

     (i) 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. The effect of this is that under U.S. GAAP, share capital and accumulated deficit are increased by $74.5 million as at March 31, 2007 and December 31, 2006.

     (ii) For 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. For U.S. GAAP, prior to January 1, 2006 the Company applied APB Opinion No. 25, as interpreted by 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. This resulted in a reduction of $3.7 million in the accumulated deficit as at March 31, 2007, and December 31, 2006, equal to accumulated stock based compensation for stock options granted to employees and directors since January 1, 2002 and expensed through December 31, 2005 under Canadian GAAP.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued a revision to SFAS No. 123, “Accounting for Stock Based Compensation” which supersedes APB No. 25, “Accounting for Stock Issued to Employees”. This statement (“SFAS No. 123(R)”) requires measurement of the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant and recognition of the cost in the results of operations over the period during which an employee is required to provide service in exchange for the award. No compensation cost is recognized for equity instruments for which employees do not render the requisite service. The Company elected to implement this statement on a modified prospective basis starting in the first quarter of 2006. Under the modified prospective basis 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 were no differences in the Company’s stock based compensation expense in its financial statements for Canadian GAAP and U.S. GAAP for the three-month periods ended March 31, 2007 and 2006.

(iii) The Company accounts for purchase warrants as equity under Canadian GAAP. As more fully described in our financial statements in Item 8 of our 2006 Annual Report filed on Form 10-K, in 2006, the accounting treatment of warrants was changed under U.S. GAAP to correct for the application of Statement of Financial Accounting Standard No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). Under SFAS No. 133, share purchase warrants with an exercise price denominated in a currency other than the 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. Under the Company’s previous U.S. GAAP accounting treatment, no changes in fair value were recorded. 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. This GAAP difference resulted in an increase in derivative instruments of $8.6 million and $6.4 million as at March 31, 2007 and December 31, 2006, and a decrease in warrants of $8.6 million as at March 31, 2007 and December 31, 2006.

     Oil and Gas Properties and Investments

     (iv) For U.S. GAAP purposes, the aggregate value attributed to the acquisition of U.S. 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.

     (v) As more fully described in our financial statements in Item 8 of our 2006 Annual Report filed on Form 10-K, there are 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. The Company performed the ceiling test in accordance with U.S. GAAP and determined that for the three-months ended March 31, 2007 no impairment provision was required and no impairment provision was required under Canadian GAAP. The differences in the ceiling test impairments by period for the U.S. and China properties between U.S. and Canadian GAAP as at March 31, 2007 were as follows:

		Ceiling Test Impairments								(Increase)
		U.S. GAAP				Canadian GAAP				Decrease
U.S. Properties
Prior to 2004		$	34,000			$	34,000			$	—
2004			15,000				16,350				1,350
2005			2,800				—				(2,800	)
2006			7,600				—				(7,600	)
2007			—				—				—
			59,400				50,350				(9,050	)
China Properties
Prior to 2004			10,000				—				(10,000	)
2004			—				—				—
2005			1,700				5,000				3,300
2006			15,940				5,420				(10,520	)
2007			—				—				—
			27,640				10,420				(17,220	)
		$	87,040			$	60,770			$	(26,270	)

     (vi) The differences in the amount of impairment provisions between U.S. and Canadian GAAP resulted in a reduction in accumulated depletion of $5.7 million and $4.4 million as at March 31, 2007 and December 31, 2006.

     (vii) As more fully described in our financial statements in Item 8 of our 2006 Annual Report filed on Form 10-K, for Canadian GAAP, the Company capitalizes certain costs incurred for HTL and GTL projects subsequent to executing a memorandum of understanding to determine the technical and commercial feasibility of a project, including studies for the marketability for the projects’ products. If no definitive agreement is reached, then the project’s capitalized costs, which are deemed to have no future value, are written down and charged to the results of operations with a corresponding reduction in the investments in HTL and GTL assets. For U.S. GAAP, feasibility, marketing and related costs incurred prior to executing an HTL or GTL definitive agreement are considered to be research and development and are expensed as incurred. As at March 31, 2007 and December 31, 2006, the Company capitalized $11.7 million for Canadian GAAP, which was expensed for U.S. GAAP purposes.

Condensed Consolidated Statements of Operations

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

		Three-Month Periods Ended March 31,
		2007								2006
		Net				Net Loss				Net				Net Loss
		Loss				Per Share				Loss				Per Share
Canadian GAAP		$	(6,547	)		$	(0.03	)		$	(5,376	)		$	(0.02	)
Provision for impairment (v and viii)			—				—				(6,450	)			(0.03	)
Depletion adjustments due to differences in provision for impairment (viii)			1,303				0.01				285				—
HTL and GTL development costs expensed, net (ix)			—				—				(571	)			—
Fair value adjustment of derivative instruments (iii)			(2,192	)			(0.01	)			(4,304	)			(0.02	)
U.S. GAAP		$	(7,436	)		$	(0.03	)		$	(16,416	)		$	(0.07	)
Weighted Average Number of Shares under U.S. GAAP (in thousands)							241,231								224,547

     (viii) As discussed under “Oil and Gas Properties and Investments” in this note, there is a difference in performing the ceiling test evaluation under the full cost method of the accounting rules between U.S. and Canadian GAAP. 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 of $26.3 million as at March 31, 2007 and December 31, 2006. This net increase in U.S. GAAP impairment provisions has resulted in lower depletion rates for U.S. GAAP purposes and a reduction of $1.3 million and $0.3 million in the net losses for the three-month periods ended March 31, 2007 and 2006.

     (ix) As more fully described under “Oil and Gas Properties and Investments” in this note, for Canadian GAAP, feasibility,

marketing and related costs incurred prior to executing an HTL or GTL definitive agreement are capitalized and are subsequently written down upon determination that a project’s future value has been impaired. For U.S. GAAP, such costs are considered to be research and development and are expensed as incurred. For the three-month periods ended March 31, 2007 and 2006 the Company expensed nil and $0.6 million in excess of the Canadian GAAP write-downs during those corresponding periods.

     Pro Forma Effect of Merger and Acquisition

Had the acquisition of Richfirst’s 40% working interest in the Dagang field been completed January 1, 2006, the U.S. GAAP pro forma revenue, net loss and net loss per share of the consolidated operations for the three-month period ended March 31, 2006 would have been as follows:

		Three Months Ended March 31,
		2006
						Net (Income)				Net (Income)
		Revenue				Loss				Loss Per Share
As reported		$	9,864			$	(16,416	)		$	(0.07	)
Pro forma adjustments			1,051				809				—
		$	10,915			$	(15,607	)		$	(0.07	)
Weighted Average Number of Shares (in thousands)											229,415

Income Taxes

On January 1, 2007, the Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation requires that the Company recognize the impact of a tax position in the financial statements if that position is more likely than not of being sustained on audit, based on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods and disclosure. In accordance with the provisions of FIN 48, any cumulative effect resulting from the change in accounting principle is to be recorded as an adjustment to the opening balance of deficit.

The implementation of FIN 48 did not result in any adjustment to the Company’s beginning tax positions. The Company continues to fully recognize its tax benefits, which are offset by a valuation allowance to the extent that it is more likely than not that the deferred tax assets will not be realized. As at March 31, 2007 and December 31, 2006, the Company did not have any unrecognized tax benefits.

The Company files federal and provincial income tax returns in Canada. The Company’s U.S. and China subsidiaries file federal, state and local income tax returns in the U.S. and China, as applicable. The Company may be subject to a reassessment of federal and provincial income taxes by Canadian tax authorities for a period of four years from the date of mailing of the original Notice of Assessment in respect of any particular taxation year. The U.S. federal statute of limitations for assessment of income tax is generally closed for the Company’s tax years ending on or prior to 2002. In certain circumstances, the U.S. federal statute of limitations can reach beyond the standard three year period. U.S. state statutes of limitations for income tax assessment vary from state to state. There is no statute of limitations for audit of tax years in China. Tax authorities have not audited any of the Company’s, or its subsidiaries’, income tax returns or issued Notices of Assessment for any tax years.

The Company recognizes any interest accrued related to unrecognized tax benefits in interest expense and penalties in interest expense and financing costs. During the three-month periods ended March 31, 2007 and 2006, there was no such interest or penalty.

Condensed Consolidated Statements of Cash Flow

As a result of expensing of HTL and GTL development costs required under U.S. GAAP, the statements of cash flows as reported would result in a cash surplus from operating activities of $1.5 million for the three-month period ended March 31, 2006. There would be no difference between Canadian and U.S. GAAP for same period in 2007. Additionally, capital investments reported under investing activities would be $4.3 million for the three-month period ended March 31, 2006. There would be no difference between Canadian and U.S. GAAP for the same period in 2007.

Impact of New and Pending U.S. GAAP Accounting Standards

On January 1, 2007, the Company adopted Statement on Financial Standards No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB statements No. 133 and 140” (“SFAS No. 155”). SFAS No. 155 resolves issues surrounding the application of the bifurcation requirements to beneficial interests in securitized financial assets. In general, this statement permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. The adoption of SFAS No. 155 did not have a material impact on the Company’s financial statements.

In February 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities (including an amendment of FASB Statement No. 115)”
(“SFAS No. 159”). The statement would create a fair value option under which an entity may irrevocably elect fair value as the initial and subsequent measurement attribute for certain financial assets and financial liabilities on a contract-by-contract basis, with changes in fair value recognized in earnings as those changes occur. This Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Management is in the process of reviewing the requirements of this recent statement.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement does not require any new fair value measurements; however, for some entities the application of this statement will change current practice. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, although early adoption is permitted. Management is in the process of reviewing the requirements of this recent statement.

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 in 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 “could”, “propose”, “should”, “intend”, “seeks to”, “is pursuing”, “expect”, “believe”, “will” and similar expressions and statements relating to matters that are not historical facts are forward-looking statements. Forward-looking statements can also include discussions relating to future production associated with our HTL Technology, GTL Technology and EOR techniques. Such statements involve known and unknown risks and uncertainties which may cause our actual results, performances or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Although we believe that our expectations are based on reasonable assumptions, we can give no assurance that our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, our ability to raise capital as and when required, the timing and extent of changes in prices for oil and gas, competition, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and the potential success of 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 we operate and implementation of our capital investment program.

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 our 2006 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 consolidated financial statements, and the Management’s Discussion and Analysis of Financial Condition and Results of Operations, contained in the Form 10-K for the year ended December 31, 2006. 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, our reserves estimates and securities regulatory disclosures generally follow SEC requirements. In 2004, 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. We have been granted certain exemptions from NI 51-101. Please refer to the Special Note to Canadian Investors on page 12 of our 2006 Annual Report on Form 10-K.

OUR DISCUSSION AND ANALYSIS OF OUR OIL AND GAS ACTIVITIES WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES IS PRESENTED ON OUR WORKING INTEREST BASIS 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 in this throughout the Form 10-Q, the following terms have the following meanings:

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

When we refer to oil in “equivalents”, we are doing so to compare quantities of oil with quantities of gas or to express these different commodities in a common unit. In calculating Bbl equivalents, we use a generally recognized industry standard in which one Bbl is

equal to six Mcf. Boes may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Electronic copies of our filings with the SEC and the CSA are available, free of charge, through our web site (www.ivanhoeenergy.com) or, upon request, by contacting our investor relations department at (604) 688-8323. Alternatively, the SEC and the CSA each maintains a website (www.sec.gov and www.sedar.com) that contains our periodic reports and other public filings with the SEC and the CSA.

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. Ivanhoe Energy plans to utilize technologically innovative methods designed to significantly improve recovery of heavy oil resources, including the application of the patented rapid thermal processing process (“RTP^TM Process”) for heavy oil upgrading (“HTL Technology” or “HTL”) and enhanced oil recovery (“EOR”) techniques. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production (“E&P”) of oil and gas. Finally, the Company is exploring an opportunity to monetize stranded gas reserves through the application of the conversion of natural gas-to-liquids using a technology (“GTL Technology” or “GTL”) licensed from Syntroleum Corporation. Our core operations are in the United States and China, with business development opportunities worldwide.

Ivanhoe Energy’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 which can be used to generate steam or electricity. The HTL 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 process will allow the oil to be transported economically over long distances.

HTL can virtually eliminate cost exposure to natural gas and diluent, solve the transport challenge, and capture the majority of the heavy to light oil price differential for oil producers. HTL 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 facilities are designed for installation near the wellhead, they eliminate the need for diluent and make large, dedicated upgrading facilities unnecessary.

Corporate Strategy

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

The global oil and gas industry is operating near capacity, driven by sharp increases in demand from developing economies and the declining availability of replacement low cost reserves. This has resulted in a significant increase in the relative price of oil and marked shifts in the demand and supply landscape. These shifts include demand moving toward China and India, while supply has shifted towards the need to develop higher cost/lower value resources, including heavy oil and bitumen.

Heavy oil developments can be segregated into two types: conventional heavy oil which flows to the surface without steam enhancement and non-conventional heavy oil and bitumen. While we focus on the heavier non-conventional heavy oil, both are playing an important role in creating opportunities for Ivanhoe.

Production of conventional heavy oil has been steadily increasing worldwide, led by Canada and Latin America but with significant contributions from most oil basins, including the Middle East and the Far East, 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 oil production has been getting heavier. Refineries, on the other hand, have not been able to keep up with the need for deep conversion capacity, and heavy-light price differentials have widened significantly.

With regard to non-conventional heavy oil and bitumen, the dramatic increase in interest and activity has been fueled by higher prices, in addition to various key advances in technology, including improved remote sensing, horizontal drilling, and new thermal techniques. This has enabled producers to much more effectively access the extensive, heavy oil resources around the world.

These newer technologies, together with firm oil prices, have generated increased access to heavy oil resources, although for profitable exploitation, key challenges remain, with varied weightings, project by project: 1) the requirement for steam and electricity to help extract heavy oil, 2) the need for diluent to move the oil once it is at the surface, and 3) the wide heavy-light price differentials that the producer is faced with when the product gets 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 lies fallow.

Ivanhoe’s Value Proposition

Ivanhoe’s application of the HTL Technology seeks to address the three key heavy oil development challenges outlined above, and can do so at a relatively small scale.

In addition to improving oil quality, an HTL facility can yield surplus energy for production of the steam and electricity used in heavy oil production. The thermal energy generated by the HTL process can provide heavy oil producers with an alternative to increasingly volatile prices for natural gas that now is widely used to generate steam. Test yields of the low-viscosity, upgraded product are 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.

Ivanhoe’s HTL process offers three potential advantages in that it can virtually eliminate cost exposure to natural gas and diluent, solve the transport challenge, and capture the majority of the heavy to light oil price differential for oil producers. Testing indicates that Ivanhoe’s HTL process can accomplish this at a much smaller scale and at lower per barrel capital cost compared with established competing technologies, using readily available plant and process components. Since HTL facilities will be designed for installation near the wellhead, they are expected to eliminate the need for diluent and may make large, dedicated upgrading facilities unnecessary.

The business opportunities available to Ivanhoe correspond to the challenges each potential heavy oil project faces. In Canada, California, the Middle East and Asia, all three of the HTL advantages identified above come into play. In others, including certain identified opportunities in Latin America and some Middle East countries, the heavy oil naturally flows to the surface, but transport is the key problem.

The economics of a project are effectively dictated by the advantages that HTL 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 value proposition.

Implementation Strategies

In order to capture the value that our HTL Technology provides, the Company is pursuing the following strategies:

	1.		Build a portfolio of major HTL projects. We will continue to deploy our personnel and our financial resources in support of our goal to capture opportunities for development projects utilizing our HTL Technology. We recently signed an agreement with a Western Canadian oilsands producer for a joint feasibility and testing program using our HTL Technology for the processing of a unique heavy oil stream from the producer’s operations in the Athabasca oil sands. The application contemplated by this test program complements our main strategy of deploying our HTL Technology as a strategic tool to acquire and develop heavy oil reserves.
	2.		Advance the technology. Additional development work will continue as we advance the technology through the first commercial application and beyond. To optimize the technology development process, the Company has recently commenced design and construction of a Feedstock Test Facility (“FTF”) that has been designed to process small quantities of heavy oil and will allow us to:

	•		Screen and test heavy oil and bitumen feedstocks in cost-effective quantities for current and potential partners,
	•		Produce, assess and evaluate physical liquid products from partner heavy oil and bitumen feedstocks,
	•		Conduct ongoing research and development in order to add to our portfolio of patents through the development and testing of improvements and optimizations, and
	•		Have an HTL showcase that possesses all of the key elements of a commercial facility.

	3.		Enhance our financial position in anticipation of major projects. Implementation of large projects requires significant capital outlays. We are refining our financing plans and establishing the relationships required for the development activities that we see ahead. The Company’s recently announced agreement with INPEX Corporation, Japan’s largest oil and gas exploration and production company, to jointly pursue the opportunity to develop a heavy oil field in Iraq complements a number of other initiatives that the Company has underway that focus on heavy oil basins around the world.
	4.		Build internal capabilities in advance of major projects. The HTL technical team, which includes our own staff, specialized consultants including the inventors of the technology, and our EOR team will be supplemented and expanded to add additional expertise in areas such as project management.
	5.		Build the relationships that we will need for the future. Commercialization of our technologies demands close alignment with partners, suppliers, host governments and financiers.

6.

Capture value from other company assets as we complete the transition to a heavy oil focused company. Revenue from existing operations in California and China will be utilized to fund growth of the business. Non-heavy oil related investment opportunities in our portfolio will be leveraged to capture value and provide maximum return for the Company.

Executive Overview of 2007 Results

The following table sets forth certain selected consolidated data for the three-month periods ended March 31, 2007 and 2006:

		Three-Month Periods
		Ended March 31,
		2007				2006
Oil and gas revenue		$	9,596			$	9,826
Net loss		$	(6,547	)		$	(5,376	)
Net loss per share		$	(0.03	)		$	(0.02	)
Average production (Boe/d)			2,035				2,013
Net operating revenue per Boe		$	32.27			$	39.25
Capital investments		$	5,334			$	4,892
Cash flow from operating activities		$	2,594			$	2,080