Edgar Filing: IVANHOE ENERGY INC

Quarterly Report for period ended Dec. 31, 2007

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, 2008
		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.

(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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


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 March 31, 2008 was 244,873,349 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, 2008 and December 31, 2007		3
	Unaudited Condensed Consolidated Statements of Operations, Comprehensive Loss and Accumulated Deficit for the Three-Month Periods Ended March 31, 2008 and 2007		4
	Unaudited Condensed Consolidated Statements of Cash Flows for the Three-Month Periods Ended March 31, 2008 and 2007		5
	Notes to the Unaudited Condensed Consolidated Financial Statements		6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29
Item 4.	Controls and Procedures		30

PART II Other Information
Item 1.	Legal Proceedings		31
Item 1A.	Risk Factors		31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 3.	Defaults Upon Senior Securities		31
Item 4.	Submission of Matters to a Vote of Security Holders		31
Item 5.	Other Information		31
Item 6.	Exhibits		31

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,			December 31,
	2008			2007

ASSETS
Current Assets:
Cash and cash equivalents	$	6,691		$	11,356
Accounts receivable		10,523			9,376
Advance		825			825
Prepaid and other current assets		515			602

		18,554			22,159
Oil and gas properties and development costs, net		109,031			111,853
Intangible assets — technology		102,153			102,153
Long term assets		1,338			751

	$	231,076		$	236,916


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	9,356		$	9,538
Debt — current portion		6,612			6,729
Derivative instruments		11,430			9,432

		27,398			25,699
Long term debt		9,448			9,812
Asset retirement obligations		2,469			2,218
Long term obligation		1,900			1,900

		41,215			39,629

Commitments and contingencies
Going concern and basis of presentation
Shareholders’ Equity:
Share capital, issued and oustanding 244,873,349 common shares		324,262			324,262
Purchase warrants		23,078			23,078
Contributed surplus		11,055			9,937
Accumulated deficit		(168,534	)		(159,990	)

		189,861			197,287

	$	231,076		$	236,916

(See accompanying notes)

IVANHOE ENERGY INC.

Unaudited Condensed Consolidated Statements of Operations,

Comprehensive Loss and Accumulated Deficit

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


	Three Months
	Ended March 31,
	2008			2007

Revenue
Oil and gas revenue	$	15,043		$	9,596
Loss on derivative instruments		(3,946	)		(459	)
Interest income		72			120

		11,169			9,257

Expenses
Operating costs		5,392			3,685
General and administrative		3,665			2,872
Business and technology development		1,757			2,162
Depletion and depreciation		8,366			6,892
Interest expense and financing costs		533			193

		19,713			15,804

Net Loss and Comprehensive Loss		(8,544	)		(6,547	)
Accumulated Deficit, beginning of period		(159,990	)		(120,783	)

Accumulated Deficit, end of period	$	(168,534	)	$	(127,330	)

Net Loss per share — Basic and Diluted	$	(0.03	)	$	(0.03	)

Weighted Average Number of Shares (in thousands)		244,873			241,231

(See accompanying notes)

IVANHOE ENERGY INC.

Unaudited Condensed Consolidated Statements of Cash Flows

(stated in thousands of U.S. Dollars)


	Three Months
	Ended March 31,
	2008			2007

Operating Activities
Net loss and comprehensive loss	$	(8,544	)	$	(6,547	)
Items not requiring use of cash:
Depletion and depreciation		8,366			6,892
Stock based compensation		1,118			802
Unrealized loss on derivative instruments		1,998			666
Other		191			169
Changes in non-cash working capital items		(112	)		612

		3,017			2,594

Investing Activities
Capital investments		(5,323	)		(5,334	)
Proceeds from sale of assets		—			1,000
Advance repayments		—			200
Other		(30	)		75
Changes in non-cash working capital items		(1,130	)		(1,006	)

		(6,483	)		(5,065	)

Financing Activities
Payments of debt obligations		(615	)		(615	)
Other		(584	)		—

		(1,199	)		(615	)

Decrease in cash and cash equivalents, for the period		(4,665	)		(3,086	)
Cash and cash equivalents, beginning of period		11,356			13,879

Cash and cash equivalents, end of period	$	6,691		$	10,793

(See accompanying notes)

IVANHOE ENERGY INC.

Notes to the Condensed Consolidated Financial Statements
March 31, 2008
(all tabular amounts are expressed in thousands of U.S. dollars except per share amounts)
(Unaudited)


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 U.S., except as outlined in Note 13. The unaudited condensed consolidated financial statements have been prepared on a basis consistent with the accounting principles and policies reflected in the December 31, 2007 consolidated financial statements except as discussed in Note 2. 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, 2007 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.

The Company’s financial statements as at and for the three-month period ended March 31, 2008 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business. The Company incurred a net loss of $8.5 million for the three-month period ended March 31, 2008, and as at March 31, 2008, had an accumulated deficit of $168.5 million and negative working capital of $8.8 million. The Company currently anticipates incurring substantial expenditures to further its capital investment programs and the Company’s cash flows from operating activities will not be sufficient to both satisfy its current obligations and meet the requirements of these capital investment programs. Recovery of capitalized costs related to potential HTL^tm and GTL projects is dependent upon finalizing definitive agreements for, and successful completion of, the various projects. Management’s plans include alliances or other arrangements with entities with the resources to support the Company’s projects as well as project financing, debt and mezzanine financing or the sale of equity securities in order to generate sufficient resources to assure continuation of the Company’s operations and achieve its capital investment objectives. The Company intends to utilize revenue from existing operations to fund the transition of the Company to a heavy oil exploration, production and upgrading company and non-heavy oil related investments in our portfolio will be leveraged or monetized to capture value and provide maximum return for the Company. The outcome of these matters cannot be predicted with certainty at this time and therefore the Company may not be able to continue as a going concern. These condensed consolidated financial statements do not include any adjustments to the amounts and classification of assets and liabilities that may be necessary should the Company be unable to continue as a going concern.


2.	CHANGES IN ACCOUNTING POLICIES


	*2008 Accounting Changes*

On January 1, 2008 the Company adopted three new accounting standards that were issued by the Canadian Institute of Chartered Accountants (“CICA”): 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. The latter two replaced S.3861. The Company has adopted the new standards on January 1, 2008 with additional disclosures included in these condensed consolidated financial statements. There was no transitional adjustment to the condensed consolidated financial statements.


	*Impact of New and Pending Canadian GAAP Accounting Standards*

In February 2008, the CICA issued Handbook Section 3064, “Goodwill and Intangible assets,” (“S.3064”) replacing Handbook Section 3062, “Goodwill and Other Intangible Assets” (“S.3062”) and Handbook Section 3450, “Research and Development Costs”. Various changes have been made to other sections of the CICA Handbook for consistency purposes. S.3064 will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. The new section establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous S.3062. Management has concluded that the requirements of this new Section as they relate to goodwill will not have a material impact on its consolidated financial statements; however, management is still evaluating the impact of the requirements related to development costs.


	*Convergence of Canadian GAAP with International Financial Reporting Standards*

In 2006, Canada’s Accounting Standards Board (“AcSB”) ratified a strategic plan that will result in Canadian GAAP, as used by public companies, being converged with International Financial Reporting Standards (“IFRS”) over a transitional period. The AcSB has developed and published a detailed implementation plan, with a required changeover date for fiscal years beginning on or after January 1, 2011. This convergence initiative is in its early stages as of the date of these financial statements. Management has commenced a program of analyzing the Company’s historical financial information in order to assess the impact of the convergence on its financial statements.


3.	OIL AND GAS PROPERTIES AND DEVELOPMENT COSTS

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


	As at March 31, 2008
	Oil and Gas
	U.S.			China			HTL^tm			GTL		Total

Oil and Gas Properties:
Proved	$	109,718		$	136,220		$	—		$	—	$	245,938
Unproved		4,386			3,851			—			—		8,237

		114,104			140,071			—			—		254,175
Accumulated depletion		(28,539	)		(64,788	)		—			—		(93,327	)
Accumulated provision for impairment		(50,350	)		(16,550	)		—			—		(66,900	)

		35,215			58,733			—			—		93,948

HTL^tm and GTL Development Costs:
Feasibility studies and other deferred costs		—			—			399			5,054		5,453
Feedstock test facility		—			—			5,408			—		5,408
Commercial demonstration facility		—			—			9,924			—		9,924
Accumulated depreciation		—			—			(5,850	)		—		(5,850	)

		—			—			9,881			5,054		14,935

Furniture and equipment		534			119			108			—		761
Accumulated depreciation		(455	)		(79	)		(79	)		—		(613	)

		79			40			29			—		148

	$	35,294		$	58,773		$	9,910		$	5,054	$	109,031


	As at December 31, 2007
	Oil and Gas
	U.S.			China			HTL^tm			GTL		Total

Oil and Gas Properties:
Proved	$	107,040		$	134,648		$	—		$	—	$	241,688
Unproved		4,373			3,297			—			—		7,670

		111,413			137,945			—			—		249,358
Accumulated depletion		(27,091	)		(58,583	)		—			—		(85,674	)
Accumulated provision for impairment		(50,350	)		(16,550	)		—			—		(66,900	)

		33,972			62,812			—			—		96,784

HTL^tm and GTL Development Costs:
Feasibility studies and other deferred costs		—			—			389			5,054		5,443
Feedstock test facility		—			—			4,724			—		4,724
Commercial demonstration facility		—			—			9,903			—		9,903
Accumulated depreciation		—			—			(5,159	)		—		(5,159	)

		—			—			9,857			5,054		14,911

Furniture and equipment		529			119			107			—		755
Accumulated depreciation		(449	)		(77	)		(71	)		—		(597	)

		80			42			36			—		158

	$	34,052		$	62,854		$	9,893		$	5,054	$	111,853

Costs as at March 31, 2008 of $8.2 million ($7.7 million at December 31, 2007), related to unproved oil and gas properties have been excluded from costs subject to depletion and depreciation. Included in that same depletion calculation were $5.3 million for future development costs associated with proven undeveloped reserves as at March 31, 2008 ($8.9 million at December 31, 2007).

For the three-month period ended March 31, 2008, general and administrative expenses related directly to oil and gas acquisition, exploration and development activities of $0.5 million ($1.2 million for 2007) were capitalized.


4.	INTANGIBLE ASSETS — TECHNOLOGY

The Company’s intangible assets consist of the following:


	HTL^tm Technology

The Company owns 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^tm Technology” or “HTL^tm”) as at March 31, 2008 and December 31, 2007 was $92.2 million. Since the Company acquired the technology, it has continued to expand its patent coverage to project innovations to the HTL Technology^tm as they are developed and to significantly extend the Company’s portfolio of HTL intellectual property. The Company has had two patents granted and has more than 20 patents pending in its name.


	*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, 2008 and December 31, 2007 was $10.0 million.

Recovery of capitalized costs related to potential HTL^tm and GTL projects is dependent upon finalizing definitive agreements for, and successful completion of, the various projects. These intangible assets were not amortized and their carrying values were not impaired for the three-month periods ended March 31, 2008 and 2007.


5.	LONG TERM DEBT

Notes payable consisted of the following as at:


	March 31,			December 31,
	2008			2007

Variable rate bank note, (5.85% — 7.83% at March 31, 2008), due 2008	$	4,500		$	4,500
Variable rate bank note (9.338% at March 31, 2008) due 2010		10,000			10,000
Non-interest bearing promissory note, due 2006 through 2009		2,261			2,876

		16,761			17,376

Less:
Unamortized discount		(88	)		(139	)
Unamortized deferred financing costs		(613	)		(696	)
Current maturities		(6,612	)		(6,729	)

		(7,313	)		(7,564	)

	$	9,448		$	9,812


	*Bank Loans*

In October 2006 the Company arranged a Senior Secured Revolving/Term Credit Facility of up to $15 million with an initial borrowing base of $8 million. The facility is a revolving facility and is due in October 2008. 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 up to 14,700 Bbls of the Company’s production from its South Midway property in California and its Spraberry property in West Texas. As part of reestablishing the borrowing base amount, the Company was required to enter into an additional commodity derivative contract (See Note 10). The facility is secured by a mortgage on both of these properties.

In September 2007 the Company arranged an additional Revolving/Term Credit Facility of up to $30 million with an initial borrowing base of $10 million. The facility is a revolving facility with a three-year term with interest payable only during the term. Interest will be three-month LIBOR plus 3.75%. The loan terms include the requirement for the Company to enter into three-year commodity derivative contracts (See Note 10) covering up to 18,000 Bbls per month of the Company’s production from its Dagang field in China. The facility is secured by a security interest in the revenue from the Company’s monthly oil sales in China and by a pledge of shares of the Company’s Chinese subsidiaries.


	*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. The Company has the right, during the three-year loan repayment period, to require the holder of the promissory note, Richfirst Holdings Limited, to convert the remaining unpaid balance of the promissory note into common shares of the Company’s wholly-owned subsidiary, Sunwing Energy Ltd (“Sunwing”), 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.


	*Demand Loan*

In April 2008, the Company obtained a loan from a third party finance company in the amount of Cdn.$5.0 million bearing interest at 8% per annum. The principal and accrued and unpaid interest matures and is repayable in August 2008. The lender has the option to convert the outstanding balance, in whole or in part, into the Company’s common shares at a conversion price of Cdn.$2.24 per share.

The scheduled maturities of the Company’s long term debt, excluding unamortized discount and unamortized deferred financing costs, as at March 31, 2008 were as follows:


2008	$	6,345
2009		416
2010		10,000

	$	16,761


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^tm 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, 2008 was estimated at $5.0 million. These payments are expected to be made over the next 30 years; with over half of the payments during 2020 and 2040. To calculate the present value of these obligations, the Company used an inflation rate of 3% and the expected future cash flows have been discounted using a credit-adjusted risk-free rate of 6%. The changes in the Company’s liability for the three-month period ended March 31, 2008 were as follows:


Carrying balance, beginning of period	$	2,218
Liabilities incurred		218
Accretion expense		33

Carrying balance, end of period	$	2,469


7.	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.

The Company has completed the first phase of this project and in December 2007, the Company and Mitsubishi (the “Zitong Partners”) made a decision to enter into the next three-year exploration phase (“Phase 2”) of the project. By electing to participate in Phase 2 the Zitong Partners must 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 a 700 foot shortfall from the first phase), with total estimated minimum expenditures for this program of $25.0 million. The Phase 2 seismic line acquisition commitment was fulfilled in the first phase exploration program. The Zitong Partners must complete the minimum work program by December 31, 2010, or will be obligated to pay to CNPC the cash equivalent of the deficiency in the work program for that exploration phase. Following the completion of Phase 2, the Zitong Partners must relinquish all of the remaining property except any areas identified for development and production.


	*Long Term Obligation*

As part of its 2005 merger with Ensyn Group, Inc., 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 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. In 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 the Chinese tax authorities and subsequently submitted its 2006 tax return taking a new filing position for development costs. This change resulted in a $50.3 million reduction in tax loss carryforwards 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 any rule changes, however it will continue to file tax returns under this new rule, and await any tax audit rulings.


	*Other Commitments*

The Company has contracted with Zeton Inc. (“Zeton”) to construct a Feedstock Test Facility (“FTF”) that has been designed to process small quantities of heavy oil. The FTF is a small (15-20 Bbls/d), highly flexible state-of-the-art HTL^tm facility which will permit more cost-effective screening of feedstock crudes for current and potential partners in smaller volumes and at lower costs than required at the CDF. The contract is considered a lump-sum turn-key contract with scheduled payments tied to milestones. Should Zeton meet all of the remaining milestones, the Company will be obligated to pay $2.2 million in addition to what has been paid to date.

From time to time the Company enters into consulting agreements whereby a success fee may be payable if and when either 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 future 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 be required 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.


8.	SHARE CAPITAL AND WARRANTS

Following is a summary of the changes in share capital and stock options outstanding for the three-month period ended March 31, 2008:


	Common Shares						Stock Options
										Weighted Average
	Number				Contributed		Number			Exercise Price
	(thousands)		Amount		Surplus		(thousands)			Cdn.$

Balance December 31, 2007		244,873	$	324,262	$	9,937		12,945		$	2.37
Options:
Granted		—		—		1,118		3,119		$	1.62
Expired		—		—		—		(85	)	$	1.78

Balance March 31, 2008		244,873	$	324,262	$	11,055		15,979		$	2.23


	*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, 2008.

As at March 31, 2008, 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			Value on
Issue		Warrant	Issued		Exercisable		Issuable		Value		Expiry Date	Share			Exercise
			(thousands)						($U.S. 000)						($U.S. 000)

	2005	Cdn. $3.10		4,100		4,100		4,100	$	2,412	⁽¹⁾	Cdn. $	3.50		$	14,088
	2005	U.S. $1.63		10,996		10,996		10,996		1,861	⁽²⁾	U.S. $	2.50			27,490
	2006	U.S. $2.23		11,400		11,400		11,400		18,805	May 2011	Cdn. $	2.93	⁽³⁾		32,792

				26,496		26,496		26,496	$	23,078					$	74,370


	(1)	In March 2007, the Company agreed that the warrants, which were to have expired on April 15, 2007, would be extended until the earlier of: (i) April 15, 2008; and (ii) thirty days following the date the closing trading price of the common shares of the Company on the Toronto Stock Exchange exceeds the exercise price of the warrants for a period of five consecutive trading days. These warrants expired unexercised on April 15, 2008.

	(2)	In October 2007, the Company agreed that these warrants, which were to have expired in November 2007, would be extended until the earlier of: (i) six months from their original expiry date; and (ii) thirty days following the date the closing trading price of the common shares of the Company on the Toronto Stock Exchange exceeds the exercise price of the warrants for a period of five consecutive trading days. On May 4^th, 2008, 7,208,599 of these warrants expired unexercised and on May 9^th, 2008, 3,480,982 of these warrants expired unexercised. The remaining 306,749 warrants will expire on May 14^th, 2008 if not exercised by then.

	(3)	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. In September 2006, these warrants were listed on the Toronto Stock Exchange and the exercise price was changed to Cdn. $2.93.

The weighted average exercise price of the exercisable purchase warrants, as at March 31, 2008 was U.S. $2.81 per share.


9.	SEGMENT INFORMATION

The Company has three reportable business segments: Oil and Gas, HTL^tm 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 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 its exploration activities are conducted on the Zitong block located in Sichuan Province.


	*HTL^tm*

The Company seeks to increase its oil reserves through the deployment of our HTL^tm 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^tm facility can yield surplus energy for producing steam and electricity used in heavy-oil production. The thermal energy from the RTPTM 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 GTL projects throughout the world to convert natural gas into 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, 2008 and 2007 and identifiable assets as at March 31, 2008 and December 31, 2007:


	Three-Month Period Ended March 31, 2008
	Oil and Gas
	U.S.			China			HTL^tm			GTL			Corporate			Total

Oil and gas revenue	$	4,155		$	10,888		$	—		$	—		$	—		$	15,043
Loss on derivative instruments		(1,264	)		(2,682	)		—			—			—			(3,946	)
Interest income		44			14			—			—			14			72

		2,935			8,220			—			—			14			11,169

Operating costs		1,082			4,310			—			—			—			5,392
General and administrative		362			566			—			—			2,737			3,665
Business and technology development		—			—			1,720			37			—			1,757
Depletion and depreciation		1,456			6,206			700			3			1			8,366
Interest expense and financing costs		148			324			10			—			51			533

		3,048			11,406			2,430			40			2,789			19,713

Net Loss	$	(113	)	$	(3,186	)	$	(2,430	)	$	(40	)	$	(2,775	)	$	(8,544	)

Capital Investments	$	2,483		$	2,125		$	715		$	—		$	—		$	5,323

Identifiable Assets (As at March 31, 2008)	$	40,527		$	70,725		$	102,653		$	15,073		$	2,098		$	231,076

Identifiable Assets (As at December 31, 2007)	$	40,726		$	73,298		$	102,456		$	15,073		$	5,363		$	236,916


	Three-Month Period Ended March 31, 2007
	Oil and Gas
	U.S.			China			HTL^tm			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


10.	FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

The accounting classification of each category of financial instruments, and their carrying amounts, are set out below.


	As at March 31, 2008
								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	$	—	$	—	$	6,691		$	—		$	6,691
Accounts receivable		10,523		—		—			—			10,523
Advance		825		—		—			—			825
Financial Liabilities:
Accounts payable and accrued liabilities		—		—		—			(9,356	)		(9,356	)
Derivative instruments		—		—		(11,430	)		—			(11,430	)
Long term debt		—		—		—			(16,060	)		(16,060	)

	$	11,348	$	—	$	(4,739	)	$	(25,416	)	$	(18,807	)


	As at December 31, 2007
								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	$	—	$	—	$	11,356		$	—		$	11,356
Accounts receivable		9,376		—		—			—			9,376
Advance		825		—		—			—			825
Financial Liabilities:
Accounts payable and accrued liabilities		—		—		—			(9,538	)		(9,538	)
Derivative instruments		—		—		(9,432	)		—			(9,432	)
Long term debt		—		—		—			(16,541	)		(16,541	)

	$	10,201	$	—	$	1,924		$	(26,079	)	$	(13,954	)


	*Financial Risk Factors*

The Company is exposed to a number of different financial risks arising from typical business exposures as well as its use of financial instruments including market risk relating 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 and nor to management’s objectives, policies and processes to manage risks from the previous year. The risks associated with our main financial instruments and our policies for minimizing these risks are detailed below.


	*Market Risk*

Market risk is the risk that the fair value or future cash flows of our financial instruments will fluctuate because of changes in market prices. Components of market risk to which we are exposed are discussed below.


	Commodity Price Risk

Commodity price risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market commodity prices. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility as well as a result of a requirement of the Company’s lenders.

The Company entered into costless collar derivatives to minimize variability in its cash flow from the sale of up to 14,700 Bbls per month of the Company’s production from its South Midway Property in California and Spraberry Property in West Texas over a two-year period starting November 2006 and a six-month period starting November 2008. The derivatives had a ceiling price of $65.20, and $70.08, per barrel and a floor price of $63.20, and $65.00, per barrel, respectively, using WTI as the index traded on the NYMEX. The Company also entered into a costless collar derivative to minimize variability in its cash flow from the sale of up to 18,000 Bbls per month of the Company’s production from its Dagang field in China over a three-year period starting September 2007. This derivative had a ceiling price of $84.50 per barrel and a floor price of $55.00 per barrel using WTI as the index traded on the NYMEX.

During the three-month periods ended March 31, 2008, and 2007 the Company had $1.9 million of realized losses and $0.2 million of realized gains, respectively, on these derivative transactions, and $2.0 million and $0.7 million, respectively, of unrealized losses. Both realized and unrealized gains and losses on derivatives have been recognized in the results of operations.

On March 31, 2008, the Company’s open positions on the derivatives referred to above had a fair value of $11.4 million. A 10% increase in oil prices would increase the fair value, and consequently increase the net loss, by approximately $4.8 million, while a 10% decrease in prices would

reduce the fair value, and consequently reduce the net loss, by approximately $4.4 million. The fair value change assumes volatility based on prevailing market parameters at March 31, 2008.


	Foreign Currency Exchange Rate Risk

Foreign currency risk refers to the risk that the value of a financial commitment, recognized asset or liability will fluctuate due to changes in foreign currency rates. The main underlying economic currency of the Company’s cash flows is the U.S. dollar. This is because the Company’s major product, crude oil, is priced internationally in U.S. dollars. Accordingly, we do not expect to face foreign exchange risks associated with our production revenues. However, the Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The majority of the operating costs incurred in our Chinese operations are paid in Chinese renminbi. The majority of costs incurred in our administrative offices in Vancouver and Calgary, as well as some business development costs, are paid in Canadian dollars. Disbursement transactions denominated in Chinese renminbi and Canadian dollars are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date. Foreign currency gains and losses also come about when monetary assets and liabilities, mainly short term payables and receivables, denominated in foreign currencies are translated at the end of each month. The estimated impact of a 10% strengthening or weakening of the Chinese renminbi, and Canadian dollar, as of March 31, 2008 on net loss and accumulated deficit for the three-month period ended March 31, 2008 is a $0.2 million increase, and a $0.2 million decrease, respectively. To help reduce our exposure to foreign currency risk we seek to maximize our expenditures and contracts denominated in U.S. dollars and minimize those denominated in other currencies.


	Interest Rate Risk

Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market interest rates. Interest rate risk arises from interest-bearing borrowings which have a variable interest rate. Interest-bearing financial assets are not considered significant. The Company currently has two separate bank loan facilities with fluctuating interest rates. We estimate that our net loss and accumulated deficit for the three-month period ended March 31, 2008 would have changed less than $0.1 million for every 1% change in interest rates as of March 31, 2008. The Company is not currently actively attempting to manage this interest rate risk given the limited amount and term of our borrowings and the current global interest rate cycle.


	*Credit Risk*

The Company is exposed to credit risk with respect to its accounts receivable and advance balances. Most of the Company’s accounts receivable balances relate to oil and natural gas sales and are exposed to typical industry credit risks. In addition, accounts receivable balances consist of costs billed to joint venture partners where the Company is the operator and advances to partners for joint operations where the Company is not the operator. The advance balance relates to an arrangement whereby scheduled advances were made to a third party contractor associated with negotiating an HTL^tm and/or GTL project for the Company. The Company manages its credit risk by entering into sales contracts with only established entities and reviewing its exposure to individual entities on a regular basis. Of the $10.5 million trade receivables balance as at March 31, 2008, $7.4 million is due from customer A and $1.3 million is due from customer B. There are no other customers who represent more than 5% of the total balance of trade receivables. As noted below, included in the Company’s trade receivable and advance balance are debtors with a carrying amount of $2.0 million which are past due at the reporting date for which the Company has not provided an allowance as there has not been a significant change in credit quality and the amounts are still considered recoverable. Losses associated with credit risk have been immaterial for all periods presented.


	March 31,		December 31,
	2008		2007

Accounts Receivable:
Neither impaired nor past due	$	9,369	$	8,259
Impaired (net of valuation allowance)		—		—
Not impaired and past due in the following periods:
within 30 days		175		347
31 to 60 days		243		—
61 to 90 days		19		4
over 90 days		717		766

		10,523		9,376
Advance
Not impaired and past due over 90 days		825		825

	$	11,348	$	10,201

Our maximum exposure to credit risk is based on the recorded amounts of our financial assets above.


	*Liquidity Risk*

Liquidity risk is the risk that suitable sources of funding for the Company’s business activities may not be available, which means we may be forced to sell financial assets or non-financial assets, refinance existing debt, raise new debt or issue equity. The Company’s present plans include alliances or other arrangements with entities with the resources to support the Company’s projects as well as project financing, debt and mezzanine financing or the sale of equity securities in order to generate sufficient resources to assure continuation of the Company’s operations and achieve its capital investment objectives.

The contractual maturity of our fixed and floating rate financial liabilities and derivatives are show in the table below. The amounts presented represent the future undiscounted principal and interest cash flows and therefore do not equate to the values presented in the balance sheet.


	As at March 31, 2008								As at December 31, 2007
	Contractual Maturity								Contractual Maturity
	(Nominal Cash Flows)								(Nominal Cash Flows)
	Less than		1 to 2		2 to 5		Over 5		Less than		1 to 2		2 to 5		Over 5
	1 year		years		years		years		1 year		years		years		years

Derivative financial liabilities:
Costless Collars — oil price commodity		8,250		3,180		—		—		7,156		2,276		—		—
Non derivative financial liabilities:
Trade accounts payable		6,236		—		—		—		6,897		—		—		—
Accruals		3,120		—		—		—		2,641		—		—		—
Long term debt		7,740		1,130		10,325		—		8,240		1,541		10,277		—


	(i)	Net amounts for costless collars for which net cash flows are exchanged.

	(ii)	For floating rate instruments, the amount disclosed is determined by reference to the interest rate at the last re-pricing date.


11.	CAPITAL MANAGEMENT

The Company manages its capital so that the Company and its subsidiaries will be able to continue as a going concern and to create shareholder value through exploring, appraising and developing its assets including the major initiative of implementing multiple, full-scale, commercial HTL^tm heavy-oil projects in Canada and internationally. There have been no significant changes in management’s objectives, policies and processes to manage capital or the components of capital from the previous year.

The Company defines capital as total equity or deficiency plus cash and cash equivalents and long-term debt. Total equity is comprised of share capital, warrants, shares to be issued and accumulated deficit as disclosed in Note 8. Cash and cash equivalents consist of $6.7 million and $11.4 million at March 31, 2008 and December 31, 2007. Long-term debt is disclosed in Note 5.

The Company’s management reviews the capital structure on a regular basis to maintain the most optimal debt to equity balance. In order to maintain or adjust its capital structure, the Company may refinance its existing debt, raise new debt, seek cost sharing arrangements with partners or issue new shares. The Company believes that it met its objectives for the first quarter of 2008.

The Company’s U.S. and Chinese oil and gas subsidiaries are subject to financial covenants, such as interest coverage ratios, under each of their revolving/term credit facilities which are measured on a quarterly or semi-annual basis. The Company’s U.S. subsidiary is in compliance with all financial covenants, while the first measurement period for the Company’s Chinese subsidiary will be for the quarter ended June 30, 2008.


12.	SUPPLEMENTAL CASH FLOW INFORMATION

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


	2008			2007

Supplemental Cash Flow Information:
Cash paid during the period for:
Income taxes	$	6		$	5

Interest	$	366		$	34

Changes in non-cash working capital items
Operating Activities:
Accounts receivable	$	(1,184	)	$	1,009
Prepaid and other current assets		108			175
Accounts payable and accrued liabilities		964			(572	)

		(112	)		612

Investing Activities
Accounts receivable		37			(115	)
Prepaid and other current assets		(21	)		50
Accounts payable and accrued liabilities		(1,146	)		(941	)

		(1,130	)		(1,006	)

	$	(1,242	)	$	(394	)

Cash and cash equivalents at March 31, 2008 and December 31, 2007 are composed entirely of bank balances in guaranteed checking or savings accounts.


13.	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 Development Costs


	As at March 31, 2008
	Assets			Liabilities		Shareholders’ Equity
	Oil and Gas
	Properties and					Share
	Development			Derivative		Capital and			Contributed			Accumulated
	Costs			Instruments		Warrants			Surplus			Deficit			Total

Canadian GAAP	$	109,031		$	11,430	$	347,340		$	11,055		$	(168,534	)	$	189,861
Adjustments for:
Reduction in stated capital ⁽ⁱ⁾		—			—		74,455			—			(74,455	)		—
Accounting for stock based compensation ⁽ⁱⁱ⁾		—			—		(396	)		(3,352	)		3,748			—
Fair value adjustment of warrants ⁽ⁱⁱⁱ⁾		—			8,953		(7,988	)		(564	)		(401	)		(8,953	)
Ascribed value of shares issued for U.S. royalty interests, net ^(iv)		1,358			—		1,358			—			—			1,358
Provision for impairment ^(v)		(25,990	)		—		—			—			(25,990	)		(25,990	)
Depletion adjustments due to differences in provision for impairment ^(vi)		10,560			—		—			—			10,560			10,560
HTL^tm and GTL development costs expensed, ^(vii)		(5,667	)		—		—			—			(5,667	)		(5,667	)

U.S. GAAP	$	89,292		$	20,383	$	414,769		$	7,139		$	(260,739	)	$	161,169


	As at December 31, 2007
	Assets			Liabilities		Shareholders’ Equity
	Oil and Gas
	Properties and					Share
	Development			Derivative		Capital and			Contributed			Accumulated
	Costs			Instruments		Warrants			Surplus			Deficit			Total

Canadian GAAP	$	111,853		$	9,432	$	347,340		$	9,937		$	(159,990	)	$	197,287
Adjustments for:
Reduction in stated capital ⁽ⁱ⁾		—			—		74,455			—			(74,455	)		—
Accounting for stock based compensation ⁽ⁱⁱ⁾		—			—		(396	)		(3,352	)		3,748			—
Fair value adjustment of warrants ⁽ⁱⁱⁱ⁾		—			5,786		(7,988	)		(564	)		2,766			(5,786	)
Ascribed value of shares issued for U.S. royalty interests, net ^(iv)		1,358			—		1,358			—			—			1,358
Provision for impairment ^(v)		(25,990	)		—		—			—			(25,990	)		(25,990	)
Depletion adjustments due to differences in provision for impairment ^(vi)		9,334			—		—			—			9,334			9,334
HTL^tm and GTL development costs																—
expensed, ^(vii)		(5,658	)		—		—			—			(5,658	)		(5,658	)

U.S. GAAP	$	90,897		$	15,218	$	414,769		$	6,021		$	(250,245	)	$	170,545

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, 2008 and December 31, 2007.

	(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, 2008, and December 31, 2007, 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 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 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, 2008 and 2007.


	(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 2007 Annual Report filed on Form 10-K, in 2006, the accounting treatment of warrants under U.S. GAAP reflects 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 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. This GAAP difference resulted in an increase in derivative instruments of $9.0 million and $5.8 million, a decrease in share capital and warrants of $8.0 million and a decrease in contributed surplus of $0.6 million at March 31, 2008 and December 2007.


	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)	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 estimated future net cash flows from proved oil and gas reserves using period-end, non-escalated prices and costs, discounted to present value at 10% per annum, 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 (c) 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-month period ended March 31, 2008 no impairment provision was required and no impairment provision was required under Canadian GAAP. The cumulative differences in the amount of impairment provisions between U.S. and Canadian GAAP were $26.0 million at March 31, 2008 and December 31, 2007.

	(vi)	The cumulative differences in the amount of impairment provisions between U.S. and Canadian GAAP resulted in a reduction in accumulated depletion of $10.6 million and $9.3 million as at March 31, 2008 and December 31, 2007.

	(vii)	As more fully described in our financial statements in Item 8 of our 2007 Annual Report filed on Form 10-K, for Canadian GAAP, the Company capitalizes certain costs incurred for HTL^tm 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 HTL^tm and GTL development costs. For U.S. GAAP, feasibility, marketing and related costs incurred prior to executing an HTL^tm or GTL definitive agreement are considered to be research and development and are expensed as incurred. As at March 31, 2008 and December 31, 2007, the Company capitalized $5.7 million for Canadian GAAP, which was expensed for U.S. GAAP purposes.


	Deferred Financing Costs

As more fully described in our financial statements in Item 8 of our 2007 Annual Report filed on Form 10-K, for Canadian GAAP the Company accounts for deferred financing costs, or transaction costs, as a reduction from the related liability and accounted for using the effective interest method. For U.S. GAAP purposes, these costs are classified as other assets resulting in an increase of $0.6 million, and $0.7 million, in long-term debt and other assets for U.S. GAAP purposes when compared to Canadian GAAP as at March 31, 2008 and December 31, 2007.


	*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,
	2008						2007
	Net			Net Loss			Net			Net Loss
	Loss			Per Share			Loss			Per Share

Canadian GAAP	$	(8,544	)	$	(0.03	)	$	(6,547	)	$	(0.03	)
Fair value adjustment of warrants ⁽ⁱⁱⁱ⁾		(3,167	)		(0.01	)		(2,192	)		(0.01	)
Depletion adjustments due to differences in provision for impairment ^(viii)		1,226			—			1,303			0.01
HTL^tm and GTL development costs expensed, net of write downs, ^(ix)		(9	)		—			—			—

U.S. GAAP	$	(10,494	)	$	(0.04	)	$	(7,436	)	$	(0.03	)

Weighted Average Number of Shares under U.S. GAAP (in thousands)					244,873						241,231


	(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 $26.0 million as at March 31, 2008 and December 31, 2007. This net increase in U.S. GAAP impairment provisions has resulted in lower depletion rates for U.S. GAAP purposes and a reduction of $1.2 million and $1.3 million in the net losses for the three-month periods ended March 31, 2008 and 2007.

	(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^tm 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, 2008 and 2007, the Company expensed nil in excess of the Canadian GAAP write-downs during those corresponding periods.


	*Condensed Consolidated Statements of Cash Flow*

There would be no material difference in cash flow presentation between Canadian and U.S. GAAP for the three-month periods ended March 31, 2008 and 2007.


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

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). The new standard is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. It is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. Management is currently evaluating the impact of the adoption of this new standard on its financial statements.

In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141(R)”) and Statement of Financial Accounting Standards No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS No. 160”). Effective for fiscal years beginning after December 15, 2008, the standards will improve, simplify, and converge internationally the accounting for business combinations and the reporting of noncontrolling interests in consolidated financial statements. SFAS 141(R) requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 160 requires all entities to report noncontrolling (minority) interests in subsidiaries in the same way—as equity in the consolidated financial statements. Management is currently evaluating the impact of the adoption of these new standards on its financial statements.

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. The Company adopted the provisions of SFAS No. 157 effective January 1, 2008. The implementation of this standard did not have a material impact on the consolidated financial statements as our current policy on accounting for fair value measurements is consistent with this guidance. We have, however, provided additional prescribed disclosures not required under Canadian GAAP.

SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The three levels of the fair value hierarchy are described below:


	Level 1:	Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

	Level 2:	Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.


	Level 3:	Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

As required by SFAS No. 157 when the inputs used to measure fair value fall within different levels of the hierarchy, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measure in its entirety.

The following table presents the company’s fair value hierarchy for those assets and liabilities measured at fair value on a recurring basis as of March 31, 2008.


	As at March 31, 2008
	Level 1		Level 2		Level 3		Total

Derivative instruments liabilities	$	8,953	$	11,430	$	—	$	20,383

The fair value measurement of derivative instruments liabilities related to our costless collars are considered Level 2 and the fair value measurement of derivative instruments liabilities related to our purchase warrants denominated in Cdn.$ are considered Level 1.

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 “anticipate”, “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^tm 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 2007 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, 2007. 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 13.

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 10 of our 2007 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^tm Technology” or “HTL^tm”) 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^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 over long distances. 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 are greater than 85% by volume, and high conversion of the heavy residual fraction is achieved.

HTL^tm 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^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.

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.

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 we focus on the non-conventional heavy oil, both play an important role in Ivanhoe’s corporate strategy.

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 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, 3) the wide heavy-light price differentials that the producer is faced with when the product gets to market, and 4) conventional upgrading technologies limited to very large scale, high capital cost facilities. 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^tm Technology seeks to address the four key heavy oil development challenges outlined above, and can do so at a relatively small minimum economic scale.

Ivanhoe’s HTL^tm upgrading is a partial upgrading process that is designed to operate in facilities as small as 10,000-30,000 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 well over 100,000 barrels per day. Ivanhoe’s HTL^tm Technology is based on carbon rejection, a tried and tested concept in heavy oil processing. The key advantage of HTL^tm is that it is a very fast process — processing times are typically under a few seconds. This results in smaller, less costly facilities and eliminates the need for hydrogen addition, an expensive, large minimum scale step typically required in conventional upgrading. Ivanhoe’s HTL^tm 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^tm process offers significant advantages as a field-located upgrading alternative, integrated with the upstream heavy oil production operation. HTL^tm provides four key benefits to the producer:


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

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

	3.	Capture of the majority of the heavy-light oil value differential.

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

The business opportunities available to Ivanhoe correspond to the challenges each potential heavy oil project faces. In Canada, Ecuador, California, Iraq and Oman, all four of the HTL^tm advantages identified above come into play. In

others, including certain identified opportunities in Colombia and Libya, 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^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 value proposition.

Implementation Strategy

We are an oil and gas company with a unique technology which addresses several major problems confronting the oil and gas industry today. Because we have a unique resource in our patented technology and because we have experienced people who have developed oil fields in the past and are involved in acquiring new resources, we are in a position to work with partners on stranded heavy oil resources around the world to add value to these resources.

In 2007 Ivanhoe completed the HTL^tm equipment and process testing associated with the Commercial Demonstration Facility (“CDF”) in California. Following this work, Ivanhoe’s principal focus has shifted to full scale commercial deployment of HTL^tm facilities. This effort includes the pursuit of opportunities in Canada and elsewhere related to the deployment of full-scale commercial HTL^tm facilities in business arrangements that would provide Ivanhoe with a share of reserves and production of heavy oil. In certain industrial and geographic markets, Ivanhoe is pursuing opportunities where shareholder value can be generated through commercial deployment of HTL^tm in business arrangements that may not include the generation of reserves and production for Ivanhoe.

The Company’s implementation strategy includes the following:


	1.	Build a portfolio of major HTL^tm 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^tm Technology.

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

	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.

	4.	*Build internal capabilities in advance of major projects.* The HTL^tm technical team, which includes our own staff and specialized consultants, including the inventors of the technology, has been expanded to add additional expertise in areas such as engineering, project management and business and project analysis and we are currently actively recruiting other new team members.

	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.

In order to facilitate the implementation of our business strategy, we plan to undertake a reorganization of our corporate, business and governance structures. We will create two new geographically focused business units that will pursue project opportunities in Latin America and the Middle East/North Africa (“MENA”), respectively. These new business units will operate through separate subsidiary companies in much the same way as our China business unit is operated through Sunwing Energy Ltd (“Sunwing”) our wholly owned subsidiary. Like Sunwing, our new Latin America and MENA business units will each have its own board of directors and senior management team. Initially, the Latin America and MENA subsidiaries and Sunwing will remain wholly-owned, and will be funded, by Ivanhoe Energy. It is intended that each subsidiary will eventually become financially independent and, as their respective geographically focused business strategies unfold, that each subsidiary will seek and obtain external sources of capital from third parties that will effectively reduce Ivanhoe Energy’s ownership interest.

Ivanhoe Energy itself will retain ownership of the HTL^tm Technology and will concentrate its business development efforts on project opportunities in North America, with a particular focus on Canada. Our Latin America business unit will continue the pursuit of opportunities to apply the HTL^tm Technology to heavy oil projects in Ecuador, Mexico and elsewhere in Latin America. Our MENA business unit will focus on heavy oil project opportunities in the Middle East/North Africa region, with a particular focus on Iraq, Egypt and Libya. It will also be responsible for advancing our GTL project opportunity in Egypt. Sunwing will continue to operate our existing EOR and exploration projects in China and to pursue business development initiatives in the East Asia region. Each of our Latin America, MENA and East Asia

business units will have the exclusive right within its own defined geographical region to obtain from Ivanhoe Energy a project-specific site license of the HTL^tm Technology as and when the decision is made to develop an HTL^tm project.

Executive Overview of 2008 Results

The following table sets forth certain selected consolidated data for the three-month periods ended March 31, 2008 and 2007:


	Three-Month Periods Ended March 31,
	2008			2007

Oil and gas revenue	$	15,043		$	9,596
Net loss	$	(8,544	)	$	(6,547	)
Net loss per share	$	(0.03	)	$	(0.03	)
Average production (Boe/d)		1,907			2,035
Net operating revenue per Boe	$	55.60		$	32.27
Cash flow from operating activities	$	3,017		$	2,594
Capital investments	$	5,323		$	5,334

Financial Results — Change in Net Loss

The following provides an analysis of our changes in net losses for the three-month period ended March 31, 2008 when compared to the same period for 2007:


	Three-Month Periods Ended March 31,
				Favorable
				(Unfavorable)
	2008			Variances			2007
Summary of Net Loss by Significant Components:
Oil and Gas Revenues:	$	15,043					$	9,596
Production volumes				$	(473	)
Oil and gas prices					5,920
Realized gain (loss) on derivative instruments		(1,948	)		(2,155	)		207
Operating costs		(5,392	)		(1,707	)		(3,685	)
General and administrative, less stock based compensation		(2,758	)		(599	)		(2,159	)
Business and technology development, less stock based compensation		(1,546	)		527			(2,073	)
Net interest		(346	)		(327	)		(19	)
Unrealized loss on derivative instruments		(1,998	)		(1,332	)		(666	)
Depletion and depreciation		(8,366	)		(1,474	)		(6,892	)
Stock based compensation		(1,118	)		(316	)		(802	)
Other		(115	)		(61	)		(54	)

Net Loss	$	(8,544	)	$	(1,997	)	$	(6,547	)

Our net loss for the three-month period ended March 31, 2008 was $8.5 million ($0.03 per share) compared to our net loss for the same period in 2007 of $6.5 million ($0.03 per share). The increase in our net loss from 2007 to 2008 of $2.0 million was due to an increase in operating costs of $1.7 million, a $1.3 million increase in unrealized loss on derivative instruments and a $1.5 million increase for depletion and depreciation. These increases were partially offset by an increase of $3.3 million in combined oil and gas revenues and realized loss on derivative instruments.

Significant variances are explained in the sections that follow.

Revenues and Operating Costs

The following is a comparison of changes in production volumes for the three-month period ended March 31, 2008 when compared to the same period in 2007:


	Three-Month Periods Ended March 31,
	Net Boe’s				Percentage
	2008		2007		Change

China:
Dagang		119,828		120,676		(1	)%
Daqing		5,143		5,640		(9	)%

		124,971		126,316		(1	)%

U.S.:
South Midway		43,677		51,773		(16	)%
Spraberry		4,508		4,694		(4	)%
Others		416		378		10	%

		48,601		56,845		(15	)%

		173,572		183,161		(5	)%

Net production volumes for the three-month period ended March 31, 2008 decreased 5% when compared to the same period in 2007 mainly due to decreases in production volumes in our U.S. properties of 15%, resulting in decreased revenues of $0.5 million.

Oil and gas prices increased 54% per Boe for the three-month period ended March 31, 2008 generating $5.9 million in additional revenue as compared to the same period in 2007. We realized an average of $87.12 per Boe from operations in China during this period, which was an increase of $32.61 per Boe from 2007 prices and accounted for $4.1 million of our increase in revenues. From the U.S. operations, we realized an average of $85.49 per Boe during this period, which was an increase of $30.98 per Boe and accounted for $1.8 million of our increased revenues. We expect crude oil prices and natural gas prices to remain volatile throughout 2008.

The increased revenues from oil and gas price increases during the three-month period ended March 31, 2008 were offset by settlements from our costless collar derivative instruments. As benchmark prices rise above the ceiling price established in the contract the Company is required to settle monthly (see further details on these contracts below under “Unrealized Loss on Derivative Instruments”). The Company realized a net loss on these settlements during this period of $1.9 million, $1.2 million of which was from the U.S. segment, the balance from the China segment. This compares to a net realized gain in the same period in 2007 of $0.2 million on U.S. contracts.

For the three-month period ended March 31, 2008, operating costs, including production taxes and engineering and support costs, increased 10.95, or 54%, per Boe compared to the same period in 2007. Of the total $1.7 million increase in these costs, $1.5 million was a result of the Windfall Levy which is explained in more detail below under the China — Operating Costs section.

China


	•	Production Volumes

Overall, net production volumes at the Dagang field during the three-month period ended March 31, 2008 were consistent with those for the same period in 2007. Normal field decline was offset by the production of 236 Gross Bopd from five new development wells completed and put on production in the second half of 2007. We expect that additional perforations, fracture stimulations and water flooding will help offset declines due to increasing water production in 2008. The expected production rates for 2008 will be similar to those averaged in 2007.


	•	Operating Costs

Operating costs in China, including engineering and support costs and Windfall Levy, increased 75% or $14.81 per Boe during the three-month period ended March 31, 2008 when compared to the same period in 2007. Field operating costs increased $2.17 per Boe. In addition to higher power costs resulting from more water injection in the first quarter of 2008 when compared to the same period in 2007, we incurred higher service rig costs in 2008 due to the timing of downhole maintenance. As well, a higher percentage of field office costs were allocated to operations versus capital as

capital activity has decreased. Enterprises exploiting and selling crude oil in the Peoples Republic of China are subject to a windfall gain levy (the “Windfall 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. Consequently as oil prices increased quarter over quarter the amount of the Windfall Levy also increased significantly, resulting in a $12.75 per Boe increase for 2008 when compared to the same period in 2007. With the exception of the Windfall Levy, we expect costs during the remainder of 2008 to remain consistent on a per barrel basis as compared to 2007. Decreases resulting from one-time maintenance projects in 2007 and the ability to charge CNPC for its share of operating costs, expected to be mid-way through 2008 once we reach “commercial production”, will be offset by an increase in office costs allocated to operations as we continue to reduce the number of capital projects.

U.S.


	•	Production Volumes

The 15% decrease in U.S. production volumes for the three-month period ended March 31, 2008 when compared to the same period in 2007 was mainly due to a decline at South Midway which resulted from the timing of drilling programs. The 2006 fall drilling program resulted in an increase in the first quarter of 2007 production, and we expect that the results from the 2008 first quarter drilling program will be reflected in the second and third quarters of 2008. In addition to an increase in production in 2008 due to abnormal downtimes in our steaming operations in 2007, we expect the current drilling program at South Midway to offset natural declines within this field and to provide additional future drilling locations.


	•	Operating Costs

Operating costs in the U.S., including engineering and support costs and production taxes, increased 5% or $1.13 per Boe for the three-month period ended March 31, 2008 when compared to the same period in 2007. Field operating costs increased $1.34 per Boe mainly due to an increase in our steaming operation at South Midway. Both generators were down in the latter part of the first quarter of 2007 in addition to the price of natural gas being significantly higher in 2008 when compared to 2007. This increase was offset by a decrease to maintenance costs and workovers at both South Midway and Spraberry. We anticipate operating expense to continue to increase in 2008 mainly as a result of the steaming operations at South Midway operating at full capacity versus a reduced capacity in 2007. We expect the 2008 operating costs at Spraberry to be consistent with 2007.

* * *

Production and operating information including oil and gas revenue, operating costs and depletion, on a per Boe basis are detailed below:


	Three-Month Periods Ended March 31,
	2008						2007
	China		U.S.		Total		China			U.S.			Total

Net Production:
Boe		124,971		48,601		173,572		126,316			56,845			183,161
Boe/day for the period		1,373		534		1,907		1,403			632			2,035


	Per Boe						Per Boe
Oil and gas revenue	$	87.12	$	85.49	$	86.67	$	54.51		$	47.69		$	52.39

Field operating costs		16.95		16.06		16.71		14.78			14.72			14.76
Production tax (U.S.) and Windfall Levy (China)		16.49		1.50		12.29		3.75			1.21			2.96
Engineering and support costs		1.04		4.71		2.07		1.14			5.21			2.40

		34.48		22.27		31.07		19.67			21.14			20.12

Net operating revenue		52.64		63.22		55.60		34.84			26.55			32.27
Depletion		49.66		29.79		44.10		37.41			28.19			34.55

Net revenue (loss) from operations	$	2.98	$	33.43	$	11.50	$	(2.57	)	$	(1.64	)	$	(2.28	)

General and Administrative

Changes in general and administrative expenses, before and after considering increases in non-cash stock based compensation, by segment for the three-month period ended March 31, 2008 when compared to the same period for 2007 were as follows:


	2008 vs.
	2007

Favorable (unfavorable) variances:
Oil and Gas Activities:
China	$	(159	)
U.S.		26
Corporate		(660	)

		(793	)
Less: stock based compensation		194

	$	(599	)

China

General and administrative expenses related to the China operations increased $0.2 million for the three-month period ended March 31, 2008 when compared to the same period in 2007 partially due to an increase in rent and facility costs and partially due to foreign exchange loss.

Corporate

General and administrative costs related to Corporate activities increased $0.7 million for the three-month period ended March 31, 2008 when compared to the same period in 2007. The increase for 2008 was partially due to a $0.2 million increase in salaries and benefits resulting from an increase in stock based compensation and the addition of key personnel added later in 2007 offset by a decrease resulting from discretionary bonuses paid in 2007. In addition, various corporate overhead costs increased $0.2 million and third party recruiting fees increased by $0.3 million.

Business and Technology Development

Changes in business and technology development expenses, before and after considering increases in non-cash stock based compensation, by segment for the three-month period ended March 31, 2008 when compared to the same period for 2007 were as follows:


	2008 vs.
	2007

Favorable (unfavorable) variances:
HTL^tm	$	297
GTL		108

		405
Less: stock based compensation		122

	$	527

Business and technology development expenses decreased $0.4 million for the three-month period ended March 31, 2008 compared to the same period in 2007 mainly as a result of a decrease in CDF operating costs due to two significant heavy oil upgrading runs in the first quarter of 2007.

Net Interest

Interest expense increased $0.3 million for the three-month period ended March 31, 2008 when compared to the same period in 2007 partially due to an additional draw on our U.S. loan and borrowings under a new loan for our China operations.

Unrealized Loss on Derivative Instruments

As required by the Company’s lenders, the Company entered into costless collar derivatives to minimize variability in its cash flow from the sale of approximately 75% of the Company’s estimated production from its South Midway property in California and Spraberry property in West Texas over a two-year period starting November 2006 and a six-month period starting November 2008. The derivatives have a ceiling price of $65.20, and $70.08, per barrel and a floor price of $63.20, and $65.00, per barrel, respectively, using WTI as the index traded on the NYMEX. The Company’s lenders also required the Company to enter into a costless collar derivative to minimize variability in its cash flow from the sale of approximately 50% of the Company’s estimated production from its Dagang field in China over a three-year period starting September 2007. This derivative has a ceiling price of $84.50 per barrel and a floor price of $55.00 per barrel using WTI as the index traded on the NYMEX.

The Company accounts for these contracts using mark-to-market accounting. As forecasted benchmark prices exceed the ceiling prices set in the contract, the contracts have negative value or a liability. These benchmark prices reached record highs in the latter part of 2007. For the three-month period ended March 31, 2008, the Company had minimal unrealized losses in its U.S. segment and $2.0 million unrealized losses in its China segment on these derivative transactions. The $0.2 million unrealized gain for the same period in 2007 was related to the U.S. segment.

Depletion and Depreciation

Depletion and depreciation increased $1.5 million for the three-month period ended March 31, 2008 when compared to the same period in 2007 partially due to a $0.2 million increase in depreciation of the CDF and a $1.5 million increase in depletion related to depletion rates for China offset by a decrease in depletion of $0.2 million related to production in the U.S.

China

China’s depletion rate increased $12.25 per Boe for the three-month period ended March 31, 2008 when compared to the same period in 2007. This resulted in a $1.5 million increase in depletion expense for the three-month period ended March 31, 2008. The increase in the rates from period to period was mainly due to an impairment of the drilling and completion costs associated with the second Zitong exploration well in the fourth quarter of 2007.

Financial Condition, Liquidity and Capital Resources

Sources and Uses of Cash

Our net cash and cash equivalents decreased for the three-month period ended March 31, 2008 by $4.7 million compared to $3.1 million for the same period in 2007.

Operating Activities

Our operating activities provided $3.0 million in cash for the three-month period ended March 31, 2008 compared to $2.6 million for the same period in 2007. The increase in cash from operating activities for the three-month period ended March 31, 2008 was mainly due to an increase in oil and gas production prices offset by an increase in expenses.

Investing Activities

Our investing activities used $6.5 million in cash for the three-month period ended March 31, 2008 compared to $5.1 million for the same period in 2007. The main reason for the increase is that we received $1.0 million in proceeds from the sale of assets in 2007 compared to nil in 2008.

Capital asset expenditures remained the same quarter over quarter. An overall decrease in our investment in China of $1.7 million was offset by an increase of $1.7 million in our investment in the U.S. The decrease in our investment in China was the result of a $2.8 million decrease in capital spending at Zitong offset by a $1.1 million increase in capital spending at Dagang. Our spending at Zitong during the first quarter of 2008 was limited to expenditures relating to the commencement of the second phase of our exploration program, which were relatively minor compared to the drilling and completion costs we incurred during 2007 in completing the first phase of the program, which was concluded in December 2007. At Dagang, we increased capital spending during 2008 over the same period in 2007 by completing several fracture stimulation jobs. Likewise, the increase in our U.S. capital spending in 2008 compared to 2007 was attributable to the expenditures we incurred in carrying out an 8 well drilling program at South Midway. Overall expenditures for the HTL^tm segment were unchanged. Increased costs related to the Feedstock Test Facility were offset by decreased costs related to the CDF as all significant modifications to that facility have been completed.

Financing Activities

Financing activities for the three-month periods ended March 31, 2008 and 2007 consisted of scheduled repayment of long-term debt in the amount of $0.6 million. In addition, there were $0.6 million in professional fees and expenses associated with the pursuit of corporate financing initiatives by the Company’s Chinese subsidiary, Sunwing, in 2008.

Outlook for balance of 2008

The Company intends to utilize revenue from existing operations to fund the transition of the Company to a heavy oil exploration, production and upgrading company and grow our existing operations where appropriate to sustain operating cash flow and our financial position. In addition, the Company is actively engaged in the process of leveraging or monetizing the non-heavy oil related investments in our portfolio, including bank and similar financing, to capture value and provide maximum return for the Company. The Company currently anticipates incurring substantial expenditures to further its capital investment programs and 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. Recovery of capitalized costs related to potential HTL^tm and GTL projects is dependent upon finalizing definitive agreements for, and successful completion of, the various projects. Management’s plans also include alliances or other arrangements with entities with the resources to support the Company’s projects as well as project financing, debt and mezzanine financing or the sale of equity securities in order to generate sufficient resources to assure continuation of the Company’s operations and achieve its capital investment objectives.

Contractual Obligations

The table below summarizes the contractual obligations that are reflected in our Unaudited Condensed Consolidated Balance Sheet as at March 31, 2008 and/or disclosed in the accompanying Notes:


	Payments Due by Year
	Total		2008		2009		2010		2011		After 2011
	(stated in thousands of U.S. dollars)

Consolidated Balance Sheets:
Note payable — current portion		6,612		6,612		—		—		—		—
Long term debt		9,448		—		—		9,448		—		—
Asset retirement obligation		2,469		—		763		—		—		1,706
Long term obligation		1,900		—		1,900		—		—		—
Other Commitments:												—
Interest payable		3,136		1,129		1,130		877		—		—
Lease commitments		3,225		884		890		770		546		135
Zitong exploration commitment		22,500		4,500		9,000		9,000		—		—

Total	$	49,290	$	13,125	$	13,683	$	20,095	$	546	$	1,841

Off Balance Sheet Arrangements

As at March 31, 2008 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. We currently 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 1, 2008, there were 245,260,226 common shares of the Company issued and outstanding. Additionally, the Company had 22,396,330 share purchase warrants outstanding and exercisable to purchase 22,396,330 common shares. As at May 1, 2008, there were 15,603,764 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
	2008			2007												2006
	1st Qtr			4th Qtr			3rd Qtr			2nd Qtr			1st Qtr			4th Qtr			3rd Qtr			2nd Qtr

Total revenue	$	11,169		$	5,848		$	8,823		$	9,589		$	9,257		$	11,137		$	14,015		$	13,084
Net loss:
Canadian GAAP	$	(8,544	)	$	(18,849	)	$	(7,232	)	$	(6,579	)	$	(6,547	)	$	(11,323	)	$	(4,388	)	$	(4,405	)
U.S. GAAP	$	(10,495	)	$	(16,094	)	$	(8,387	)	$	(1,211	)	$	(7,536	)	$	(18,255	)	$	(5,422	)	$	(2,329	)
Net loss per share:
Canadian GAAP	$	(0.03	)	$	(0.07	)	$	(0.03	)	$	(0.03	)	$	(0.03	)	$	(0.05	)	$	(0.02	)	$	(0.02	)
U.S. GAAP	$	(0.04	)	$	(0.07	)	$	(0.01	)	$	—		$	(0.03	)	$	(0.08	)	$	(0.03	)	$	(0.01	)

The differences in the net loss and net loss per share for the third quarter of 2006 were due mainly to the impairment charged for the U.S. Oil and Gas Properties for U.S. GAAP purposes of $3.1 million when compared to nil calculated for Canadian GAAP, offset by a $1.7 million additional fair value adjustment of derivative instruments for U.S. GAAP. The differences in the net loss and net loss per share for the fourth quarter of 2006 were due mainly to the impairment charged for U.S. GAAP purposes of $8.1 million ($4.5 million relates to the U.S. Oil and Gas Properties and $3.6 million for the China Oil and Gas Properties) when compared to nil calculated for Canadian GAAP. The differences in the net loss and net loss per share for the second quarter of 2007 were due mainly to the treatment of the payment by INPEX for past costs paid by the Company related to its Iraq project and HTL^tm Technology development costs. Approximately $6.3 million of this payment was applied to capital balances for Canadian GAAP purposes and as reduction to net loss for U.S. GAAP purposes. The differences in the net loss and net loss per share for the third quarter of 2007 were mainly due to an additional $3.6 million fair value adjustment of derivative instruments for U.S. GAAP.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Commodity price risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to the changes in market commodity prices. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Company may periodically use different types of derivative instruments to manage its exposure to price volatility and as well as a result of a requirement of the Company’s lenders.

On March 31, 2008, the Company’s open positions on the derivatives referred to above had a fair value of $11.4 million. A 10% increase in oil prices would increase the fair value by approximately $4.8 million, while a 10% decrease in prices would reduce the fair value by approximately $4.4 million. The fair value change assumes volatility based on prevailing market parameters at March 31, 2008.

Foreign Currency Exchange Rate Risk

Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The majority of the operating costs incurred in our Chinese operations are paid in Chinese renminbi. The majority of costs incurred in our administrative offices in Vancouver and Calgary, as well as some business development costs, are paid in Canadian dollars. Disbursement transactions denominated in Chinese renminbi and Canadian dollars are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date. Foreign currency gains and losses also come about when monetary assets and liabilities, mainly short term payables and receivables, denominated in foreign currencies are translated at the end of each month. The estimated impact of a 10% strengthening or weakening of the Chinese renminbi, and Canadian dollar, as of March 31, 2008 on net loss and accumulated deficit for the three-month period ended March 31, 2008 is a $0.2 million increase, and a $0.2 million decrease, respectively. To help reduce our exposure to foreign currency risk we seek to maximize our expenditures and contracts denominated in U.S. dollars and minimize those denominated in other currencies.

Interest Rate Risk

Item 4. Controls and Procedures

The Company’s management, including our 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, 2008. 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 period ended March 31, 2008, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II — Other Information

Item 1. Legal Proceedings: None

Item 1A. Risk Factors: As at March 31, 2008, there were no additional material risks and no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds: None

Item 3. Defaults Upon Senior Securities: None

Item 4. Submission of Matters To a Vote of Security Holders: None

Item 5. Other Information: None

Item 6. Exhibits


EXHIBIT
NUMBER			DESCRIPTION

	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/ W. Gordon Lancaster

Name: W. Gordon Lancaster

Title: Chief Financial Officer

Dated: May 1, 2008

INDEX TO EXHIBITS


Exhibit
Number			Description

	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