Edgar Filing: IVANHOE ENERGY INC

Form 10-Q

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 September 30, 2008


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		98-0372413
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

Suite 654 — 999 Canada Place
Vancouver, British Columbia, Canada		V6C 3E1
(Address of principal executive office)		(zip code)

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

No Changes
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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	Smaller reporting company o
		(Do not check if a smaller reporting company)

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 November 3, 2008 was 279,211,916 Common Shares, no par value.

TABLE OF CONTENTS


		Page
PART I	Financial Information

Item 1	Financial Statements

	Unaudited Condensed Consolidated Balance Sheets as at September 30, 2008 and December 31, 2007	3

	Unaudited Condensed Consolidated Statements of Operations, Comprehensive Income (Loss) and Accumulated Deficit for the Three-Month and Nine-Month Periods Ended September 30, 2008 and 2007	4

	Unaudited Condensed Consolidated Statements of Cash Flows for the Three-Month and Nine-Month Periods Ended September 30, 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	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40

Item 4.	Controls and Procedures	42

PART II	Other Information

Item 1.	Legal Proceedings	43

Item 1A.	Risk Factors	43

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

Item 3.	Defaults Upon Senior Securities	46

Item 4.	Submission of Matters to a Vote of Security Holders	46

Item 5.	Other Information	46

Item 6.	Exhibits	46

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)


	September 30, 2008			December 31, 2007
Assets
Current Assets:
Cash and cash equivalents	$	61,649		$	11,356
Accounts receivable		13,811			9,376
Advance		—			825
Prepaid and other current assets		485			602
Future income tax assets		1,161			—

		77,106			22,159

Oil and gas properties and development costs, net		179,641			111,853
Intangible assets — technology		102,153			102,153
Long term assets		4,104			751

	$	363,004		$	236,916


Liabilities and Shareholders’ Equity
Current Liabilities:
Accounts payable and accrued liabilities	$	13,074		$	9,538
Income tax payable		358			—
Debt — current portion		18,111			6,729
Derivative instruments		9,310			9,432

		40,853			25,699

Long term debt		45,640			9,812
Asset retirement obligations		3,673			2,218
Long term obligation		1,900			1,900

		92,066			39,629


Commitments and contingencies

Shareholders’ Equity:
Share capital, issued 279,211,916 common shares; December 31, 2007 244,873,349 common shares		413,918			324,262
Purchase warrants		18,805			23,078
Contributed surplus		16,332			9,937
Convertible note		2,086			—
Accumulated deficit		(180,203	)		(159,990	)

		270,938			197,287

	$	363,004		$	236,916

(See accompanying notes)

IVANHOE ENERGY INC.

Unaudited Condensed Consolidated Statements of Operations,
Comprehensive Income (Loss) and Accumulated Deficit
(stated in thousands of U.S. Dollars, except per share amounts)


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Revenue
Oil and gas revenue	$	20,437		$	10,864		$	53,459		$	30,249
Gain (loss) on derivative instruments		14,818			(2,153	)		(9,915	)		(2,928	)
Interest income		371			112			479			348

		35,626			8,823			44,023			27,669


Expenses
Operating costs		8,211			4,266			20,217			12,174
General and administrative		5,255			2,725			13,749			8,981
Business and technology development		1,969			2,831			4,889			7,341
Depletion and depreciation		8,183			6,044			24,678			18,960
Interest expense and financing costs		463			189			1,500			571

		24,081			16,055			65,033			48,027


Income (Loss) before Income Taxes		11,545			(7,232	)		(21,010	)		(20,358	)


(Provision for) recovery of income taxes
Current		(358	)		—			(364	)		—
Future		(1,125	)		—			1,161			—

		(1,483	)		—			797			—


Net Income (Loss) and Comprehensive Income (Loss)		10,062			(7,232	)		(20,213	)		(20,358	)
Accumulated Deficit, beginning of period		(190,265	)		(133,909	)		(159,990	)		(120,783	)

Accumulated Deficit, end of period	$	(180,203	)	$	(141,141	)	$	(180,203	)	$	(141,141	)


Net Income (Loss) per share — Basic and Diluted	$	0.04		$	(0.03	)	$	(0.08	)	$	(0.08	)


Weighted Average Number of Shares (in thousands)

Basic		265,372			242,747			251,907			241,812

Diluted		279,641			242,747			251,907			241,812

(See accompanying notes)

IVANHOE ENERGY INC.

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


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Operating Activities
Net income (loss) and comprehensive income (loss)	$	10,062		$	(7,232	)	$	(20,213	)	$	(20,358	)
Items not requiring use of cash:
Depletion and depreciation		8,183			6,044			24,678			18,960
Stock based compensation		1,114			758			3,025			2,613
Unrealized (gain) loss on derivative instruments		(18,553	)		1,730			(122	)		2,682
Unrealized foreign exchange loss		314			—			397			—
Future income tax provision (recovery)		1,125			—			(1,161	)		—
Provision for uncollectible accounts		725			—			725			—
Other		238			151			697			481
Changes in non-cash working capital items		(1,535	)		315			(627	)		188

		1,673			1,766			7,399			4,566


Investing Activities
Capital investments		(8,956	)		(9,100	)		(16,872	)		(22,557	)
Acquisition of oil and gas assets		(22,308	)		—			(22,308	)		—
Proceeds from sale of assets		—			—			100			1,000
Recovery of development costs		—			—			—			9,000
Advance repayments		—			—			100			400
Other		(714	)		(47	)		(817	)		28
Changes in non-cash working capital items		2,869			2,189			337			695

		(29,109	)		(6,958	)		(39,460	)		(11,434	)


Financing Activities
Shares issued on private placements, net of share issue costs		82,687			—			82,687			—
Proceeds from exercise of options		518			113			1,204			278
Proceeds from debt obligations, net of financing costs		—			9,335			5,490			9,335
Payments of debt obligations		(615	)		(615	)		(1,845	)		(1,845	)
Payments of deferred financing costs		(542	)		—			(2,606	)		—
Other		—			62			—			—
Changes in non-cash working capital items		(711	)		—			(9	)		—

		81,337			8,895			84,921			7,768



Foreign Exchange Loss on Cash and Cash Equivalents Held in a Foreign Currency		(2,466	)		—			(2,567	)		—


Increase in Cash and Cash Equivalents, for the period		51,435			3,703			50,293			900
Cash and cash equivalents, beginning of period		10,214			11,076			11,356			13,879

Cash and Cash Equivalents, end of period	$	61,649		$	14,779		$	61,649		$	14,779

(See accompanying notes)

Notes to the Condensed Consolidated Financial Statements
September 30, 2008
(all tabular amounts are expressed in thousands of U.S. dollars except per share amounts)
(Unaudited)

1. 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 16. 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 currently anticipates incurring substantial expenditures to further its capital development programs, particularly those related to the development of two recently acquired oil sands leases in Alberta and the development of a heavy oil field in Ecuador under a recently announced specific services contract with the state oil company of Ecuador. The continued existence of the Company is dependent upon its ability to obtain capital to fund further development and to meet obligations to preserve its interests in these properties and to meet the obligations associated with other potential HTL™ and GTL projects. The Company intends to finance the future payments required for its capital projects from a combination of strategic investors and/or traditional debt and equity markets, either at a parent company level or at the project level. The Company believes that it has sufficient funds to reach final investment decisions on its projects, however significant amounts of new capital will be required. These interim condensed consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles applicable to a going concern, which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities in the normal course of operations. If the going concern assumption was not appropriate for these condensed consolidated financial statements, then adjustments would be necessary to the carrying values of assets and liabilities, the reported expenses and the balance sheet classifications used.

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 Handbook Section.3861 “Financial Instruments — Disclosure and Presentation”. The Company 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 as a result of having adopted these standards.

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”. 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. Also in February 2008, the CICA amended portions of Handbook Section 1000, “Financial Statement Concepts”, which the CICA concluded permitted deferral of costs that did not meet the definition of an asset. The amendments apply to annual and interim financial statements relating to fiscal years beginning on or after October 1, 2008. Upon adoption of S.3064 and the amendments to Section 1000 on January 1, 2009, capitalized amounts that no longer meet the definition of an asset will be expensed retrospectively. The Company is currently reviewing the potential impact, if any, on its consolidated statements.

Convergence of Canadian GAAP with International Financial Reporting Standards

In April 2008, the CICA published the exposure draft “Adopting IFRSs in Canada”. The exposure draft proposes to incorporate International Financial Reporting Standards (“IFRS”) into the CICA Accounting Handbook effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. At this date, publicly accountable enterprises will be required to prepare financial statements in accordance with IFRS. The Company is currently reviewing the standards to determine the potential impact on its consolidated financial statements.

3. OIL AND GAS PROPERTIES AND DEVELOPMENT COSTS

The Company has four reportable business segments: Oil and Gas — Integrated, Oil and Gas - Conventional, Business and Technology Development and Corporate as further described in Note 9. These segments are different than those reported in the Company’s previous financial statements included in its Form 10-Qs and Form 10-Ks and as such the presentation has been changed to conform to the new segments.


	As at September 30, 2008
	Oil and Gas									Business and
	Integrated			Conventional						Technology
	Canada			China			U.S.			Development			Total
Oil and Gas Properties:
Proved	$	—		$	139,313		$	110,914		$	—		$	250,227
Unproved		78,348			4,197			4,394			—			86,939

		78,348			143,510			115,308			—			337,166
Accumulated depletion		—			(76,461	)		(31,877	)		—			(108,338	)
Accumulated provision for impairment		—			(16,550	)		(50,350	)		—			(66,900	)

		78,348			50,499			33,081			—			161,928

Development Costs:
Feasibility studies and other deferred costs		—			—			—			5,592			5,592
Feedstock test facility		—			—			—			7,902			7,902
Commercial demonstration facility		—			—			—			11,037			11,037
Accumulated depreciation		—			—			—			(7,095	)		(7,095	)

		—			—			—			17,436			17,436

Furniture and equipment		14			120			537			270			941
Accumulated depreciation		(5	)		(92	)		(467	)		(100	)		(664	)

		9			28			70			170			277

	$	78,357		$	50,527		$	33,151		$	17,606		$	179,641


	As at December 31, 2007
	Oil and Gas						Business and
	Conventional						Technology
	China			U.S.			Development			Total
Oil and Gas Properties:
Proved	$	134,648		$	107,040		$	—		$	241,688
Unproved		3,297			4,373			—			7,670

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

		62,812			33,972			—			96,784

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

		—			—			14,911			14,911

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

		42			80			36			158

	$	62,854		$	34,052		$	14,947		$	111,853

Costs as at September 30, 2008 of $86.9 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 the depletion calculation are $15.2 million for future development costs associated with proven undeveloped reserves as at September 30, 2008 ($8.9 million at December 31, 2007).

For the three-month and nine-month periods ended September 30, 2008, general and administrative expenses related directly to oil and gas acquisition, exploration and development activities of $0.7 million and $1.9 million ($0.7 million and $2.5 million for those same periods in 2007) were capitalized.

For both the three-month and nine-month periods ended September 30, 2008, interest on debt related to oil and gas acquisition activities of $0.8 million (nil for the same periods in 2007) was 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 September 30, 2008 and December 31, 2007 was $92.2 million. Since the Company acquired the technology, it has continued to expand its patent coverage to protect innovations to the HTL™ Technology as they are developed and to significantly extend the Company’s portfolio of HTL™ intellectual property. The Company is the assignee of three granted patents and currently has five patent applications pending in the U.S. The Company also has multiple patents pending in numerous other countries.

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 September 30, 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 and nine-month periods ended September 30, 2008 and 2007.

5. LONG TERM DEBT

Notes payable consisted of the following as at:


	September 30,			December 31,
	2008			2007
Variable rate bank note, (5.61% at September 30, 2008), due April 2009	$	5,200		$	4,500
Variable rate bank note (6.54% at September 30, 2008) due September 2010		10,000			10,000
Non-interest bearing promissory note, due 2006 through 2009		1,031			2,876
Convertible note (6.75% at September 30, 2008) due July 2011		38,106			—
Promissory note (6.75% at September 30, 2008) due December 2008		11,908			—

		66,245			17,376


Less:
Unamortized discount		(2,024	)		(139	)
Unamortized deferred financing costs		(470	)		(696	)
Current maturities		(18,111	)		(6,729	)

		(20,605	)		(7,564	)

	$	45,640		$	9,812

Bank Loan

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. In October 2008, the original due date of the revolving facility of October 2008 was extended to April 2009 and $5.2 million was outstanding at September 30, 2008.

Promissory Note

In connection with the acquisition in July 2008 described in Note 14, the Company issued a promissory note to Talisman Energy Canada (“Talisman”) in the principal amount of Cdn.$12.5 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated daily and not compounded, and maturing on December 31, 2008 (the “2008 Note”).

Convertible Note

Also in connection with the acquisition in July 2008, the Company issued a convertible promissory note to Talisman in the principal amount of Cdn.$40.0 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated daily and not compounded, and payable semi-annually, maturing in July 2011 and convertible (as to the outstanding principal amount), at Talisman’s option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per common share (the “Convertible Note”). There were no conversions of this note in the three-month period ended September 30, 2008.

Under Canadian GAAP, the Convertible Note should be assessed based on the substance of the contractual arrangement in determining whether it exhibits the fundamental characteristic of a financial liability or equity. Management has assessed that this debenture instrument mainly exhibits characteristics that are liability in nature, however, the embedded conversion feature is equity in nature and is required to be bifurcated and disclosed separately within shareholders’ equity. Management has applied residual basis and has valued the liability component first and assigned the residual value to the equity component. Management has fair valued the liability component by discounting the expected interest and principal payments using an interest rate of 8.75% being management’s estimate of the expected interest payments for a similar instrument without the conversion feature. The liability component was valued at Cdn.$37.9 and the remaining balance of Cdn.$2.1 was allocated to the equity component. The liability component will be accreted over the three-year maturity period to bring the liability back to Cdn.$40,000,000 using the effective interest method.

The Company’s obligations under the 2008 Note, the Convertible Note and the Contingent Payment (see Note 14) are secured by a first fixed charge and security interest in favor of Talisman against the acquired Talisman leases and the related assets acquired by the Company pursuant to the Talisman lease acquisition, and a subordinate security interest in and to all other present and after-acquired property of the Company other than the shares of any subsidiary of Ivanhoe Energy. The Talisman security interest also does not extend to any assets of any subsidiary of Ivanhoe Energy.

The scheduled maturities of the Company’s long term debt, excluding unamortized discount and unamortized deferred financing costs, as at September 30, 2008 were as follows:


2008		12,523
2009		5,616
2010		10,000
2011		38,106

	$	66,245

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 September 30, 2008 was estimated at $6.3 million. These payments are expected to be made over the next 30 years; with over half of the payments between 2010 and 2025. 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%. A reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties and the CDF were as follows:


	As at		As at
	September, 30		December, 31
	2008		2007
Carrying balance, beginning of year	$	2,218	$	1,953
Liabilities incurred		219		20
Liabilities settled		—		(792	)
Accretion expense		101		119
Revisions in estimated cash flows		1,135		918

Carrying balance, end of period	$	3,673	$	2,218

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 the drilling of approximately 23,700 feet of new wellbore, (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 and no further seismic acquisition is required by the contract. 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 and perform an impairment assessment on the costs incurred to date. The May 2008 earthquake in China’s Sichuan Province resulted in some delays in analyzing and reviewing geophysical data. The Company will be evaluating whether these delays will prohibit it from completing the work program within the required time frame and address whether or not an extension of that time frame is needed in the near future. 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 in its net operating losses available for carry-forward in the various jurisdictions in which the Company operates. While the Company believes its tax filings do not include uncertain tax positions, except as noted below, the results of potential audits or the effect of changes in tax law cannot be ascertained at this time.

The Company has an uncertain tax position related to when its entitlement to take tax deductions associated with development costs commenced. In March 2007, the Company received a preliminary indication from local Chinese tax authorities as to a potential change in the rule under which development costs are deducted from taxable income effective for the 2006 tax year. The Company discussed this matter with Chinese tax authorities and subsequently filed its 2006 tax return for Sunwing’s wholly-owned subsidiary Pan-China Resources Ltd. (“Pan-China”) taking a new filing position in which development costs are capitalized and amortized on a straight line basis over six years starting in the year the development costs are incurred rather than deducted in their entirety in the year incurred. This change resulted in a $50.3 million reduction in tax loss carry-forwards in 2007 with an equivalent increase in the tax basis of development costs available for application against future Chinese income. The Company has received no formal notification of this rule change, however it will continue to file tax returns under this new approach. To the extent that there is a different interpretation in the timing of the deductibility of development costs this could potentially result in an increase in the current tax provision of $1.9 million.

The Company has an uncertain tax position related to the calculation of a gain on the consideration received from two farm-out transactions (Richfirst January 2004 — see Note 5 and Mitsubishi January 2006 — see under Zitong Block Exploration Commitment in this Note 7) and the designation of whether the taxable gains may be subject to a withholding tax of 10% pursuant to Chinese tax law for income derived by a foreign entity. The Company is waiting for the Chinese tax authorities to reply to its request to validate in writing that its current treatment of such tax position is appropriate. To the extent that the calculation of a gain is interpreted differently and the amounts are subject to withholding tax there would be an additional current tax provision of approximately $0.7 million.

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

Other Commitments

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

Also see Note 14 for commitment related to acquisition of properties in Alberta.

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 nine-month period ended September 30, 2008:


	Common Shares												Stock Options
																Wtd. Avg
	Number				Purchase			Contributed			Convertible		Number			Exercise Price
	(thousands)		Amount		Warrants			Surplus			Note		(thousands)			Cdn.$
Balance December 31, 2007		244,873	$	324,262	$	23,078		$	9,937		$	—		12,945		$	2.37
Shares issued for:
Private placement, net of share issue costs		29,334		82,687		—			—			—		—			—
Exercise of convertible debt		2,291		4,862		—			—			—		—			—
Services		217		490		—			—			—		—			—
Exercise of options		2,497		1,617		—			(413	)		—		(2,897	)	$	0.82
Options:
Granted		—		—		—			2,535			—		3,832		$	1.79
Cancelled/forfeited		—		—		—			—			—		(447	)	$	2.62
Convertible note issued		—		—		—			—			2,086		—			—
Purchase warrants expired		—		—		(4,273	)		4,273			—		—			—

Balance September 30, 2008		279,212	$	413,918	$	18,805		$	16,332		$	2,086		13,433		$	2.53

Special Warrants Offering

In July 2008, the Company completed a Cdn.$88.0 million private placement consisting of 29,334,000 Special Warrants (“Special Warrants”) at Cdn.$3.00 per Special Warrant (the “Offering”). Each Special Warrant entitled the holder to one common share of the Company upon exercise of the Special Warrant. In August 2008, all of the Special Warrants were exercised for 29,334,000 common shares. The net proceeds from the Offering of the Special Warrants was approximately Cdn.$83.4 million after deducting the agents’ commission of Cdn.$4.0 million and the expenses of the Offering of Cdn.$0.6 million. The Company used Cdn.$22.5 million of the net proceeds of the Offering to complete the cash component of the Talisman lease acquisition described in Note 14.

Purchase Warrants

The only changes to the number of the Company’s purchase warrants and common shares issuable upon the exercise of the purchase warrants for the nine-month period ended September 30, 2008 were the expiration of 4.1 million and 11.0 million purchase warrants in April and May 2008. The combined value of $4.3 million associated with these warrants was reclassified from Purchase Warrants to Contributed Surplus at the time of expiration.

Convertible Notes

As described in Note 5, in connection with the acquisition in July 2008, the Company issued the Convertible Note to Talisman in the principal amount of Cdn.$40.0 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated daily and not compounded, and payable semi-annually, maturing in July 2011 and convertible (as to the outstanding principal amount), at Talisman’s option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per common share. Also described in Note 5, management accounted for this convertible note by assigning a portion of the value, Cdn.$2.1 million, of the instrument to equity.

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 matured and was repayable in August 2008. The lender exercised its option to convert the entire outstanding balance into the Company’s common shares at the conversion price of Cdn.$2.24 per share.

As at September 30, 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

Value on

Year of

Special

Shares

Price per

Exercise

Issue

Warrant

Issued

Exercisable

Issuable

Value

Expiry Date

Share

($U.S. 000)

(thousands)

($U.S. 000)

2006

U.S.$2.23

11,400

18,805

May 2011

Cdn. $2.93 (1)

31,821


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

9. SEGMENT INFORMATION

The Company has four reportable business segments: Oil and Gas — Integrated, Oil and Gas - Conventional, Business and Technology Development and Corporate. These segments are different than those reported in the Company’s previous financial statements included in its Form 10-Qs and Form 10-Ks and as such the presentation has been changed to conform to the new segments. Due to newly established geographically focused entities and the initiation of two new integrated projects, new segments are being reported to reflect how management now analyzes and manages the Company.

Oil and Gas

Integrated

Projects in this segment will have two primary components. The first component consists of conventional exploration and production activities together with enhanced oil recovery techniques such as steam assisted gravity drainage. The second component consists of the deployment of the HTL^TM Technology which will be used to upgrade heavy oil at facilities located in the field to produce lighter, more valuable crude. The Company has two such projects currently reported in this segment — a heavy oil project in Alberta (see Note 14) and a heavy oil property in Ecuador (see Note 15).

Conventional

The Company explores for, develops and produces crude oil and natural gas in China and in the U.S. In China, the Company’s development and production activities are conducted at the Dagang oil field located in Hebei Province and its exploration activities are conducted on the Zitong block located in Sichuan Province. In the U.S., the Company’s exploration, development and production activities are primarily conducted in California and Texas.

Business and Technology Development

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

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

Corporate

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

The following tables present the Company’s segment information for the three-month and nine-month periods ended September 30, 2008 and 2007 and identifiable assets as at September 30, 2008 and December 31, 2007:


	Three-Month Period Ended September 30, 2008
	Oil and Gas											Business and
	Integrated						Conventional					Technology
	Canada			Ecuador			China			U.S.		Development			Corporate			Total
Revenue
Oil and gas revenue	$	—		$	—		$	14,912		$	5,525	$	—		$	—		$	20,437
Gain on derivative instruments		—			—			10,898			3,920		—			—			14,818
Interest income		—			—			11			22		—			338			371

		—			—			25,821			9,467		—			338			35,626


Expenses
Operating costs		—			—			6,626			1,585		—			—			8,211
General and administrative		655			102			639			856		—			3,003			5,255
Business and technology development		(20	)		—			—			—		1,989			—			1,969
Depletion and depreciation		—			—			5,891			1,660		632			—			8,183
Interest expense and financing costs		—			—			169			128		22			144			463

		635			102			13,325			4,229		2,643			3,147			24,081


Income (Loss) before Income Taxes		(635	)		(102	)		12,496			5,238		(2,643	)		(2,809	)		11,545


Provision for income taxes
Current		—			—			(358	)		—		—			—			(358	)
Future		—			—			(1,125	)		—		—			—			(1,125	)

		—			—			(1,483	)		—		—			—			(1,483	)


Net Income (Loss) and Comprehensive
Income (Loss)	$	(635	)	$	(102	)	$	11,013		$	5,238	$	(2,643	)	$	(2,809	)	$	10,062


Capital Investments	$	3,999		$	—		$	1,795		$	596	$	2,566		$	—		$	8,956


	Nine-Month Period Ended September 30, 2008
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			China			U.S.			Development			Corporate			Total
Revenue
Oil and gas revenue	$	—		$	—		$	37,547		$	15,912		$	—		$	—		$	53,459
Loss on derivative instruments		—			—			(6,793	)		(3,122	)		—			—			(9,915	)
Interest income		—			—			36			88			—			355			479

		—			—			30,790			12,878			—			355			44,023


Expenses
Operating costs		—			—			16,239			3,978			—			—			20,217
General and administrative		1,404			102			1,902			1,734			—			8,607			13,749
Business and technology development		129			—			—			—			4,760			—			4,889
Depletion and depreciation		—			—			17,891			4,814			1,969			4			24,678
Interest expense and financing costs		—			—			642			408			54			396			1,500

		1,533			102			36,674			10,934			6,783			9,007			65,033


Income (Loss) before Income Taxes		(1,533	)		(102	)		(5,884	)		1,944			(6,783	)		(8,652	)		(21,010	)


(Provision for) recovery of income taxes
Current		—			—			(358	)		(4	)		(2	)		—			(364	)
Future		—			—			1,161			—			—			—			1,161

		—			—			803			(4	)		(2	)		—			797


Net Income (Loss) and Comprehensive

Income (Loss)	$	(1,533	)	$	(102	)	$	(5,081	)	$	1,940		$	(6,785	)	$	(8,652	)	$	(20,213	)


Capital Investments	$	3,999		$	—		$	5,566		$	3,797		$	3,510		$	—		$	16,872


Identifiable Assets:
As at September 30, 2008	$	78,548		$	168		$	71,832		$	39,252		$	120,171		$	53,033		$	363,004


As at December 31, 2007	$	—		$	—		$	73,298		$	40,726		$	117,529		$	5,363		$	236,916


	Three-Month Period Ended September 30, 2007
	Oil and Gas						Business and
	Conventional						Technology
	China			U.S.			Development			Corporate			Total
Revenue
Oil and gas revenue	$	7,994		$	2,870		$	—		$	—		$	10,864
Loss on derivative instruments		(720	)		(1,433	)		—			—			(2,153	)
Interest income		12			32			—			68			112

		7,286			1,469			—			68			8,823

Expenses
Operating costs		3,220			1,046			—			—			4,266
General and administrative		416			381			—			1,928			2,725
Business and technology development		—			—			2,831			—			2,831
Depletion and depreciation		4,537			1,306			199			2			6,044
Interest expense and financing costs		—			110			7			72			189

		8,173			2,843			3,037			2,002			16,055

Net Loss and Comprehensive Loss	$	(887	)	$	(1,374	)	$	(3,037	)	$	(1,934	)	$	(7,232	)


Capital Investments	$	7,735		$	645		$	720		$	—		$	9,100


	Nine-Month Period Ended September 30, 2007
	Oil and Gas						Business and
	Conventional						Technology
	China			U.S.			Development			Corporate			Total
Revenue
Oil and gas revenue	$	21,869		$	8,380		$	—		$	—		$	30,249
Loss on derivative instruments		(720	)		(2,208	)		—			—			(2,928	)
Interest income		31			93			—			224			348

		21,180			6,265			—			224			27,669


Expenses
Operating costs		8,991			3,183			—			—			12,174
General and administrative		1,446			1,564			—			5,971			8,981
Business and technology development		—			—			7,341			—			7,341
Depletion and depreciation		13,591			4,402			963			4			18,960
Interest expense and financing costs		5			295			20			251			571

		24,033			9,444			8,324			6,226			48,027


Net Loss and Comprehensive Loss	$	(2,853	)	$	(3,179	)	$	(8,324	)	$	(6,002	)	$	(20,358	)


Capital Investments	$	18,053		$	2,438		$	2,066		$	—		$	22,557

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 September 30, 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	$	—	$	—	$	61,649		$	—		$	61,649
Accounts receivable		13,811		—		—			—			13,811

Financial Liabilities:
Accounts payable and accrued liabilities		—		—		—			(13,074	)		(13,074	)
Income tax payable		—		—		—			(358	)		(358	)
Derivative instruments		—		—		(9,310	)		—			(9,310	)
Long term debt		—		—		—			(63,751	)		(63,751	)

	$	13,811	$	—	$	52,339		$	(77,183	)	$	(11,033	)


	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 nor to management’s objectives, policies and processes to manage risks from the previous year. The risks associated with our 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 being 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.

Results of these derivative transactions for the three-month and nine-month periods ended September 30:


	Three Month Periods Ended September 30,
	2008			2007
Realized losses on derivative transactions	$	(3,735	)	$	(423	)
Unrealized gains (losses) on derivative transactions		18,553			(1,730	)

	$	14,818		$	(2,153	)


	Nine Month Periods Ended September 30,
	2008			2007
Realized losses on derivative transactions	$	(10,037	)	$	(246	)
Unrealized gains (losses) on derivative transactions		122			(2,682	)

	$	(9,915	)	$	(2,928	)

Both realized and unrealized gains and losses on derivatives have been recognized in the results of operations.

On September 30, 2008, the Company’s open positions on the derivative liabilities referred to above had a fair value of $9.3 million. A 10% increase in oil prices would increase the fair value, and consequently increase the net loss (or decrease net income), by approximately $3.3 million, while a 10% decrease in prices would reduce the fair value, and consequently reduce the net loss (or increase net income), by approximately $3.1 million. The fair value change assumes volatility based on prevailing market parameters at September 30, 2008.

Foreign Currency Exchange Rate Risk

administrative offices in Vancouver and Calgary, as well as some business development costs, are paid in Canadian dollars. In addition, with the recent property acquisition in Alberta (see Note 14) the Company’s Canadian dollar expenditures have increased during the most recent quarter along with an increase in cash and debt balances denominated 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 September 30, 2008 on net loss and accumulated deficit for the nine-month period ended September 30, 2008 is a $1.8 million increase, and a $1.4 million decrease, respectively. To help reduce the Company’s exposure to foreign currency risk it seeks to maximize the expenditures and contracts denominated in U.S. dollars and minimize those denominated in other currencies, except for its Canadian activities where it attempts to hold cash denominated in Canadian dollars in order to manage its currency risk related to outstanding debt and current liabilities denominated in Canadian dollars.

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. The Company estimates that its interest income generated by its cash equivalents for the three-month period ended September 30, 2008 would have changed $0.3 million for a 0.5% change in average interest rates over the period. The Company currently has two separate bank loan facilities, a promissory note and a convertible note with fluctuating interest rates. The Company estimates that its net loss and accumulated deficit for the nine-month period ended September 30, 2008 would have changed $0.1 million for every 1% change in interest rates as of September 30, 2008. The Company is not currently actively attempting to mitigate this interest rate risk given the limited amount and term of its borrowings and the current global interest rate environment.

Credit Risk

The Company is exposed to credit risk with respect to its cash held with financial institutions, accounts receivable and advance balances. The Company believes its exposure to credit risk related to cash held with financial institutions is minimal due to the quality of the institutions where the cash is held and the nature of the deposit instruments. 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 only with established entities and reviewing its exposure to individual entities on a regular basis. Of the $13.8 million trade receivables balance as at September 30, 2008, $10.3 million is due from a single customer and $1.4 million is due from another single customer. 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 balance are debtors with a carrying amount of $1.3 million as of the quarter ended September 30, 2008 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. During the quarter ended September 30, 2008 the Company recorded an allowance associated with the advance balance for the entire outstanding amount of $0.7 million. The provision was recorded in General and Administrative expense in the accompanying Statement of Operations and Comprehensive Income (Loss). There were no other changes to the allowance for credit losses account during the three-month and nine-month periods ended September 30, 2008 and no other losses associated with credit risk were recorded during these same periods.


	September 30,		December 31,
	2008		2007
Accounts Receivable:
Neither impaired nor past due	$	12,465	$	8,259
Impaired (net of valuation allowance)		—		—
Not impaired and past due in the following periods:
within 30 days		566		347
31 to 60 days		39		—
61 to 90 days		11		4
over 90 days		730		766

		13,811		9,376

Advance
Not impaired and past due over 90 days		—		825

	$	13,811	$	10,201

Our maximum exposure to credit risk is based on the recorded amounts of the 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 it 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 to generate sufficient resources to assure continuation of its operations and achieve its capital investment objectives include alliances or other arrangements with entities with the resources to support the Company’s projects as well as project financing, debt financing or the sale of equity securities.

The contractual maturity of the 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 September 30, 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		$6,421		$2,888		$—		$—		$7,156		$2,276		$—		$—

Non derivative financial liabilities:
Trade accounts payable		$6,359		$—		$—		$—		$6,897		$—		$—		$—
Accruals		$6,714		$—		$—		$—		$2,641		$—		$—		$—
Long term debt and interest		$13,723		$6,281		$46,321		$—		$8,240		$1,541		$10,277		$—

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™ 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, convertible note, shares to be issued and accumulated deficit as disclosed in Note 8. Cash and cash equivalents consist of $61.6 million and $11.4 million at September 30, 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’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 is in compliance with all financial covenants for the quarter ended September 30, 2008.

12. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information for the three-month and nine-month periods ended September 30:


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Supplemental Cash Flow Information

Cash paid during the period for
Income taxes	$	—		$	1		$	6		$	6

Interest	$	168		$	22		$	773		$	108


Investing and Financing activities, non-cash
Debt issued for the acquisition of oil and gas assets	$	52,052		$	—		$	52,052		$	—


Conversion of debt to shares
Extinguishment of debt	$	4,737		$	—		$	4,737		$	—
Extinguishment of interest		125			—			125			—

	$	4,862		$	—		$	4,862		$	—


Shares issued for bonuses	$	490		$	413		$	490		$	692


Changes in non-cash working capital items
Operating Activities
Accounts receivable	$	(1,366	)	$	(921	)	$	(3,915	)	$	(453	)
Prepaid and other current assets		(15	)		155			116			407
Accounts payable and accrued liabilities		(512	)		1,081			2,814			234
Income tax payable		358			—			358			—

		(1,535	)		315			(627	)		188


Investing Activities
Accounts receivable		(552	)		(5	)		(520	)		(139	)
Prepaid and other current assets		(9	)		19			1			79
Accounts payable and accrued liabilities		3,430			2,175			856			755

		2,869			2,189			337			695


Financing Activities
Accounts payable and accrued liabilities		(711	)		—			(9	)		—

	$	623		$	2,504		$	(299	)	$	883

Cash and cash equivalents consisted of the following as at:


	September 30,		December 31,
	2008		2007
Bank balances in checking accounts	$	10,444	$	11,356
Time deposits with maturities of less than 90 days		51,205		—

	$	61,649	$	11,356

13. INCOME TAXES

In the second quarter of 2008, the Company concluded that it is more likely than not to be able to utilize the tax deductions associated with future income tax assets related to its Pan-China operations. This resulted in a future income tax recovery of $2.3 million recorded during the three month period ended June 30, 2008. During the third quarter of 2008, Pan-China had approximately $8.0 million of net income, which created a $1.1 million future income tax provision and reduced the future income tax recovery to $1.2 million for the nine month period ended September 30, 2008. In addition, the amount of current income tax payable at September 30, 2008 equaled $0.4 million.

14. ACQUISITION

In July 2008, the Company completed the acquisition of Talisman Energy Canada’s (“Talisman”) 100% working interests in two leases located in the Athabasca oil sands region in the Province of Alberta, Canada. The total purchase price was Cdn.$90.0 million, of which an initial payment of Cdn.$22.5 million was made on closing. In addition to this initial payment, as described in Note 5, the Company issued a promissory note to Talisman in the principal amount of Cdn.$12.5 million bearing interest at a rate per year equal to the prime rate plus 2% maturing on December 31, 2008 and a second promissory note to Talisman in the principal amount of Cdn.$40.0 million bearing interest at a rate per annum equal to the prime rate plus 2%, maturing in July 2011 and convertible (as to the outstanding principal amount), at Talisman’s option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per common share.

The Company will also make a cash payment to Talisman of Cdn.$15 million if the requisite government and other approvals necessary to develop the northern border of one of the leases (the "Contingent Payment”) are obtained. No amount is recorded in the financial statements for this payment as at September 30, 2008.

The Company had also agreed to acquire Talisman’s 75% working interest in a third oil sands lease, subject to the remaining working interest holder not exercising its right of first refusal to acquire Talisman’s interest. The third party right of first refusal was exercised and the Company did not acquire Talisman’s interest in this lease. Pursuant to the asset transfer agreement, the Company and Talisman have agreed that if the remaining working interest holder in the lease does not complete the acquisition of Talisman’s interest by November 30, 2008, within 30 days after notice from Talisman, the Company will acquire such interest from Talisman for a purchase price of Cdn.$15 million.

Talisman retains a back-in right (the “Back-in Right”), exercisable once per lease until July 11, 2011, to re-acquire up to a 20% undivided interest in each lease. The purchase price payable by Talisman were it to exercise the Back-in Right in respect of a particular lease would be an amount equal to 20% of:

	(a)		100% of the Company’s acquisition cost and certain expenses in respect of the relevant lease if the Back-in Right is exercised on or before July 11, 2009;

	(b)		150% of the Company’s acquisition cost and certain expenses in respect of the relevant lease if the Back-in Right is exercised after July 11, 2009 but on or before July 11, 2010; or

	(c)		200% of the Company’s acquisition cost and certain expenses in respect of the relevant lease if the Back-in Right is exercised after July 11, 2010 but on or before July 11, 2011.

Until July 11, 2011, Talisman has the right of first offer to acquire any interests in heavy oil projects in the Province of Alberta that the Company or any of its subsidiaries wishes to sell, excluding the acquired leases.

15. SUBSEQUENT EVENT

On October 8, 2008, Ivanhoe Energy Ecuador Inc. (“IE Ecuador”) entered into a contract with Empresa Estatal de Petroleos del Ecuador, Petroecuador (“Petroecuador”), the state oil company of Ecuador, and its affiliate, Empresa Estatal de Exploracion y Produccion de Petroleos del Ecuador, Petroproduccion (“Petroproduccion”) to explore and develop an oil field concession area in Ecuador that includes the Pungarayacu heavy-oil field, utilizing the Company’s HTL^TM technology. IE Ecuador is a wholly-owned subsidiary of Ivanhoe Energy Latin America Inc. (“IE Latin America”), a wholly-owned subsidiary of the Company.

IE Ecuador will lead the development of the project. The contract is guaranteed by its parent company IE Latin America, which will obtain or provide funding and financing for IE Ecuador’s operations under the contract. The contract’s 30-year term may be extended by mutual agreement. To recover its investments, costs and expenses, and to provide for a profit, IE Ecuador will receive from Petroproduccion a payment of US$37.00 per barrel of oil produced and delivered to Petroproduccion. The payment will be indexed (adjusted) quarterly for inflation, starting from the contract date, using the weighted average of a basket of three US Government-published producer price indices relating to steel products, refinery products and upstream oil and gas equipment. IE Ecuador may elect to receive its payment in oil, based on market prices.

16. 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 September 30, 2008
	Assets			Liabilities				Shareholders’ Equity
	Oil and Gas
	Properties and
	Development			Derivative		Long Term		Share Capital			Contributed			Accumulated			Convertible
	Costs			Instruments		Debt		and Warrants			Surplus			Deficit			Note			Total
Canadian GAAP	$	179,641		$	9,310	$	45,640	$	432,723		$	16,332		$	(180,203	)	$	2,086		$	270,938
Adjustments:
(i)		—			—		—		74,455			—			(74,455	)		—			—
(ii)		—			—		—		(498	)		(3,250	)		3,748			—			—
(iii)		—			6,516		—		(5,575	)		(2,977	)		2,036			—			(6,516	)
(iv)		1,358			—		—		1,358			—			—			—			1,358
(v)		(25,990	)		—		—		—			—			(25,990	)		—			(25,990	)
(vi)		12,773			—		—		—			—			12,773			—			12,773
(vii)		(5,806	)		—		—		—			—			(5,806	)		—			(5,806	)
(viii)		—			—		2,086		—			—			—			(2,086	)		(2,086	)

U.S. GAAP	$	161,976		$	15,826	$	47,726	$	502,463		$	10,105		$	(267,897	)	$	—		$	244,671


	As at December 31, 2007
	Assets			Liabilities		Shareholders’ Equity
	Oil and Gas
	Properties and
	Development			Derivative		Share Capital			Contributed			Accumulated
	Costs			Instruments		and Warrants			Surplus			Deficit			Total
Canadian GAAP	$	111,853		$	9,432	$	347,340		$	9,937		$	(159,990	)	$	197,287
Adjustments:
(i)		—			—		74,455			—			(74,455	)		—
(ii)		—			—		(396	)		(3,352	)		3,748			—
(iii)		—			5,786		(7,988	)		(564	)		2,766			(5,786	)
(iv)		1,358			—		1,358			—			—			1,358
(v)		(25,990	)		—		—			—			(25,990	)		(25,990	)
(vi)		9,334			—		—			—			9,334			9,334
(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 September 30, 2008 and December 31, 2007.

(ii) Under Canadian GAAP, the Company accounts for all stock options granted to employees and directors since January 1, 2002 using the fair value based method of accounting. Under this method, compensation costs are recognized in the financial statements over the stock options’ vesting period using an option-pricing model for determining the fair value of the stock options at the grant date. Under U.S. GAAP, prior to January 1, 2006 the Company applied Accounting Principles Board (“APB”) Opinion No. 25, as

interpreted by the Financial Accounting Standards Board (“FASB”) Interpretation No. 44, in accounting for its stock option plan and did not recognize compensation costs in its financial statements for stock options issued to employees and directors. This resulted in a reduction of $3.7 million in the accumulated deficit as at September 30, 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 FASB issued a revision to the Statement of Financial Accounting Standards (“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 under Canadian GAAP and U.S. GAAP for the three-month and nine-month periods ended September 30, 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, the accounting treatment of warrants under U.S. GAAP reflects the application of SFAS 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. When such warrants expire unexercised, there is no adjustment under U.S. GAAP as the fair value of the liability is zero. Under Canadian GAAP the value of the warrants is reclassified to contributed surplus upon expiry. This GAAP difference resulted in an increase in derivative instruments of $6.6 million and $5.8 million, a decrease in share capital and warrants of $5.6 million and $8.0 million and a decrease in contributed surplus of $3.0 million and $0.6 million at September 30, 2008 and December 2007.

Oil and Gas Properties and Development Costs

(iv) Under U.S. GAAP, 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 (d) income tax effects related to the difference between the book and tax basis of the properties referred to in (b) and (c) above. If capitalized costs exceed this limit, the excess is charged as a provision for impairment. Unproved properties and major development projects are assessed on a quarterly basis for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to the carrying value of proved oil and gas properties. The Company performed the ceiling test in accordance with U.S. GAAP and determined that for the three-month and nine-month periods ended September 30, 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 September 30, 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 $12.8 million and $9.3 million as at September 30, 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, under Canadian GAAP, the Company capitalizes certain development costs incurred for 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 development costs. Under U.S. GAAP, feasibility, marketing and related costs incurred prior to executing a definitive agreement are considered to be research and development and are expensed as incurred. As at September 30, 2008 and December 31, 2007, the Company capitalized $5.8 and $5.7 million for Canadian GAAP, which was expensed for U.S. GAAP purposes.

(viii) As described in Note 5 of these financial statements under Canadian GAAP we were required to bifurcate the value of the Convertible Debt, allocating a portion to long term debt and a portion to equity. Under U.S. GAAP, the convertible debt securities in their entirety are classified as debt. This resulted in an increase in long term debt and a decrease in equity of $2.1 million for U.S. GAAP when compared to Canadian GAAP as at September 30, 2008. The difference between the fair value and the face value is amortized over the life of the convertible debt using the effective interest method.

Deferred Financing Costs

As more fully described in our financial statements in Item 8 of our 2007 Annual Report filed on Form 10-K, under 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. Under U.S. GAAP purposes, these costs are classified as other assets resulting in an increase of $0.5 million, and $0.7 million, in long term debt and other assets for U.S. GAAP purposes when compared to Canadian GAAP as at September 30, 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 September 30,
	2008							2007
				Net Income		Net Income					Net Loss			Net Loss
	Net			Per Share		Per Share		Net			Per Share			Per Share
	Income			Basic		Diluted		Loss			Basic			Diluted
Canadian GAAP	$	10,062		$	0.04	$	0.04	$	(7,232	)	$	(0.03	)	$	(0.03	)
Fair value adjustment of derivative instruments (iii)		14,641			0.06		0.05		3,571			0.01			0.01
Depletion adjustments due to differences in provision for impairment (ix)		1,132			—		—		1,172			0.01			0.01
Development costs expensed, net of write downs (x)		(11	)		—		—		(62	)		—			—


U.S. GAAP	$	25,824		$	0.10	$	0.09	$	(2,551	)	$	(0.01	)	$	(0.01	)


Weighted Average Number of Shares under U.S. GAAP (in thousands)					265,372		279,641					242,747			242,747


	Nine-Month Periods Ended September 30,
	2008									2007
				Net Loss			Net Loss						Net Loss			Net Loss
	Net			Per Share			Per Share			Net			Per Share			Per Share
	Loss			Basic			Diluted			Loss			Basic			Diluted
Canadian GAAP	$	(20,213	)	$	(0.08	)	$	(0.08	)	$	(20,358	)	$	(0.08	)	$	(0.08	)
Fair value adjustment of derivative instruments (iii)		(730	)		—			—			(525	)		—			—
Depletion adjustments due to differences in provision for impairment (ix)		3,439			0.01			0.01			3,617			0.01			0.01
Development costs expensed, net of write downs (x)		(148	)		—			—			(180	)		—			—
Recovery of HTL^TM investments (x)		—			—			—			6,279			0.02			0.02


U.S. GAAP	$	(17,652	)	$	(0.07	)	$	(0.07	)	$	(11,167	)	$	(0.05	)	$	(0.05	)


Weighted Average Number of Shares under U.S. GAAP (in thousands)					251,907			251,907						241,812			241,812

(ix) As discussed under “Oil and Gas Properties and Development Costs” in this note, there is a difference between U.S. and Canadian GAAP in performing the ceiling test evaluation under the full cost method of the accounting rules. Application of the ceiling test evaluation under U.S. GAAP has resulted in an accumulated net increase in impairment provisions on the Company’s U.S. and China oil and gas properties of $26.0 million as at September 30, 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 $1.1 million and $3.4 million in the net losses for the three-month and nine-month periods ended September 30, 2008 and a reduction of $1.2 million and $3.6 million in the net losses for the three-month and nine-month periods ended September 30, 2007.

(x) As more fully described under “Oil and Gas Properties and Development Costs” in this note, under Canadian GAAP, feasibility, marketing and related costs incurred prior to executing a definitive agreement are capitalized and are subsequently written down upon determination that a project’s future value has been impaired. Under U.S. GAAP, such costs are considered to be research and development and are expensed as incurred. The Company expensed nil and $0.1 million in excess of the Canadian GAAP write-downs for the three-month and nine-month periods ended September 30, 2008, and the Company expensed $0.1 million and $0.2 million in excess of the Canadian GAAP write-downs during those corresponding periods in 2007.

The Company and INPEX Corporation (“INPEX”) signed an agreement to jointly pursue the opportunity to develop a heavy oil field in Iraq that Ivanhoe Energy believes is a suitable candidate for its patented HTL^TM heavy oil upgrading technology. In the second quarter of 2007, the Company received a $9.0 million payment related to this agreement which was credited to the carrying value of its Iraq and CDF Development Costs related to this project for Canadian GAAP purposes. The prior costs for Iraq projects had previously been expensed for U.S. GAAP purposes and therefore that portion of the proceeds, $6.3 million, was credited to the statement of operations for U.S. GAAP purposes.

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 and nine-month periods ended September 30, 2008. As a result of expensing of development costs required under U.S. GAAP and recovery of such costs, the statements of cash flows as reported would result in a cash surplus from operating activities of $1.7 million and $10.7 million for the three-month and nine-month period ended September 30, 2007 if reported under U.S. GAAP. Additionally, capital investments reported under investing activities would be $9.0 million and $22.4 million for the three-month and nine-month period ended September 30, 2007 if reported under U.S. GAAP.

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

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). This Statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP in the United States (the “GAAP hierarchy”). The FASB concluded that the GAAP hierarchy should reside in the accounting literature established by the FASB and is issuing this Statement to achieve that result. SFAS No. 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles”. Management has concluded that the requirements of this recent statement will not have a material impact on its financial statements.

In March 2008, the FASB issued SFAS 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 SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141(R)”) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS No. 160”). Effective for fiscal years beginning after December 15, 2008, 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 SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. 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 the current policy on accounting for fair value measurements is consistent with this guidance. The Company has, 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 September 30, 2008.


	As at September 30, 2008
	Level 1		Level 2		Level 3		Total
Derivative instruments liabilities	$	6,516	$	9,310	$	—	$	15,826

The fair value measurement of derivative instruments liabilities related to the Company’s costless collars are considered Level 2 and the fair value measurement of derivative instruments liabilities related to its 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 Ivanhoe Energy’s agreement with Talisman to acquire all of Talisman’s working interest in two oil sand leases, Ivanhoe Energy Ecuador’s agreement with Petroecuador and Petroproduccion to develop Block 20 in Ecuador, Ivanhoe Energy’s ability to obtain the financing to pay the principal and interest on the notes delivered by Ivanhoe Energy at the acquisition closing and obtain the financing necessary to fund the Ecuador project, Ivanhoe Energy’s plan to establish integrated HTL heavy oil projects on Talisman Lease 10 and Ecuador Block 20, the anticipated production capacity of the proposed HTL plants, the anticipated quantities of recoverable barrels of bitumen and other statements which are not historical facts and to future production associated with the HTL^TM Technology, GTL Technology and Enhanced Oil Recovery (“EOR”) techniques. Such statements involve known and unknown risks and uncertainties which may cause the 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 the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, but are not limited to, the ability to raise capital as and when required, the timing and extent of changes in prices for oil and gas, competition, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and the potential success of heavy-to-light and gas-to-liquids technologies, the prices of goods and services, the availability of drilling rigs and other support services, legislative and government regulations, political and economic factors in countries in which the Company operates and implementation of its capital investment program.

The above items and their possible impact are discussed more fully in the section entitled “Risk Factors” in Item 1A and “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of the Company’s 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 16.

SPECIAL NOTE TO CANADIAN INVESTORS

The Company is a registrant under the Securities Exchange Act of 1934 and voluntarily files reports with the U.S. Securities and Exchange Commission (“SEC”) on Form 10-K, Form 10-Q and other forms used by registrants that are U.S. domestic issuers. Therefore, the Company’s reserves estimates and securities regulatory disclosures generally follow SEC requirements. In 2004, the Canadian Securities Administrators (“CSA”) adopted National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities (NI 51-101) which prescribes certain standards for the preparation and disclosure of reserves and related information by Canadian issuers. The Company has been granted certain exemptions from NI 51-101. Please refer to the Special Note to Canadian Investors on page 10 of the 2007 Annual Report on Form 10-K.

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

As generally used in the oil and gas business and 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

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

Electronic copies of the Company’s filings with the SEC and the CSA are available, free of charge, through its web site (www.ivanhoeenergy.com) or, upon request, by contacting its 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 the Company’s 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 using advanced technologies, including its proprietary, patented rapid thermal processing process (“RTP^TM Process”) for heavy oil upgrading (“HTL^TM Technology” or “HTL^TM”). In mid-2008, the Company acquired two leases located in the heart of the Athabasca oil sands region in Alberta, Canada and recently signed a Specific Services contract in Ecuador for the appraisal and development of a heavy oil lease in Ecuador. It is anticipated that these sites will provide for the first commercial applications of the Company’s HTL™ Technology in major, integrated heavy oil projects (see Implementation Strategy below).

In addition, the Company seeks to selectively 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. Core operations are in Canada, the United States, China and Ecuador, with business development opportunities worldwide.

The Company has established a number of geographically focused entities. The parent company, Ivanhoe Energy Inc., will pursue HTL opportunities in the Athabasca oil sands of Western Canada and will hold and manage the core HTL technology. A new subsidiary for Latin America recently signed a Specific Services Contract for the appraisal and development of a heavy oil lease in Ecuador. In addition, a subsidiary has been established to undertake activities in the Middle East and North Africa. These companies complement Sunwing Energy Ltd., the Company’s existing, wholly-owned company for China. Ivanhoe Energy Inc. owns 100% of each of these subsidiaries, although the percentages are expected to decline as they develop their respective businesses and raise capital independently.

This structure will allow the development and financing of multiple HTL projects around the world, while minimizing dilution of the Company’s existing shareholders. In addition, the alignment with principal energy-producing regions will facilitate financing from region-specific strategic investors, some of which already have been identified, and also will enhance flexibility in accessing global capital markets.

Corporate Strategy

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

The global oil and gas industry is experiencing sharp increases in demand from developing economies and is being impacted by the declining availability of replacement low cost reserves. This has resulted in volatile but increased oil prices and marked shifts in the demand and supply landscape. Although there has been a great deal of volatility in the price of oil and significant recent price declines, long term demand, and the natural decline of conventional oil production will see the development of higher cost and 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 the Company focuses on the non-conventional heavy oil, both play an important role in Ivanhoe Energy’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 other 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 heavy oil production has been increasingly more common. Refineries, on the other hand, have not been able to keep up with the need for deep conversion capacity, and heavy versus light oil 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 higher 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 versus light oil 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 Energy’s Value Proposition

The Company’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 Energy’s HTL™ upgrading is a partial upgrading process that is designed to operate in facilities as small as 10,000 to 30,000 barrels per day produced. This is substantially smaller than the minimum economic scale for conventional stand-alone upgraders such as delayed cokers, which typically operate at scales of over 100,000 barrels per day produced. The Company’s HTL™ Technology is based on carbon rejection, a tried and tested concept in heavy oil processing. The key advantage of HTL™ is that it is a very fast process, as processing times are typically under a few seconds. 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. The Company’s HTL™ Technology has the added advantage of converting the byproducts from the upgrading process into onsite energy, rather than generating large volumes of low value coke.

The HTL™ process offers significant advantages as a field-located upgrading alternative, integrated with the upstream heavy oil production operation. HTL™ 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 versus 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 the Company 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 Energy value proposition.

Implementation Strategy

The Company’s continuing strategy is as follows:

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

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

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

	4.		*Build internal capabilities.* During 2008, significant progress has been made in building execution teams in preparation for the Company’s first HTL^TM projects. The upstream team consists of a number of experienced heavy oil engineers and geologists complemented by a core team of petroleum engineers and geologists. Also, the Company’s Houston-based HTL^TM technology team has been strengthened. The Company expects to continue filling key positions in its execution mode.

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

Talisman Lease Acquisition

In July, the Company announced the completion of the acquisition of Talisman Energy Canada’s (“Talisman’) 100% working interests in two leases (Leases 10 and 6) located in the heart of the Athabasca oil sands region in the Province of Alberta, Canada. Lease 10 is a 6,880-acre contiguous block located approximately ten miles (16 km) northeast of Fort McMurray. Lease 6 is a small, un-delineated, 680-acre block, one mile (1.6 km) south of Lease 10.

The acquisition of Lease 10 will provide the site for the application of Ivanhoe Energy’s proprietary, HTL™ heavy oil upgrading technology in a major, integrated heavy oil project. Lease 10 has a relatively high level of delineation (four wells per section). It is believed to be a high-quality reservoir and an excellent candidate for thermal recovery production using the SAGD (steam-assisted gravity drainage) process. The high quality of the asset is expected to provide for favorable projected operating costs, including attractive steam-oil ratios (SOR) using SAGD development techniques.

The Company’s HTL plant on Lease 10 is projected ultimately to be capable of operating at production rates of at least 30,000 barrels per day for approximately 25 years. The Company intends to integrate established SAGD thermal recovery techniques with its patented HTL upgrading process, producing and marketing a light, synthetic sour crude.

The Company has already commenced planning its Lease 10 development program in preparation for the submission of permits for an integrated HTL project. In general, thermal oil sands projects, including SAGD projects, require a period of initial development, including delineation, permitting and field development, which is followed by relatively stable operations for many years.

Ecuador Block 20 Contract

In October, Ivanhoe Energy Ecuador Inc., a wholly owned subsidiary, signed a contract with Ecuador state oil companies Petroecuador and Petroproduccion to explore and develop Ecuador’s Pungarayacu heavy oil field. Block 20 is an area of approximately 426 square miles, approximately 125 miles southeast of Quito, Ecuador’s capital.

The contract is a Specific Services Contract under which Ivanhoe Energy Ecuador will use its unique and patented HTL technology, as well as provide advanced oil-field technology, expertise and capital to develop, produce and upgrade heavy crude oil from Block 20, which contains the Pungarayacu field. In addition, Ivanhoe Energy Ecuador has the right to conduct exploration for light oil in the contract area and to use any light oil that it discovers to blend with the heavy oil for delivery to Petroproduccion.

The contract has an initial term of 30 years and has three phases. The first two phases are for evaluation of the field’s production capability and the crude-oil characteristics, as well as for the construction of the first HTL plant. The third phase is for full field development and will include drilling additional exploration and development wells. Additional HTL capacity will be added as necessary for expected production.

To recover its investments, costs and expenses, and to provide for a profit, Ivanhoe Energy Ecuador will receive from Petroproduccion a payment of US$37.00 per barrel of oil produced and delivered to Petroproduccion. The payment will be indexed (adjusted) quarterly for inflation, starting from the contract date, using the weighted average of a basket of three US Government-published producer price indices relating to steel products, refinery products and upstream oil and gas equipment. Ivanhoe Energy Ecuador may elect to receive its payment in oil, based on market prices.

Executive Overview of 2008 Results

The following table sets forth certain selected consolidated data for the three-month and nine-month periods ended September 30, 2008 and 2007:


	Three-Month Periods Ended					Nine-Month Periods Ended
	September 30,					September 30,
	2008		2007			2008			2007
Oil and gas revenue	$	20,437	$	10,864		$	53,459		$	30,249
Net income (loss)	$	10,062	$	(7,232	)	$	(20,213	)	$	(20,358	)
Net income (loss) per share	$	0.04	$	(0.03	)	$	(0.08	)	$	(0.08	)
Average production (Boe/d)		1,895		1,734			1,898			1,863
Net operating revenue per Boe	$	70.12	$	41.36		$	63.93		$	35.53
Cash flow from operating activities	$	1,673	$	1,766		$	7,399		$	4,566
Capital investments	$	8,956	$	9,100		$	16,872		$	22,557

Financial Results — Change in Net Loss

The following provides an analysis of the changes in net losses for the three-month and nine-month periods ended September 30, 2008 as compared to the same periods for 2007:


	Three-Month Periods Ended September 30,								Nine-Month Periods Ended September 30,
				*Favorable*								*Favorable*
				*(Unfavorable)*								*(Unfavorable)*
	2008			*Variances*		2007			2008			*Variances*		2007
Summary of Net Income (Loss) by Significant Components:
Oil and Gas Revenues:	$	20,437				$	10,864		$	53,459				$	30,249
Production volumes				$	996							$	621
Oil and gas prices					8,577								22,589
Realized loss on derivative instruments		(3,735	)		(3,312)		(423	)		(10,037	)		(9,791)		(246	)
Operating costs		(8,211	)		(3,945)		(4,266	)		(20,217	)		(8,043)		(12,174	)

General and administrative, less stock based compensation		(4,352	)		(2,119)		(2,233	)		(11,228	)		(4,247)		(6,981	)
Business and technology development, less stock based compensation		(1,758	)		807		(2,565	)		(4,385	)		2,343		(6,728	)
Net interest		91			105		(14	)		(514	)		(472)		(42	)
Current income tax provision		(358	)		(358)		—			(364	)		(364)		—

Unrealized gain (loss) on derivative instruments		18,553			20,283		(1,730	)		122			2,804		(2,682	)
Depletion and depreciation		(8,183	)		(2,139)		(6,044	)		(24,678	)		(5,718)		(18,960	)
Stock based compensation		(1,114	)		(356)		(758	)		(3,025	)		(412)		(2,613	)
Future income tax (provision) recovery		(1,125	)		(1,125)		—			1,161			1,161		—
Other		(183	)		(120)		(63	)		(507	)		(326)		(181	)


Net Income (Loss)	$	10,062		$	17,294	$	(7,232	)	$	(20,213	)	$	145	$	(20,358	)

Net income for the three-month period ended September 30, 2008 was $10.1 million ($0.04 net income per share) compared to a net loss for the same period in 2007 of $7.2 million ($0.03 net loss per share). The change from net loss to net income from 2007 to 2008 of $17.3 million was primarily due to a $20.3 million increase in unrealized gain on derivative instruments and a $9.6 million increase in oil and gas revenues offset by increases in realized losses on derivative instruments and expenses.

Net loss for the nine-month period ended September 30, 2008 was $20.2 million ($0.08 net loss per share) compared to a net loss for the same period in 2007 of $20.4 million ($0.08 net loss per share). The decrease in net loss from 2007 to 2008 of $0.1 million was

primarily due to a $23.2 million increase in oil and gas revenues and a $2.8 million increase in unrealized gain on derivative instruments offset by increases in realized losses on derivative instruments and expenses.

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 and nine-month periods ended September 30, 2008 as compared to the same periods in 2007:


	Three-Month Periods Ended September 30,							Nine-Month Periods Ended September 30,
	Net Boe’s				Percentage			Net Boe’s				Percentage
	2008		2007		Change			2008		2007		Change
China:
Dagang		118,110		111,012		6	%		349,599		342,368		2	%
Daqing		4,615		5,172		-11	%		14,604		16,069		-9	%

		122,725		116,184		6	%		364,203		358,437		2	%

U.S.:
South Midway		47,722		38,297		25	%		143,419		134,265		7	%
Spraberry		3,261		4,838		-33	%		10,984		14,876		-26	%
Others		638		239		167	%		1,406		1,092		29	%

		51,621		43,374		19	%		155,809		150,233		4	%


		174,346		159,558		9	%		520,012		508,670		2	%

Net production volumes for the three-month period ended September 30, 2008 increased 9% when compared to the same period in 2007 primarily due to an increase in production volumes in both our U.S. and China properties. Total volume changes in the quarter resulted in increased revenues of $1.0 million. Production volumes for the nine-month period ended September 30, 2008 increased 2% when compared to the same period in 2007 resulting in increased revenues of $0.6 million.

Oil and gas prices increased 72%, and 73%, per Boe for the three-month and nine-month periods ended September 30, 2008 generating $8.6 million and $22.6 million in additional revenue when compared to the same periods in 2007. For the China operations, the average realized prices were $121.50 and $103.09 per Boe during these respective periods in 2008, which were increases of $52.69 and $42.08 per Boe from the prices in the comparable periods in 2007. Average realized prices in China accounted for $6.5 million and $15.3 million of the increase in revenues for the three-month and nine-month periods ended September 30, 2008. For the U.S. operations, the average realized prices were $107.04 and $102.13 per Boe during these respective periods, which were increases of $40.88 and $46.35 per Boe from the prices in the comparable periods in 2007. Average realized prices in the U.S. accounted for $2.1 million and $7.3 million of the increase in revenues for the three-month and nine-month periods ended September 30, 2008. Crude oil prices and natural gas prices will likely remain volatile throughout 2008.

The increased revenues that resulted from increases to oil and gas prices during the three-month and nine-month periods ended September 30, 2008 were partially offset by the realized loss on derivatives resulting from the settlements from the 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 realized net loss on these settlements increased by $3.3 million and $9.8 million during the three-month and nine-month periods ended September 30, 2008 when compared to the same periods in 2007. Changes in these realized settlement losses by segment are detailed below:


	Three Months Ended			*Favorable*		Three Months Ended
	September 30,			*(Unfavorable)*		September 30,
	2008			*Variances*		2007
China	$	(1,808	)	$	(1,808)	$	—
U.S.		(1,927	)		(1,504)		(423	)

	$	(3,735	)	$	(3,312)	$	(423	)


	Nine Months Ended			*Favorable*		Nine Months Ended
	September 30,			*(Unfavorable)*		September 30,
	2008			*Variances*		2007
China	$	(4,663	)	$	(4,663)	$	—
U.S.		(5,374	)		(5,128)		(246	)

	$	(10,037	)	$	(9,791)	$	(246	)

For the three-month and nine-month periods ended September 30, 2008, operating costs, including Windfall Levy (the “Windfall Levy”) and production taxes and engineering and support costs, increased 76%, and 62%, per Boe compared to the same periods in 2007. Of the total $3.9 million, and $8.0 million, increase in these costs, $2.7 million, and $6.1 million, were a result of the change in 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 and nine-month periods ended September 30, 2008 increased by 83 Gross Bopd and 34 Gross Bopd , respectively, when compared to similar periods in 2007. The normal field decline was offset by the production from five new development wells that were completed and put on production in the second half of 2007, as well as productivity increases from adding new perforations, fracture stimulations and water flood response. The production rates for 2008 are expected to be similar to those averaged in 2007.

•

Operating Costs

Operating costs in China, including engineering and support costs and Windfall Levy, increased 95% and 78% per Boe during the three-month and nine-month periods ended September 30, 2008 as compared to the same periods in 2007. Field operating costs increased $5.38, and $2.83 per Boe. These increases were mainly a result of a higher percentage of field office costs allocated to operations versus capital as capital activity has decreased, increased security expenses and higher power costs resulting from greater water injection in 2008 when compared to the same periods in 2007. These increases were offset by decreases resulting from one-time maintenance projects in 2007 and lower project management salaries. In addition, during the third quarter of 2008, there were higher costs associated with oil treatment and transportation and more workover service days than the third quarter of 2007. Enterprises exploiting and selling crude oil in the Peoples Republic of China are subject to a windfall gain levy if the monthly weighted average price of crude oil is above $40 per barrel. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the weighted average sales price exceeding $40 per barrel. Consequently, as oil prices have increased, the amount of the Windfall Levy also increased significantly, resulting in a $21.27 and $16.76 per Boe increase for 2008 when compared to the same periods in 2007. With the exception of the Windfall Levy, the Company expects 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 in the fourth quarter of 2008 once “commercial production” status is reached, will be offset by an increase in office costs allocated to operations as the Company continues to reduce the number of capital projects.

			*U.S.*

	•		Production Volumes

There was a 4% and 19% increase in U.S. production volume for the three-month and nine-month periods ended September 30, 2008 compared to the same periods in 2007. The overall changes to the U.S. production volumes were mainly due the 2008 first quarter drilling program at South Midway. In addition, an increase in production in 2008 was due to abnormal downtimes in the steaming operations in 2007. The 2008 first quarter drilling program at South Midway is expected to offset natural declines within this field and to provide additional future drilling locations. Increases at South Midway were offset by smaller decreases in our Spraberry field in West Texas where there was significant downtime related to downhole problems.

•

Operating Costs

Operating costs in the U.S., including engineering and support costs and production taxes, increased 27% and 21% per Boe for the three-month and nine-month periods ended September 30, 2008 when compared to the same periods in 2007. Field operating costs increased $6.01 and $4.69 per Boe mainly due to an increase in steaming operations at South Midway. Both steam generators were down in the latter part of the first quarter and through the second quarter of 2007. In addition, the price of natural gas has been

significantly higher in 2008 when compared to 2007. Additional maintenance costs and workovers at the Spraberry field in West Texas in the second and third quarters of 2008 added to the overall increase in costs. Also, oil field expenses in general have been increasing due to the demand both in California and nationwide The Company anticipates 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. Operating costs during the remainder of 2008 at Spraberry are expected to be consistent with the preceding quarters of 2008.

* * *

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 September 30,
	2008						2007
	China		U.S.		Total		China		U.S.		Total
Net Production:
Boe		122,725		51,621		174,346		116,184		43,374		159,558
Boe/day for the period		1,334		561		1,895		1,263		471		1,734

			Per Boe						Per Boe

Oil and gas revenue	$	121.50	$	107.04	$	117.22	$	68.81	$	66.16	$	68.09

Field operating costs		22.58		24.07		23.02		17.20		18.06		17.43
Windfall Levy (China) and Production tax (U.S.)		30.47		1.63		21.93		9.20		1.46		7.09
Engineering and support costs		0.95		5.00		2.15		1.32		4.59		2.21

		54.00		30.70		47.10		27.72		24.11		26.73

Net operating revenue		67.50		76.34		70.12		41.09		42.05		41.36
Depletion		48.01		31.94		43.25		39.02		29.91		36.55

Net revenue from operations	$	19.49	$	44.40	$	26.87	$	2.07	$	12.14	$	4.81


	Nine-Month Periods Ended September 30,
	2008						2007
	China		U.S.		Total		China			U.S.		Total
Net Production:
Boe		364,203		155,809		520,012		358,437			150,233		508,670
Boe/day for the period		1,329		569		1,898		1,313			550		1,863

			Per Boe							Per Boe

Oil and gas revenue	$	103.09	$	102.13	$	102.81	$	61.01		$	55.78	$	59.47

Field operating costs		20.48		19.55		20.21		17.65			14.86		16.83
Windfall Levy (China) and Production tax (U.S.)		22.94		1.42		16.49		6.18			1.27		4.73
Engineering and support costs		1.17		4.56		2.18		1.26			5.06		2.38

		44.59		25.53		38.88		25.09			21.19		23.94

Net operating revenue		58.50		76.60		63.93		35.92			34.59		35.53
Depletion		49.12		30.72		43.61		37.89			29.08		35.29

Net revenue (loss) from operations	$	9.38	$	45.88	$	20.32	$	(1.97	)	$	5.51	$	0.24

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 and nine-month periods ended September 30, 2008 as compared to the same periods for 2007 were as follows:


	Three Months			Nine Months
	Ended			Ended
	September 30,			September 30,
	2008 vs.			2008 vs.
	2007			2007
Favorable (unfavorable) variances:
Oil and Gas Activities:
Canada	$	(655	)	$	(1,404	)
Ecuador		(102	)		(102	)
China		(223	)		(456	)
U.S.		(475	)		(170	)
Corporate		(1,075	)		(2,636	)

		(2,530	)		(4,768	)
Less: stock based compensation		411			521

	$	(2,119	)	$	(4,247	)

Canada

As noted in Note 14 to the accompanying financial statements, the Company acquired working interests in two leases located in Alberta, Canada in July 2008. General and administrative costs related to Canada in 2008 consist of hiring key staff, reallocation of existing resources and some initial office setup costs. In prior periods, these costs were recorded in the Business and Technology Development segment.

China

General and administrative expenses related to the China operations increased $0.2 million for the three-month period ended September 30, 2008 as compared to the same period in 2007 mainly resulting from discretionary bonuses paid in the third quarter of 2008 compared to these same bonuses paid in the second quarter of 2007. The increase for the nine month period ended September 30, 2008 of $0.5 million when compared to 2007 was mainly due to increases in rent and facility costs and unrealized foreign exchange loss.

U.S.

General and administrative expenses related to the U.S. operations increased $0.5 million for the three-month period ended September 30, 2008 as compared to the same period in 2007 mainly resulting from discretionary bonuses paid in the third quarter of 2008 compared to these same bonuses paid in the second quarter of 2007. The increase for the nine month period ended September 30, 2008 of $0.2 million when compared to 2007 was mainly due to a lower allocation to capital and operations.

Corporate

General and administrative costs related to Corporate activities increased $1.1 million and $2.6 million for the three-month and nine-month periods ended September 30, 2008 when compared to the same periods in 2007. The increase in the three-month period resulted from a $0.7 million provision for uncollectible accounts (see Note 10 in the accompanying financial statements for further details) unrealized foreign exchange loss of $0.3 million, discretionary bonuses of $0.4 million and corporate aircraft costs of $0.3 million. These increases were somewhat offset by the reallocation of certain executive salaries to business development activities at the beginning of the third quarter 2008. The increase for the nine month period ended September 30, 2008 was mainly due to a $0.7 million provision for uncollectible accounts, a $0.6 million increase in salaries and benefits (consisting of an accrual of severance for an executive, an increase in executive bonuses and increase in stock based compensation offset by the reallocation of certain executive salaries to business development activities at the beginning of the quarter), corporate aircraft costs of $0.7 million, and increases in third party recruiting fees of $0.4 million and unrealized foreign exchange losses of $0.4 million.

Business and Technology Development

Business and technology development expenses decreased $0.9 million and $2.5 million (including changes in stock based compensation) for the three-month and nine-month periods ended September 30, 2008 when compared to the same periods in 2007 mainly as a result of a decrease in CDF operating costs due to several heavy oil upgrading runs in the first and second quarters of 2007. These decreases were offset by increases in compensation costs for the assembly of a core technology team.

Net Interest

Interest expense increased $0.3 million and $0.1 million for the three-month and nine-month periods ended September 30, 2008 when compared to the same periods in 2007 partially due to an additional draw on our U.S. loan, borrowings under a new loan for our China operations in the fourth quarter of 2007 and a short term loan that was outstanding from May 2008 to August 2008.

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 at the beginning of the third quarter of 2008 before steadily declining at the end of the third quarter to a level last reached in the first quarter of 2008. For the three-month and nine-month periods ended September 30, 2008, the Company had $18.6 million and $0.1 million unrealized gains on these derivative transactions. Changes in these unrealized settlement (losses) and gains by segment are detailed below:


	Three Months Ended		*Favorable*		Three Months Ended
	September 30,		*(Unfavorable)*		September 30,
	2008		*Variances*		2007
China	$	12,706	$	13,426	$	(720	)
U.S.		5,847		6,857		(1,010	)

	$	18,553	$	20,283	$	(1,730	)


	Nine Months Ended			*Favorable*			Nine Months Ended
	September 30,			*(Unfavorable)*			September 30,
	2008			*Variances*			2007
China	$	(2,130	)	$	(1,410	)	$	(720	)
U.S.		2,252			4,214			(1,962	)

	$	122		$	2,804		$	(2,682	)

Depletion and Depreciation

Depletion and depreciation increased $2.1 million and $5.7 million for the three-month and nine-month periods ended September 30, 2008 as compared to the same periods in 2007, respectively. This is partially due to a $0.4 million and $1.0 million increase in depreciation of the CDF, increases in depletion rates for China and $0.4 million in the U.S.

China

China’s depletion rate increased $8.99, and $11.23, per Boe for the three-month and nine-month periods ended September 30, 2008 when compared to the same periods in 2007. This resulted in a $1.1 million, and $4.1 million, increase in depletion expense for the

three-month and nine-month periods ended September 30, 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

Net cash and cash equivalents increased for the three-month period ended September 30, 2008 by $51.4 million compared to $3.7 million for the same period in 2007. Net cash and cash equivalents increased for the nine-month period ended September 30, 2008 by $50.3 million compared to $0.9 million for the same period in 2007. Reasons for the changes for these periods are as follows.

Operating Activities

Operating activities provided $1.7 million in cash for the three-month period ended September 30, 2008 compared to $1.8 million for the same period in 2007. Operating activities provided $7.4 million in cash for the nine-month period ended September 30, 2008 compared to $4.6 million for the same period in 2007. The increase in cash from operating activities for the three-month and nine-month periods ended September 30, 2008 was mainly due to an increase in oil and gas production prices offset by an increase in expenses, as well as a decrease in changes in working capital when compared to the same periods in 2007.

Investing Activities

Investing activities used $29.1 million in cash for the three-month period ended September 30, 2008 compared to $7.0 million for the same period in 2007. Investing activities used $39.5 million in cash for the nine-month period ended September 30, 2008 compared to $11.4 million for the same period in 2007. The main reason for the differences is the $22.3 million paid as part of the cost of the acquisition of 100% working interests in two leases located in the Athabasca oil sands region in the Province of Alberta, Canada (see Note 14 in the accompanying financial statements for more details). There was also a decrease in capital asset expenditures of $5.7 million for the nine-month period ended September 30, 2008 as compared to the same period in 2007.

Changes in capital investments by segment are detailed below:


	Three-Month Periods Ended							Nine-Month Periods Ended
	September 30,							September 30,
					(Increase)							(Increase)
	2008		2007		Decrease			2008		2007		Decrease
Oil and Gas Activities:
Canada	$	3,999	$	—	$	(3,999	)	$	3,999	$	—	$	(3,999	)
China		1,795		7,735		5,940			5,566		18,053		12,487
U.S.		596		645		49			3,797		2,438		(1,359	)
Business and Technology Development		2,566		720		(1,846	)		3,510		2,066		(1,444	)

	$	8,956	$	9,100	$	144		$	16,872	$	22,557	$	5,685

•

Canada

As noted above, two leases located in Canada were acquired in the third quarter of 2008. Capital investments this quarter consisted of capitalized interest, seismic/ERT and environmental work.

•

China

The decrease in investment in China in the third quarter of 2008 compared to 2007 was the result of a $1.4 million decrease in capital spending at Zitong and a $4.5 million decrease in capital spending at Dagang. The decrease in investment in China for the nine-month period ended September 30, 2008 was the result of a $7.3 million decrease in capital spending at Zitong and a $5.2 million decrease in capital spending at Dagang. Spending at Zitong during 2008 was limited to expenditures relating to the commencement of the second phase of the exploration program, which were relatively minor compared to the drilling and completion costs incurred during 2007 for completing the first phase of the program, which was concluded in December 2007. At Dagang, we spud five new development wells in 2007 compared to 2008, where we only completed a series of fracture stimulation projects.

•

U.S.

The $1.4 million increase in U.S. capital spending in the nine-month period ended September 30, 2008 compared to 2007 was mainly due to the eight well drilling program at South Midway in 2008 compared to the cost of a new steam generator in 2007.

•

Business and Technology Development

The increase in capital spending during the three-month and nine-month periods ending September 30, 2008 when compared to 2007 was due to the timing of costs relating to the construction and delivery of the Feedstock Test Facility (“FTF”).

Financing Activities

Financing activities for the three-month and nine-month periods ended September 30, 2008 consisted mainly of $82.3 million private placement proceeds realized in the third quarter of 2008. In July 2008, the Company completed a Cdn.$88.0 million private placement consisting of 29,334,000 Special Warrants (“Special Warrants”) at Cdn.$3.00 per Special Warrant (the “Offering”). Each Special Warrant entitled the holder to one common share of the Company upon exercise of the Special Warrant. In August 2008, all of the Special Warrants were exercised for 29,334,000 common shares. The net proceeds from the Offering of the Special Warrants was approximately Cdn.$83.4 million. In addition, 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. At the lender’s option, the principal and accrued and unpaid interest, was converted in August 2008 into the Company’s common shares at a conversion price of Cdn.$2.24 per share. These cash inflows were offset by $1.3 million, and $2.6 million in professional fees and expenses associated with the pursuit of corporate financing initiatives by the Company’s Chinese subsidiary, Sunwing Energy.

Outlook for balance of 2008

In the second and third quarters of 2008 the Company completed three key transactions: 1) the acquisition of high quality oilsand assets in the Athabasca region of Canada (named “Tamarack”), 2) an agreement with the Government of Ecuador on the development of a major heavy oil block in Ecuador (“Pungarayacu”), and 3) a Cdn.$88 million special warrant financing that provided investors access to Ivanhoe Energy common shares at Cdn.$3.00 per share. With these transactions, the Company has taken significant steps towards its transition to a heavy oil exploration, production and upgrading company.

The balance of 2008 will be dedicated primarily to formulating the development plans for the Tamarack project in Alberta and for Pungarayacu in Ecuador, including advancing the permitting processes. In addition, the Company will commission and begin operating the HTL Feedstock Test Facility in San Antonio, and will continue with HTL engineering of commercial scale HTL facilities consistent with the development plans for Tamarack and Pungarayacu.

In addition to Tamarack and Pungarayacu, the Company will continue to pursue ongoing discussions related to other HTL heavy oil opportunities in Canada, Latin America, the Middle East and North Africa. The Company will also continue to selectively invest in non-HTL oil and gas development activities in California and China.

In parallel with these project development activities, the Company will continue to pursue discussions with potential strategic partners related to the development of Tamarack, Pungarayacu, and other potential heavy oil opportunities around the world. These discussions are focused primarily on national oil companies and other sovereign or government entities from Asian and Middle Eastern countries that have approached the Company and expressed interest in participating in the Company’s heavy oil activities in Ecuador, Canada and around the world.

Contractual Obligations

The table below summarizes the contractual obligations that are reflected in the Unaudited Condensed Consolidated Balance Sheet as at September 30, 2008 and/or disclosed in the accompanying Notes:


	Payments Due by Year
	(stated in thousands of U.S. dollars)
	Total		2008		2009		2010		2011		After 2011
Consolidated Balance Sheets:
Note payable — current portion	$	18,111	$	12,920	$	5,191	$	—	$	—	$	—
Long term debt		45,640		—		—		9,538		36,102		—
Asset retirement obligation		3,673		—		15		1,905		—		1,753
Long term obligation		1,900		—		1,900		—		—		—
Other Commitments:
Interest payable		2,573		803		1,089		681		—		—
Lease commitments		2,610		259		893		773		549		136
Zitong exploration commitment		22,500		2,500		9,000		11,000		—		—

Total	$	97,007	$	16,482	$	18,088	$	23,897	$	36,651	$	1,889

Off Balance Sheet Arrangements

As at September 30, 2008 there were no 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. The Company does not engage in trading activities involving non-exchange traded contracts, and therefore is not materially exposed to any financing, liquidity, market or credit risk that could arise if it had engaged in such relationships. The Company does not have relationships and transactions with persons or entities that derive benefits from their non-independent relationship with it, or its related parties, except as disclosed herein.

Outstanding Share Data

As at November 3, 2008, there were 279,211,916 common shares of the Company issued and outstanding. Additionally, the Company had 11,400,000 share purchase warrants outstanding and exercisable to purchase 11,400,000 common shares. As at November 3, 2008, there were 13,332,574 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
	3rd Qtr		2nd Qtr			1st Qtr			4th Qtr			3rd Qtr			2nd Qtr			1st Qtr			4th Qtr
Total revenue	$	35,626	$	(2,772	)	$	11,169		$	5,848		$	8,823		$	9,589		$	9,257		$	11,137
Net income (loss):
Canadian GAAP	$	10,062	$	(21,731	)	$	(8,544	)	$	(18,849	)	$	(7,232	)	$	(6,579	)	$	(6,547	)	$	(11,323	)
U.S. GAAP	$	25,824	$	(32,981	)	$	(10,495	)	$	(16,094	)	$	(2,551	)	$	(1,211	)	$	(7,536	)	$	(18,255	)
Net income (loss) per share:
Canadian GAAP	$	0.04	$	(0.09	)	$	(0.03	)	$	(0.07	)	$	(0.03	)	$	(0.03	)	$	(0.03	)	$	(0.05	)
U.S. GAAP	$	0.10	$	(0.13	)	$	(0.04	)	$	(0.07	)	$	(0.01	)	$	—		$	(0.03	)	$	(0.08	)

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 $12.8 million 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. The differences in the net loss and net loss per share for the second quarter of 2008 were mainly due to an additional negative $12.2 million fair value adjustment of

derivative instruments for U.S. GAAP. The differences in the net income and net income per share for the third quarter of 2008 were mainly due to an additional $14.6 million positive fair value adjustment of derivative instruments for U.S. GAAP.

Transition to International Financial Reporting Standards (“IFRS”)

In April 2008, the CICA published the exposure draft “Adopting IFRSs in Canada”. The exposure draft proposes to incorporate IFRS into the CICA Accounting Handbook effective for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. At this date, publicly accountable enterprises will be required to prepare financial statements in accordance with IFRS. The company is currently reviewing the standards to determine the potential impact on its consolidated financial statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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 or to management’s objectives, policies and processes to manage risks from the previous year. The risks associated with our financial instruments and our policies for minimizing these risks are detailed below.

Market Risk

Commodity Price Risk


	Three Months Ended			*Favorable*		Three Months Ended
	September 30,			*(Unfavorable)*		September 30,
	2008			*Variances*		2007
China	$	(1,808	)	$	(1,808)	$	—
U.S.		(1,927	)		(1,504)		(423	)

	$	(3,735	)	$	(3,312)	$	(423	)


	Nine Months Ended			*Favorable*		Nine Months Ended
	September 30,			*(Unfavorable)*		September 30,
	2008			*Variances*		2007
China	$	(4,663	)	$	(4,663)	$	—
U.S.		(5,374	)		(5,128)		(246	)

	$	(10,037	)	$	(9,791)	$	(246	)

Both realized and unrealized gains and losses on derivatives have been recognized in the results of operations.

On September 30, 2008, the Company’s open positions on the derivative liabilities referred to above had a fair value of $9.3 million. A 10% increase in oil prices would increase the fair value, and consequently increase the net loss (or reduce net income), by approximately $3.3 million, while a 10% decrease in prices would reduce the fair value, and consequently reduce the net loss (or increase net income), by approximately $3.1 million. The fair value change assumes volatility based on prevailing market parameters at September 30, 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, the Company does not expect to face foreign exchange risks associated with its production revenues. However, some of 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 the Chinese operations are paid in Chinese renminbi. The majority of costs incurred in the administrative offices in Vancouver and Calgary, as well as some business development costs, are paid in Canadian dollars. In addition, with the recent property acquisition in Alberta (see Note 14) the Company’s Canadian dollar expenditures have increased during the most recent quarter along with an increase in cash and debt balances denominated 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 September 30, 2008 on net loss and accumulated deficit for the nine-month period ended September 30, 2008 is a $1.8 million increase, and a $1.4 million decrease, respectively. To help reduce the Company’s exposure to foreign currency risk it seeks to maximize the expenditures and contracts denominated in U.S. dollars and minimize those denominated in other currencies, except for its Canadian activities where it attempts to hold cash denominated in Canadian dollars in order to manage its currency risk related to outstanding debt and current liabilities denominated in Canadian dollars.

Interest Rate Risk

Credit Risk

Liquidity Risk

Item 4. Controls and Procedures

The Company’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 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 quarter ended September 30, 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:

In connection with the Talisman lease acquisition and the entering into of the specific Services Contract for the exploration and development of Block 20 in Ecuador, our risk factors have been updated. As a result, the following risk factors should be reviewed and given careful consideration in addition to the risk factors set forth in the Annual Report on Form 10-K for the year ended December 31, 2007.

Capital Requirements and Additional Financing. Any future costs of the development of an HTL™ plant and field development costs for both the Talisman leases and Block 20 in Ecuador are currently intended to be sourced from a combination of strategic investors and/or traditional debt and equity markets, either at the Ivanhoe parent company level or at the subsidiary or project level. Capital requirements are subject to oil and natural gas prices and capital market risks, primarily the availability and cost of capital. There can be no assurance that any such project will be completed or capable of operating at any specified level or that any or all of such required financing will be obtained by the Company on favorable terms or at all.

Reserves. No reserves have yet been established in respect of the Talisman leases or Block 20 in Ecuador (“Ecuador Block 20”). There are numerous uncertainties inherent in estimating reserves, including many factors beyond Ivanhoe’s control and no assurance can be given that any level of reserves or recovery thereof will be realized. In general, estimates of reserves are based upon a number of assumptions made as of the date on which the estimates were determined, many of which are subject to change and are beyond the Company’s control.

Stage of Development. While the Company plans to establish integrated HTL™ projects on Lease 10 and on Ecuador Block 20, such projects are currently at a very early stage of development and, accordingly, no feasibility or engineering studies have been produced. There can be no assurances that such projects will be completed within any time frame or within the parameters of any determined capital cost. The Company has not yet established a defined schedule for financing and developing such projects. Development of the projects may suffer delays, interruption of operations or increased costs due to many factors, including, without limitation: breakdown or failure of equipment or processes; construction performance falling below expected levels of output or efficiency, design errors, challenges to proprietary technology, contractor or operator errors; non-performance by third party contractors; labour disputes, disruptions or declines in productivity; increases in materials or labour costs; inability to attract sufficient numbers of qualified workers; delays in obtaining, or conditions imposed by, regulatory approvals; violation of permit requirements; disruption in the supply of energy; and catastrophic events such as fires; earthquakes, storms or explosions.

Nature of Oil Sands and Heavy Oil Exploration and Development and Operational Risks. Oil sands and heavy oil exploration and development are very competitive and involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. As with any petroleum property, there can be no assurance that oil will be produced from the lands underlying the leases. Furthermore, the viability and marketability of any production from the properties may be affected by numerous factors beyond Ivanhoe’s control. These factors include, but are not limited to, market fluctuations of prices, proximity and capacity of pipelines and processing equipment, electricity transmission and distribution system, transportation arrangements, equipment availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, land tenure, allowable production, importing and exporting of oil and gas and environmental protection). The extent of these factors cannot be accurately predicted. In the event that Ivanhoe’s proposed HTL™ projects in Alberta and Ecuador are developed and become operational, there is no assurance that such projects will have production in any specific quantities or within any defined framework of costs, or that it will not cease producing entirely in certain circumstances. Because operating costs for production from oil sands and heavy oil fields may be substantially higher than operating costs to produce conventional crude oil, an increase in such costs may render the extraction of resources from the proposed projects uneconomical. Moreover, it is possible that other developments, such as increasingly strict environmental and safety laws and regulations and enforcement policies thereunder and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities, delays or an inability to complete the proposed project or the abandonment of the proposed project. Changing oil prices in the future could render development of the leases uneconomical.

SAGD Recovery Process and Technology Risks. Ivanhoe intends to integrate established SAGD thermal recovery techniques with its patented HTL™ upgrading process. There are risks associated with the implementation of the HTL™ process and no commercial-scale HTL™ facility based on the Company’s technology has been constructed to date. In addition, recovery using the SAGD process is subject to technical and financial uncertainty and positioning these technologies as conceptualized may result in unforeseen issues and challenges that may require engineering remediation. There is no assurance that capital and operating cost performance as anticipated from the integration technologies will be realized.

Regulations, Permits, Leases and Licenses. Oil sands development in Alberta and heavy oil extraction in Ecuador are subject to substantial regulation relating to the exploration for, and the development, production, upgrading, marketing, pricing, taxation, and transportation of oil sands bitumen and heavy oil and related products and other matters, including environmental protection.

Legislation and regulations may be changed from time to time in response to economic or political conditions. The exercise of discretion by governmental authorities under existing legislation and regulations, the implementation of new legislation or regulations or the amendment of existing legislation and regulations affecting the crude oil and natural gas industry generally could materially increase the costs of developing the Talisman leases and Ecuador Block 20 and could have a material adverse impact on the Company’s business. More particularly, there can be no assurance that income tax laws, royalty regulations and government incentive programs related to the Company’s proposed developments will not be changed in a manner which may adversely affect such development and cause delays, inability to complete or abandonment of the proposed projects.

Failure to obtain all necessary permits, leases, licenses and approvals, or failure to obtain them on a timely basis, could result in delays or restructuring of the project and increased costs, all of which could have a material adverse affect on the Company.

Construction, operation and decommissioning of any projects on the Talisman leases will be conditional upon the receipt of necessary permits, leases, licenses and other approvals from applicable governmental and regulatory authorities. The approval process can involve stakeholder consultation, environmental impact assessments, public hearings and appeals to tribunals and courts, among other things. An inability to secure local and regional community support could result in the necessary approvals being delayed or stopped. There is no assurance such approvals will be issued, or if granted, will not be appealed or cancelled or will be renewed upon expiry or will not contain terms and conditions that adversely affect the final design or economics of the project.

Environmental Regulation. Oil sands and heavy oil extraction, upgrading and transportation operations are subject to extensive regulation and various approvals are required thereunder in respect of such activities. Such laws provide for restrictions and prohibitions on releases or emissions of various substances produced or used in association with petroleum activities, and address the decommissioning, abandonment and reclamation of properties at the end of their economic life. Compliance with such laws and the terms and conditions of any such approvals, if obtained, both now and in the future, could increase the cost of carrying out the Company’s business plans, necessitate alteration of those plans, require a change in or cessation of operations thereon (if commenced) or result in delays. The effect on the Company could be material and adverse. A violation of any such laws may result in the issuance of remedial orders, the suspension of approvals or the imposition of significant fines or penalties. No assurance can be given with respect to the impact of future environmental laws or the approvals, processes or other requirements thereunder on Ivanhoe’s ability to develop or operate the affected properties.

Human Resources. Development of the Talisman leases and Ecuador Block 20 will require experienced employees with particular areas of expertise. Currently, there are many other petroleum projects and expansions underway around the world. The Company’s proposed development projects may compete with these other projects for experienced employees resulting in payment of increased compensation to such employees or increase the Company’s reliance and associated costs from partnering or outsourcing arrangements. In addition, there can be no assurance that all of the required employees with the necessary abilities and expertise will be available.

Future Payments and Security granted to Talisman under the Talisman Lease Acquisition. Future payments will be required to be made by the Company to Talisman pursuant to the Company’s acquisition of the Talisman leases, including: (i) Cdn.$12,500,000 principal owing by the Company on a promissory note which is due to be repaid on December 31, 2008; (ii) Cdn.$40,000,000 principal owing by Ivanhoe on the Convertible Note which is due July 11, 2011 unless and to the extent such principal is converted into common shares of the Company before such due date; (iii) up to Cdn.$15,000,000 may be payable by the Company in respect of the Contingent Payment if requisite governmental and other approvals necessary to develop the northern border of Lease 10 are obtained; and (iv) a further Cdn.$15,000,000 could become payable by the Company to acquire Talisman’s 75% interest in Lease 50 in 2008 if the remaining working interest holder does not complete the acquisition of Talisman’s interest in certain circumstances. The Company intends to finance such future payments from a combination of strategic investors and/or traditional debt and equity markets, either at the Ivanhoe parent company level or at the subsidiary or project level. There can be no assurance that such financing will be obtained by the Company on favorable terms or at all and any future equity issuances may be dilutive to investors. Failure to obtain such additional financing or failure to meet ongoing covenants or default terms could result in the default of the Company under the terms of the security granted by the Company in favor of Talisman under the Talisman Lease Acquisition. This security includes a first fixed charge and security interest in favor of Talisman over the Talisman leases and a subordinate security over certain present and after acquired property of Ivanhoe. In the case of such default, Talisman could foreclose on the assets of the Company so secured, including the Talisman leases.

Royalty Regime. In the event that a project is developed by the Company and becomes operational, the Company’s revenue and expenses in respect of the Talisman leases will be directly affected by the royalty regime applicable to such project. The economic benefit of future capital expenditures for such project is, in many cases, dependent on a satisfactory royalty regime.

On October 25, 2007, the Government of Alberta announced a new proposed royalty regime applicable to oil sands projects. The new regime, proposed to be effective January 1, 2009, would introduce new royalties for conventional oil, natural gas and oil sands production that are linked to price and production levels and would apply to both new and existing oil sands projects. Currently, in respect of oil sands projects having regulatory approval, a royalty of one percent of gross bitumen revenue is payable prior to the payout of specified allowed costs, including certain exploration and development costs, operating costs and a return allowance. Once such allowed costs have been recovered, a royalty of the greater of (i) one percent of gross bitumen revenue and (ii) 25 percent of net bitumen revenue, is levied. The new regime would retain the pre-payout gross royalty and post-payout net revenue royalty framework and introduces price sensitivity to establish royalty rates. It would apply a royalty of between one and nine percent on gross bitumen production revenue before payout and between 25 and 40 percent on net bitumen production revenue after payout, dependent on the price of crude oil. The minimum rates (one percent pre-payout and 25 percent post-payout) apply when the Canadian dollar equivalent of the US dollar West Texas Intermediate (“WTI”) posted crude oil price is at or below $55 per barrel. The maximum rates (nine percent pre-payout and 40 percent post-payout) would apply when the Canadian dollar equivalent of the US dollar WTI posted crude oil price is $120 per barrel or higher at the time of production. The royalty rates would adjust pro-rateably when the Canadian dollar equivalent of the WTI crude oil price is between $55 and $120 per barrel.

Implementation of the proposed changes to the Alberta royalty regime is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation and development of proprietary software to support the calculation and collection of royalties. Additionally, certain proposed changes contemplate further public and/or industry consultation. There may be modifications introduced to the proposed royalty structure prior to the implementation thereof.

An increase in royalties may reduce the Company’s future earnings, if any, and could make future capital expenditures or Ivanhoe’s operations in respect of the Talisman leases uneconomic and could materially reduce the value of the associated assets.

There is no assurance that the federal government and the Province of Alberta will adopt or maintain a royalty regime that will make development of the Talisman leases economic.

Title Risks and Aboriginal Claims. The Company has not obtained title opinions in respect of the Talisman leases and, accordingly, its ownership of the Talisman leases may be subject to prior unregistered agreements or interests or undetected claims or interests that could defeat or subordinate the Company’s interest therein. If this occurred, the Company’s entitlement to the economic benefits, if any, associated with the Talisman leases, could be jeopardized, which could have a material adverse effect on the Company’s financial condition, results of operations and ability to execute its business plan in a timely manner or at all.

In addition, aboriginal peoples have claimed aboriginal title and rights to large areas of land in western Canada where crude oil and natural gas operations are conducted, including a claim filed against the Government of Canada, the Province of Alberta, certain governmental entities and the regional municipality of Wood Buffalo (which includes the City of Fort McMurray, Alberta) claiming, among other things, aboriginal title to large areas of lands surrounding Fort McMurray where most of the oil sands operations in Alberta are located. Such claims, if successful, could have a significant adverse effect on the Company and the Talisman leases.

Emissions Management. It is noted that Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder, which requires signatory nations to reduce their nation-wide emissions of carbon dioxide and other greenhouse gases (“GHGs”). Extraction or upgrading operations in respect of the Talisman leases is likely to produce a significant amount of certain GHGs covered by the convention.

In order to meet its obligations under the Kyoto Protocol, the Canadian federal government will likely implement domestic legislation that applies to companies operating facilities in Canada. In April 2007, the federal government published its Regulatory Framework for Air Emissions (Framework), which outlines proposed new requirements governing the emission of GHGs and other industrial air pollutants through mandatory emissions reductions on a sector-by-sector basis. Sector-specific regulations are expected to come into force in 2010 and targets would be set relative to units of production rather than absolute reductions. The Framework also proposes a credit emissions trading system and creates an incentive to deploy carbon capture and storage measures.

GHG regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions from facilities in that province by reducing specified gas emissions relative to gross domestic product to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires emissions reductions

through the use of emission intensity targets (emission intensity is the amount of GHG emissions per unit of production or output). The Canadian federal government proposes to enter into equivalency agreements with provinces that establish a regulatory regime to ensure consistency of provincial GHG initiatives with the federal plan, although the success of any such plan is dependent on the prevailing political climate and Ivanhoe and other industry members may face multiple, overlapping levels of GHG regulation. The direct and indirect costs of these regulations, including any tax that the federal or provincial government may levy on GHG emissions, may adversely affect the Company’s operations and financial condition.

Any mandatory emission intensity reductions to which Ivanhoe may be subject, whether in respect of the Talisman leases or otherwise, may not be technically or economically feasible to implement. Failure to meet any such requirements or successfully engage alternative compliance mechanisms (such as emissions credits) could materially adversely affect the Company’s ability to carry on the affected business.

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

In July 2008, in compliance with Rule 903 of Regulation S of the Securities Act of 1933, as amended (the “Securities Act”) and Regulation D of the Securities Act, the Company completed a Cdn.$88.0 million private placement consisting of 29,334,000 Special Warrants (“Special Warrants”) at Cdn.$3.00 per Special Warrant (the “Offering”). Each Special Warrant entitled the holder to one common share of the Company upon exercise of the Special Warrant. In August 2008, all of the Special Warrants were exercised for 29,334,000 common shares.

In July 2008, in compliance with Rule 903 of Regulation S of the Securities Act, the Company issued a convertible promissory note to Talisman in the principal amount of Cdn.$40.0 million bearing interest at a rate per year equal to the prime rate plus 2%, calculated daily and not compounded, and payable semi-annually, maturing in July 2011 and convertible (as to the outstanding principal amount), at Talisman’s option, into a maximum of 12,779,552 common shares of the Company at Cdn.$3.13 per common share(the “Convertible Note”).

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

10.1		Cdn.$12.5 million Promissory Note in favour of Talisman Energy Canada due December 31, 2008

10.2		Cdn.$40 million Promissory Note in favour of Talisman Energy Canada due July 11, 2011 and convertible at the option of Talisman Energy Canada into 12,779,552 common shares at Cdn.$3.13 per share

10.3		Fixed and Floating Charge Debenture of Ivanhoe Energy Inc. in favour of Talisman Energy Canada dated July 11, 2008 in the principal sum of Cdn.$67.5 million

10.4		Pledge Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada

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: November 10, 2008

INDEX TO EXHIBITS


Exhibit
Number		Description
10.1		Cdn.$12.5 million Promissory Note in favour of Talisman Energy Canada due December 31, 2008

10.2		Cdn.$40 million Promissory Note in favour of Talisman Energy Canada due July 11, 2011 and convertible at the option of Talisman Energy Canada into 12,779,552 common shares at Cdn.$3.13 per share

10.3		Fixed and Floating Charge Debenture of Ivanhoe Energy Inc. in favour of Talisman Energy Canada dated July 11, 2008 in the principal sum of Cdn.$67.5 million

10.4		Pledge Agreement dated July 11, 2008 between Ivanhoe Energy Inc. and Talisman Energy Canada

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