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, 2010


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

For the transition period from to

Commission File Number 000-30586

IVANHOE ENERGY INC.

(Exact name of registrant as specified in its charter)


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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No

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

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


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

As at October 29, 2010, Ivanhoe Energy Inc. had 334,233,100 Common Shares outstanding with no par value.

TABLE OF CONTENTS


		Page
PART I FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Consolidated Balance Sheets as at September 30, 2010 and December 31, 2009		3

Unaudited Consolidated Statements of Operations and Comprehensive Loss for the Three and Nine Months Ended September 30, 2010 and 2009		4

Unaudited Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2010 and 2009		5

Notes to the Unaudited Consolidated Financial Statements		6

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

Item 4. Controls and Procedures		30

PART II OTHER INFORMATION

Item 1. Legal Proceedings		31

Item 6. Exhibits		31

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I FINANCIAL INFORMATION

Item 1. Financial Statements

IVANHOE ENERGY INC.

Unaudited Consolidated Balance Sheets
(thousands of US dollars)


	September 30, 2010			December 31, 2009

Assets
Current Assets
Cash and cash equivalents	$	90,248		$	21,512
Accounts receivable		4,332			5,021
Note receivable		260			225
Prepaid and other current assets		1,329			771
Restricted cash (Note 12)		2,850			2,850

		99,019			30,379

Oil and gas properties and development costs, net (Note 2)		213,685			158,392
Intangible assets – HTL^TM technology (Note 3)		92,153			92,153
Long term assets		2,126			839

	$	406,983		$	281,763


Liabilities and Shareholders’ Equity
Current Liabilities
Debt (Note 4)	$	38,279		$	—
Accounts payable and accrued liabilities		14,394			10,779
Income tax payable		—			530
Asset retirement obligations (Note 5)		—			753

		52,673			12,062

Long term debt (Note 4)		—			36,934
Asset retirement obligations (Note 5)		496			195
Long term obligation		1,900			1,900
Future income tax liability (Note 11)		22,624			22,643

		77,693			73,734


Commitments and contingencies (Note 6)

Going concern and basis of presentation (Note 1)

Shareholders’ Equity (Note 7)
Share capital, issued 334,011,588 common shares
December 31, 2009 282,558,593 common shares		549,220			422,322
Purchase warrants		33,423			19,427
Contributed surplus		20,343			20,029
Convertible note		2,086			2,086
Accumulated deficit		(275,782	)		(255,835	)

		329,290			208,029

	$	406,983		$	281,763

(See Notes to the Unaudited Consolidated Financial Statements)

IVANHOE ENERGY INC.

Unaudited Consolidated Statements of Operations and Comprehensive Loss
(thousands of US dollars, except per share amounts)


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
				(Note 12)						(Note 12)

Revenue
Oil revenue	$	4,177		$	7,917		$	15,554		$	19,659
Gain (loss) on derivative instruments		—			72			—			(1,020	)
Interest		88			2			130			20

		4,265			7,991			15,684			18,659

Expenses
Operating		1,975			2,907			6,577			8,052
General and administrative (Note 2)		6,055			4,412			16,510			14,126
Business and technology development		3,045			2,301			7,979			6,104
Depletion and depreciation		2,079			5,308			6,744			17,308
Foreign exchange (gain) loss		(1,188	)		2,815			(2,289	)		4,501
Interest and financing		6			177			14			512
Provision for impairment		—			948			—			948

		11,972			18,868			35,535			51,551


Loss from continuing operations before income taxes		(7,707	)		(10,877	)		(19,851	)		(32,892	)

(Provision for) recovery of income taxes
Current		—			(618	)		(115	)		(1,624	)
Future		479			8,700			19			8,700

		479			8,082			(96	)		7,076


Net loss from continuing operations		(7,228	)		(2,795	)		(19,947	)		(25,816	)
Net loss from discontinued operations (net of tax of $29.6 million for 2009) (Note 12)		—			(23,290	)		—			(23,921	)

Net loss and comprehensive loss		(7,228	)		(26,085	)		(19,947	)		(49,737	)

Accumulated deficit, beginning of period		(268,554	)		(217,835	)		(255,835	)		(194,183	)

Accumulated deficit, end of period	$	(275,782	)	$	(243,920	)	$	(275,782	)	$	(243,920	)


Net loss per share
Net loss from continuing operations, basic and diluted	$	(0.02	)	$	(0.01	)	$	(0.06	)	$	(0.09	)
Net loss from discontinued operations, basic and diluted		—			(0.08	)		—			(0.09	)

Net loss per share, basic and diluted	$	(0.02	)	$	(0.09	)	$	(0.06	)	$	(0.18	)


Weighted average number of shares
Basic and diluted (in thousands)		334,012			279,427			325,153			279,381

(See Notes to the Unaudited Consolidated Financial Statements)

IVANHOE ENERGY INC.

Unaudited Consolidated Statements of Cash Flows
(thousands of US dollars)


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009

Operating Activities
Net loss	$	(7,228	)	$	(26,085	)	$	(19,947	)	$	(49,737	)
Net loss from discontinued operations		—			23,290			—			23,921
Items not requiring use of cash
Depletion and depreciation		2,079			5,308			6,744			17,308
Provision for impairment		—			948			—			948
Stock based compensation		1,052			1,270			2,610			2,242
Unrealized (gain) loss on derivative instruments		—			(72	)		—			1,632
Unrealized foreign exchange (gain) loss		(1,496	)		2,786			(2,834	)		4,432
Future income tax recovery		(479	)		(8,700	)		(19	)		(8,700	)
Other		4			104			14			268
Abandonment costs recovered (settled) (Note 5)		3			—			(179	)		—
Changes in non-cash working capital items (Note 10)		644			85			(151	)		(3,177	)

Net cash used in operating activities from continuing operations		(5,421	)		(1,066	)		(13,762	)		(10,863	)
Net cash (used in) provided by operating activities from discontinued operations		—			(135	)		—			2,703

Net cash used in operating activities		(5,421	)		(1,201	)		(13,762	)		(8,160	)


Investing Activities
Additions to oil and gas properties and development costs		(20,428	)		(5,823	)		(60,991	)		(17,723	)
Increase in restricted cash		—			(2,000	)		—			(2,000	)
Other		(442	)		(202	)		(1,288	)		(355	)
Changes in non-cash working capital items (Note 10)		525			(499	)		3,358			(1,186	)

Net cash used in investing from continuing operations		(20,345	)		(8,524	)		(58,921	)		(21,264	)
Net cash provided by investing activities from discontinued operations		—			35,878			—			35,292

Net cash (used in) provided by investing activities		(20,345	)		27,354			(58,921	)		14,028


Financing Activities
Shares issued on private placements, net of share issue costs		(69	)		—			135,696			—
Proceeds from exercise of options and warrants		8			98			2,102			98
Payments of debt obligations		—			—			—			(416	)
Other		—			—			—			(100	)
Changes in non-cash working capital items (Note 10)		(41	)		—			(2	)		(26	)

Net cash (used in) provided by financing activities from continuing operations		(102	)		98			137,796			(444	)
Net cash used in financing activities from discontinued operations		—			(5,200	)		—			(5,200	)

Net cash (used in) provided by financing activities		(102	)		(5,102	)		137,796			(5,644	)


Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency		2,299			12			3,623			(23	)


Increase (decrease) in cash and cash equivalents, for the period		(23,569	)		21,063			68,736			201
Cash and cash equivalents, beginning of period		113,817			18,403			21,512			39,265

Cash and cash equivalents, end of period	$	90,248		$	39,466		$	90,248		$	39,466


Cash and cash equivalents, end of period — continuing operations	$	90,248		$	39,466		$	90,248		$	39,466

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

(See Notes to the Unaudited Consolidated Financial Statements)

Notes to the Unaudited Consolidated Financial Statements
September 30, 2010

(all tabular amounts are expressed in thousands of US dollars except per share amounts)

1. GOING CONCERN AND BASIS OF PRESENTATION

The accounting policies of Ivanhoe Energy Inc. (the “Company” or “Ivanhoe”) are in accordance with accounting principles generally accepted in Canada. These policies are consistent with accounting principles generally accepted in the United States (“US”), except as outlined in Note 13. These unaudited interim consolidated financial statements do not include all disclosures normally provided in annual consolidated financial statements and should be read in conjunction with the Company’s most recent annual consolidated financial statements. In the opinion of management, the unaudited interim consolidated financial statements reflect all adjustments necessary for the fair presentation of the interim periods. The results of operations and cash flows are not necessarily indicative of the results for a full year.

The Company’s unaudited interim consolidated financial statements showing the financial position as at September 30, 2010, and the results of operations and cash flows for the three and nine months ended September 30, 2010 and 2009, have been prepared in accordance with generally accepted accounting principles (“GAAP”) as applied in Canada for a going concern, which assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities in the normal course of operations. Ivanhoe incurred a net loss of $19.9 million for the nine months ended September 30, 2010, and as of September 30, 2010, had an accumulated deficit of $275.8 million. Cash flow consumed in operating activities to date in 2010 was $13.8 million.

The Company currently anticipates incurring substantial expenditures to further its capital development programs, particularly those related to the development of exploration opportunities in China and Mongolia, the development of an oil sands project in Alberta and the development of a heavy oil field in Ecuador. The Company’s cash flow from operating activities will not be sufficient to both satisfy its current obligations and meet the requirements of these capital investment programs. Completion of these projects by the Company is dependent upon its ability to obtain capital to fund further development of these projects and others in the portfolio and to meet ongoing obligations. Ivanhoe intends to finance its future funding requirements primarily through a combination of strategic private investors and/or public equity markets. Without access to financing, there is a chance that the Company may not be able to continue as a going concern. These unaudited consolidated financial statements do not include any adjustments to the amounts and classification of assets and liabilities that would be necessary should the Company be unable to continue as a going concern.

2. OIL AND GAS PROPERTIES AND DEVELOPMENT COSTS


	September 30, 2010
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			Asia			Corporate			Development			Total

Oil and gas properties
Proved	$	—		$	—		$	153,963		$	—		$	—		$	153,963
Unproved		121,874			22,479			26,489			—			—			170,842

		121,874			22,479			180,452			—			—			324,805
Accumulated depletion								(106,398	)		—			—			(106,398	)
Accumulated provision for impairment								(16,550	)		—			—			(16,550	)

		121,874			22,479			57,504			—			—			201,857


Development costs
Feasibility studies and other deferred costs
Iraq and Libya — HTL^TM		—			—			—			—			834			834
Egypt — GTL		—			—			—			—			5,054			5,054
Accumulated provision for impairment		—			—			—			—			(5,888	)		(5,888	)
Feedstock test facility		—			—			—			—			11,357			11,357
Accumulated depreciation and impairment		—			—			—			—			(789	)		(789	)

		—			—			—			—			10,568			10,568


Furniture and equipment		30			408			543			1,429			68			2,478
Accumulated depreciation		(18	)		(99	)		(179	)		(909	)		(13	)		(1,218	)

		12			309			364			520			55			1,260

	$	121,886		$	22,788		$	57,868		$	520		$	10,623		$	213,685

As at September 30, 2010, $170.8 million (December 31, 2009 – $115.6 million) of costs related to unproved oil and gas properties are excluded from costs subject to depletion and depreciation. For the three and nine months ended September 30, 2010, the Company capitalized $2.8 million and $5.1 million respectively (2009 – $1.2 million and $3.2 million) of general and administrative expenses related directly to oil and gas activities and interest of $0.6 million and $1.8 million respectively (2009 – $0.5 million and $1.6 million) was capitalized on debt related to oil and gas acquisition activities.


	December 31, 2009
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			Asia			Corporate			Development			Total

Oil and gas properties
Proved	$	—		$	—		$	148,110		$	—		$	—		$	148,110
Unproved		94,431			6,755			14,411			—			—			115,597

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

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


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

		—			—			—			—			10,475			10,475


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

		16			116			43			318			11			504

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

In July 2009, the Company sold its US operating segment (see Note 12); consequently, the historical segment comparative information has been revised to reflect this sale.

3. INTANGIBLE ASSETS

In the 2005 merger with the Ensyn Group, Inc. (“Ensyn”), the Company acquired an exclusive, irrevocable license to deploy, worldwide, the HTL^TM Process for petroleum applications as well as the exclusive right to deploy the HTL^TM Process in all applications other than biomass. The Company’s carrying value of the HTL^TM Technology as at September 30, 2010, is $92.2 million (December 31, 2009 – $92.2 million). This intangible asset was not amortized and its carrying value was not impaired at September 30, 2010.

4. DEBT


	September 30,			December 31,
	2010			2009

Convertible note	$	38,842		$	38,005
Less: Unamortized discount		(563	)		(1,071	)

	$	38,279		$	36,934

The convertible note has a maturity of July 2011 and bears interest at 5.00% at September 30, 2010 (December 31, 2009 – 4.25%).

5. ASSET RETIREMENT OBLIGATIONS

Ivanhoe provides for the expected costs required to abandon its oil and gas assets. At September 30, 2010, the Company’s total estimated undiscounted inflated costs to settle its asset retirement obligations were approximately $1.3 million (December 31, 2009 – $0.9 million). These costs are expected to be incurred in 2012 and 2029 and have been discounted using a weighted average credit-adjusted risk-free rate of 5.1% (December 31, 2009 – 5.3%). A reconciliation of the discounted asset retirement obligations is as follows:


	September 30,			December 31,
	2010			2009

Balance, beginning of period	$	948		$	1,928
Liabilities incurred		287			185
Liabilities settled		(179	)		(118	)
Accretion expense		14			79
Revisions in estimated cash flows		(574	)		(1,126	)

Balance, end of period		496			948
Less current portion		—			(753	)

Balance, end of period	$	496		$	195

6. COMMITMENTS AND CONTINGENCIES

Zitong Block Exploration Commitment

Under the 30 year production sharing contract with China National Petroleum Corporation (“CNPC”) in the Zitong Block, located in the northwestern portion of the Sichuan Basin, the Company was obligated to conduct a minimum exploration program during the first three years ending December 1, 2005 (“Phase I”). The Company completed Phase I with a drilling shortfall of approximately 700 feet. In December 2007, the Company and Mitsubishi (the “Zitong Partners”) entered into the next three-year exploration phase (“Phase II”). The shortfall in Phase I drilling was carried over into Phase II.

By electing to participate in Phase II, the Zitong Partners had to relinquish 30%, plus or minus 5%, of the Zitong block acreage and complete a minimum work program involving the acquisition of approximately 200 miles of new seismic lines and approximately 23,700 feet of drilling (including the Phase I shortfall), with total net remaining estimated minimum expenditures for this program of $11.8 million at September 30, 2010. The Zitong Partners relinquished 25% of the Block to complete the Phase I relinquishment requirement. The Phase II seismic line acquisition commitment was fulfilled in the Phase I exploration program. Drilling of the two locations commenced in the second and third quarters of 2010 and evaluation of both prospects is expected to be finalized in late 2010. The Zitong Partners must complete the minimum work program by the end of the Phase II period, December 31, 2010, or pay to CNPC the cash equivalent of the deficiency in the work program for that exploration phase. The cash equivalent of the deficiency in the drilling program is defined as the actual average unit cost of the last well drilled multiplied by the footage shortfall. Based on the Company’s historical drilling costs, we estimate the Company’s portion of this deficiency to be $0.7 million at September 30, 2010. Subsequent to quarter end, the Company drilled the required contract commitment footage and no further deficiency exists. Following the completion of Phase II, the Zitong Partners must relinquish all of the remaining property except any areas identified for development and future production.

Nyalga Block Exploration Commitment

The exploration period for the Nyalga Block XVI in Mongolia is five years and consists of three phases of two years, one year and two years respectively, with the ability to nominate a two-year extension following the first or second phase. The minimum work obligations consist of $2.7 million for the first phase, with the majority of that commitment in the second year of the phase, $1.0 million for the second phase and $2.5 million for the third phase, with the majority of that commitment in the second year of that phase. If, in one year, more than the minimum is expended, the excess can be applied to reduce the minimum expenditure in the next year of that phase. During the initial seismic program, a portion of the block, representing approximately 16% of the total, was declared by the Mongolian government to be an historical site and operations on that portion of the block, the Delgerkhaan area, were suspended. A letter from the Mineral Resources and Petroleum Authority of Mongolia (the “MRPAM”) was received in May 2008 that stated that the obligations under year one of the first phase would be extended for one year from the time the Company is allowed access to the suspended area. To date, access has not been allowed and discussions with MRPAM are still ongoing as to the possibility of entering into this suspended area. Further to these discussions, the government has adjusted dates in which the project year begins. Year three of the exploration period, being year one of phase two, was adjusted to begin July 20, 2010. In accordance with its contractual obligations, the Company relinquished 25% of the block’s acreage in the third quarter. As at September 30, 2010, the Company has spent in excess of the commitments for the first phase. The minimum work obligation as at September 30, 2010, is $0.3 million.

Lease Commitments


											After
	Total		2010		2011		2012		2013		2013

Lease commitments	$	3,055	$	313	$	1,601	$	828	$	313		—

7. SHAREHOLDERS’ EQUITY


	Common Shares
	Number				Purchase			Contributed			Convertible
	(000s)		Amount		Warrants			Surplus			Note

Balance December 31, 2008		279,381	$	413,857	$	18,805		$	16,862		$	2,086
Shares issued for acquisition of a business		2,683		6,874		622			—			—
Shares issued for services		81		207		—			—			—
Exercise of stock options		414		1,384		—			(492	)		—
Stock based compensation expense		—		—		—			3,659			—

Balance December 31, 2009		282,559	$	422,322	$	19,427		$	20,029		$	2,086
Shares issued for cash, net of share issue costs		50,000		121,697		13,999			—			—
Shares issued for services		280		799		—			—			—
Exercise of stock options		1,171		4,393		—			(2,296	)		—
Exercise of purchase warrants		2		9		(3	)		—			—
Stock based compensation expense		—		—		—			2,610			—

Balance September 30, 2010		334,012	$	549,220	$	33,423		$	20,343		$	2,086

At September 30, 2010, there were 24.6 million purchase warrants issued and exercisable, of which 12.5 million were issued in 2010 with an exercise price of Cdn$3.16. The outstanding purchase warrants have a cash value on exercise of $73.7 million at September 30, 2010 (December 31, 2009 – $34.6 million). Stock options outstanding totaled 14.8 million with 2.8 million options granted in 2010.

In January 2010, one of the Company’s subsidiaries signed an agreement that granted a private investor an option to acquire 833,334 shares of the subsidiary for Cdn$25 million. The investor’s right to exercise the option is contingent upon the occurrence of specific trigger events that are specified in the contract, and the share purchase option does not become exercisable, if at all, until the first quarter of 2011. The option is valid for a period of one year. Given the specific terms and conditions contained in the contract, management believes the option has no current value at September 30, 2010.

8. SEGMENT INFORMATION

The Company has four reportable business segments: Oil and Gas – Integrated, Oil and Gas – Conventional, Business and Technology Development and Corporate, as described in Note 11 to the Audited Consolidated Financial Statements included in the 2009 Form 10-K.

The following tables present the Company’s segment information for the three and nine months ended September 30, 2010 and September 30, 2009, and identifiable assets as at September 30, 2010, and December 31, 2009:


	Three Months Ended September 30, 2010
	Oil and Gas											Business and
	Integrated						Conventional					Technology
	Canada			Ecuador			Asia			US		Development			Corporate			Total

Revenue
Oil	$	—		$	—		$	4,177		$	—	$	—		$	—		$	4,177
Interest		—			—			1			—		—			87			88

		—			—			4,178			—		—			87			4,265


Expenses
Operating		—			—			1,975			—		—			—			1,975
General and administrative		421			661			877			—		—			4,096			6,055
Business and technology development		54			15			—			—		2,976			—			3,045
Depletion and depreciation		2			14			1,914			—		81			68			2,079
Foreign exchange gain		(10	)		—			(49	)		—		—			(1,129	)		(1,188	)
Interest and financing		1			2			—			—		3			—			6

		468			692			4,717			—		3,060			3,035			11,972


Loss from continuing operations before income taxes		(468	)		(692	)		(539	)		—		(3,060	)		(2,948	)		(7,707	)

Recovery of income taxes
Current		—			—			—			—		—			—			—
Future		—			—			—			—		479			—			479

		—			—			—			—		479			—			479


Net loss from continuing operations		(468	)		(692	)		(539	)		—		(2,581	)		(2,948	)		(7,228	)
Net loss from discontinued operations		—			—			—			—		—			—			—

Net loss and comprehensive loss	$	(468	)	$	(692	)	$	(539	)	$	—	$	(2,581	)	$	(2,948	)	$	(7,228	)


Capital Investments	$	3,600		$	5,722		$	10,951		$	—	$	172		$	(17	)	$	20,428


	Nine Months Ended September 30, 2010
	Oil and Gas											Business and
	Integrated						Conventional					Technology
	Canada			Ecuador			Asia			US		Development			Corporate			Total

Revenue
Oil	$	—		$	—		$	15,554		$	—	$	—		$	—		$	15,554
Interest		—			—			5			—		—			125			130

		—			—			15,559			—		—			125			15,684


Expenses
Operating		—			—			6,577			—		—			—			6,577
General and administrative		1,293			1,759			2,438			—		—			11,020			16,510
Business and technology development		77			41			—			—		7,861			—			7,979
Depletion and depreciation		6			30			6,704			—		(173	)		177			6,744
Foreign exchange (gain) loss		(13	)		—			38			—		—			(2,314	)		(2,289	)
Interest and financing		4			2			—			—		8			—			14

		1,367			1,832			15,757			—		7,696			8,883			35,535


Loss from continuing operations before income taxes		(1,367	)		(1,832	)		(198	)		—		(7,696	)		(8,758	)		(19,851	)

(Provision for) recovery of income taxes
Current		—			—			(111	)		—		—			(4	)		(115	)
Future		—			—			—			—		19			—			19

		—			—			(111	)		—		19			(4	)		(96	)


Net loss from continuing operations		(1,367	)		(1,832	)		(309	)		—		(7,677	)		(8,762	)		(19,947	)
Net loss from discontinued operations		—			—			—			—		—			—			—

Net loss and comprehensive loss	$	(1,367	)	$	(1,832	)	$	(309	)	$	—	$	(7,677	)	$	(8,762	)	$	(19,947	)


Capital Investments	$	26,762		$	15,004		$	18,317		$	—	$	537		$	371		$	60,991


Identifiable Assets
As at September 30, 2010	$	122,198		$	24,677		$	71,023		$	—	$	103,050		$	86,035		$	406,983
As at December 31, 2009	$	94,594		$	7,597		$	57,528		$	—	$	102,878		$	19,166		$	281,763


	Three Months Ended September 30, 2009
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			Asia			US			Development			Corporate			Total

Revenue
Oil	$	—		$	—		$	7,917		$	—		$	—		$	—		$	7,917
Gain on derivative instruments		—			—			72			—			—			—			72
Interest		—			—			—			—			—			2			2

		—			—			7,989			—			—			2			7,991

Expenses
Operating		—			—			2,907			—			—			—			2,907
General and administrative		239			606			636			—			—			2,931			4,412
Business and technology development		104			—			—			—			2,197			—			2,301
Depletion and depreciation		1			11			5,130			—			129			37			5,308
Foreign exchange (gain) loss		(7	)		—			3			—			2			2,817			2,815
Interest and financing		—			—			151			—			25			1			177
Provision for impairment		—			—			—			—			948			—			948

		337			617			8,827			—			3,301			5,786			18,868


Loss from continuing operations before income taxes		(337	)		(617	)		(838	)		—			(3,301	)		(5,784	)		(10,877	)

(Provision for) recovery of income taxes
Current		—			—			(269	)		—			—			(349	)		(618	)
Future		—			—			—			—			8,700			—			8,700

		—			—			(269	)		—			8,700			(349	)		8,082


Net income (loss) from continuing operations		(337	)		(617	)		(1,107	)		—			5,399			(6,133	)		(2,795	)
Net loss from discontinued operations (net of tax of $29.6 million)		—			—			—			(23,290	)		—			—			(23,290	)

Net income (loss) and comprehensive income (loss)	$	(337	)	$	(617	)	$	(1,107	)	$	(23,290	)	$	5,399		$	(6,133	)	$	(26,085	)


Capital Investments	$	3,186		$	1,333		$	1,179		$	—		$	125		$	—		$	5,823


	Nine Months Ended September 30, 2009
	Oil and Gas												Business and
	Integrated						Conventional						Technology
	Canada			Ecuador			Asia			US			Development			Corporate			Total

Revenue
Oil	$	—		$	—		$	19,659		$	—		$	—		$	—		$	19,659
Loss on derivative instruments		—			—			(1,020	)		—			—			—			(1,020	)
Interest		—			—			4			—			—			16			20

		—			—			18,643			—			—			16			18,659

Expenses
Operating		—			—			8,052			—			—			—			8,052
General and administrative		573			1,583			1,663			—			—			10,307			14,126
Business and technology development		491			—			—			—			5,613			—			6,104
Depletion and depreciation		3			47			15,646			—			1,502			110			17,308
Foreign exchange (gain) loss		(12	)		—			39			—			2			4,472			4,501
Interest and financing		—			—			430			—			76			6			512
Provision for impairment		—			—			—			—			948			—			948

		1,055			1,630			25,830			—			8,141			14,895			51,551


Loss from continuing operations before income taxes		(1,055	)		(1,630	)		(7,187	)		—			(8,141	)		(14,879	)		(32,892	)

(Provision for) recovery of income taxes
Current		—			—			(1,266	)		—			—			(358	)		(1,624	)
Future		—			—			—			—			8,700			—			8,700

		—			—			(1,266	)		—			8,700			(358	)		7,076


Net income (loss) from continuing operations		(1,055	)		(1,630	)		(8,453	)		—			559			(15,237	)		(25,816	)
Net loss from discontinued operations (net of tax of $29.6 million)		—			—			—			(23,921	)		—			—			(23,921	)

Net income (loss) and comprehensive loss	$	(1,055	)	$	(1,630	)	$	(8,453	)	$	(23,921	)	$	559		$	(15,237	)	$	(49,737	)


Capital Investments	$	9,263		$	2,883		$	3,702		$	—		$	1,818		$	57		$	17,723

9. FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

Financial instruments are comprised of cash and cash equivalents, accounts receivable, note receivable, restricted cash, debt, accounts payable and accrued liabilities and a long-term obligation. Due to their short-term nature, the fair value of the Company’s financial instruments approximates their carrying values, with the exception of the debt. Based on management’s assessment of the Company’s credit risk, the fair value of the debt at September 30, 2010, is $36.8 million.

Financial Risk Factors

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

10. SUPPLEMENTAL CASH FLOW INFORMATION


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009

Cash paid during the period for
Income taxes	$	8		$	—		$	646		$	1,655
Interest	$	819		$	864		$	1,634		$	2,059

Shares issued for services and capitalized	$	—		$	—		$	799		$	—

Changes in non-cash working capital items
Operating activities
Accounts receivable	$	1,338		$	(1,308	)	$	1,029		$	(2,669	)
Note receivable		(4	)		—			(35	)		—
Prepaid and other current assets		1,092			294			414			287
Accounts payable and accrued liabilities		(1,774	)		480			(1,029	)		(764	)
Income tax payable		(8	)		619			(530	)		(31	)

		644			85			(151	)		(3,177	)


Investing activities
Accounts receivable		(298	)		3			(327	)		49
Note receivable		—			(248	)		—			(248	)
Prepaid and other current assets		(1,055	)		(11	)		(972	)		—
Accounts payable and accrued liabilities		1,878			(243	)		4,657			(987	)

		525			(499	)		3,358			(1,186	)


Financing activities
Accounts payable and accrued liabilities		(41	)		—			(2	)		(26	)


	$	1,128		$	(414	)	$	3,205		$	(4,389	)


	September 30,		December 31,
	2010		2009

Cash and cash equivalents
Bank accounts	$	9,164	$	21,512
Term deposit		81,084		—

	$	90,248	$	21,512

Cash and cash equivalents at September 30, 2010, and December 31, 2009, are composed of bank balances in checking accounts with excess cash in money market accounts which invest primarily in government securities with less than 90 day original maturities.

11. INCOME TAXES

Prior to the Company selling its US operating segment in July 2009, as further described in Note 12, the Company had future tax assets arising from net operating loss carry-forwards generated by this business segment. These future income tax assets were partially offset by certain future income tax liabilities in the US and by a valuation allowance. As at June 30, 2009, as a result of the sale of the business segment, the Company was no longer able to offset these tax assets and liabilities but was required to reclassify these future income tax assets as “assets from discontinued operations” and a future income tax liability both in the amount of $29.6 million. The future income tax assets classified as “assets from discontinued operations” were ultimately included in the $23.4 million loss on disposition. Revisions have been made to the future income tax liability based on the Company’s ongoing projections for taxable income and its ability to utilize net operating loss carry-forwards to reduce associated future income tax liabilities.

12. DISCONTINUED OPERATIONS

In June of 2009, management commenced a process to sell all of the Company’s US oil and gas exploration and production operations. On July 17, 2009, the Company completed the sale of its wholly owned subsidiary Ivanhoe Energy (USA) Inc. for a purchase price of $39.2 million. The purchaser acquired the Company’s oil and gas exploration and production operations in California and Texas and additional exploration acreage in California.

The Company used approximately $5.2 million of the sales proceeds to repay an outstanding loan to a third party financial institution holding a security interest in the subsidiary company’s assets. The Company applied the balance of the sales proceeds in the ongoing development of its heavy oil projects in Canada and Ecuador and for general corporate purposes.

An escrow deposit of $2.0 million was set aside from the sale proceeds and made available to the purchaser for a period of one year to satisfy any indemnification obligations of the Company. In July 2010, the purchaser notified the Company that it intended to make a claim against the escrow deposit for alleged breaches of certain covenants in the purchase and sale agreement in respect of tax matters. At September 30, 2010, the Company and the purchaser are currently negotiating an agreement whereby the purchaser would receive $250,000 of the escrow deposit. This amount has been included in the Company’s accrued liabilities at September 30, 2010.

In conjunction with the disposition of the US assets and the Company’s focus on heavy oil opportunities, the Company closed its support office in Bakersfield, California and transferred its accounting operations to Calgary, Alberta. This transition was completed by the end of the second quarter of 2010. Total costs associated with this closure, including severance and retention payments, were approximately $0.6 million.

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


	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2010		2009			2010		2009
Revenue
Oil and gas	$	—	$	556		$	—	$	5,455
Gain on derivative instruments		—		—			—		189
Interest		—		—			—		8

		—		556			—		5,652


Expenses
Operating		—		164			—		2,132
General and administrative		—		9			—		139
Depletion and depreciation		—		303			—		3,772
Interest and financing		—		13			—		173

		—		489			—		6,216
Net income (loss) before disposition		—		67			—		(564	)
Loss on disposition (net of tax of $29.6 million for 2009)		—		(23,357	)		—		(23,357	)

Net loss from discontinued operations	$	—	$	(23,290	)	$	—	$	(23,921	)

13. ADDITIONAL DISCLOSURE REQUIRED UNDER US GAAP

The Company’s unaudited 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 US GAAP except for certain matters, the details of which are outlined on the following pages.

Consolidated Balance Sheets

The application of US GAAP has the following effects on unaudited consolidated balance sheet items as reported under Canadian GAAP:


	As at September 30, 2010										As at December 31, 2009
	Canadian			Increase				US			Canadian			Increase				US
	GAAP			(Decrease)			Notes	GAAP			GAAP			(Decrease)			Notes	GAAP

Assets
Current Assets
Cash and cash equivalents	$	90,248			—			$	90,248		$	21,512			—			$	21,512
Accounts receivable		4,332			—				4,332			5,021			—				5,021
Note receivable		260			—				260			225			—				225
Prepaid and other current assets		1,329			—				1,329			771			—				771
Restricted cash		2,850			—				2,850			2,850			—				2,850

		99,019			—				99,019			30,379			—				30,379

Oil and gas properties and development costs, net		213,685			(38,500	)	(i)		197,301			158,392			(38,500	)	(i)		139,346
					23,504		(ii)								20,315		(ii)
					(1,388	)	(iii)								(861	)	(iii)
Intangible assets — technology		92,153			—				92,153			92,153			—				92,153
Long term assets		2,126			—				2,126			839			—				839

Total Assets	$	406,983			(16,384	)		$	390,599		$	281,763			(19,046	)		$	262,717


Liabilities and Shareholders’ Equity
Current Liabilities
Debt	$	38,279			698		(iii)	$	38,845		$	—			—			$	—
					(132	)	(iii)
Accounts payable and accrued liabilities		14,394			—				14,394			10,779			—				10,779
Income tax payable		—			—				—			530			—				530
Derivative instruments		—			6,273		(vi)		6,273			—			8,249		(vi)		8,249
Asset retirement obligations		—			—				—			753			—				753

		52,673			6,839				59,512			12,062			8,249				20,311

Long term debt		—			—				—			36,934			1,225		(iii)		38,005
															(154	)	(iii)
Asset retirement obligations		496			—				496			195			—				195
Long term obligation		1,900			—				1,900			1,900			—				1,900
Future income tax liability		22,624			—				22,624			22,643			—				22,643

		77,693			6,839				84,532			73,734			9,320				83,054


Shareholders’ Equity
Share capital		549,220			74,455		(iv)		637,205			422,322			74,455		(iv)		510,784
					(1,028	)	(v)								(551	)	(v)
					1,358		(vii)								1,358		(vii)
					13,200		(vi)								13,200		(vi)
Purchase warrants		33,423			(33,423	)	(vi)		—			19,427			(19,427	)	(vi)		—
Contributed surplus		20,343			(2,720	)	(v)		14,676			20,029			(3,197	)	(v)		13,885
					(2,947	)	(vi)								(2,947	)	(vi)
Convertible note		2,086			(2,086	)	(iii)		—			2,086			(2,086	)	(iii)		—
Accumulated deficit		(275,782	)		(70,032	)			(345,814	)		(255,835	)		(89,171	)			(345,006	)

		329,290			(23,223	)			306,067			208,029			(28,366	)			179,663

	$	406,983			(16,384	)		$	390,599		$	281,763			(19,046	)		$	262,717

Oil and Gas Properties and Development Costs

(i)

There are certain differences between the full cost method of accounting for oil and gas properties as applied in Canada and as applied in the US. 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 US GAAP purposes, the Company limits, on a country-by-country basis, the capitalized costs of oil and gas properties, net of accumulated depletion, depreciation and amortization and deferred income taxes, to (a) the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10% and assuming continuation of existing economic conditions; plus (b) the cost of properties not being amortized (e.g. major development projects) and (c) the lower of cost or fair value of unproved properties included in the costs being amortized less (d) income tax effects related to the difference between the book and tax basis of the properties referred to in (b) and (c) above. If capitalized costs exceed this limit, the excess is charged as a provision for impairment. Unproved properties and major development projects are assessed on a quarterly basis for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to the carrying value of proved oil and gas properties. The Company performed the ceiling test in accordance with US GAAP and determined that for the three months ended September 30, 2010, no impairment provision was required, nor was an impairment provision required under Canadian GAAP. The cumulative differences in the amount of impairment provisions between US and Canadian GAAP were $38.5 million at September 30, 2010, and December 31, 2009.

(ii)

The cumulative differences in the amount of impairment provisions between US and Canadian GAAP resulted in a reduction in accumulated depletion.

(iii)

The Company was required, under Canadian GAAP, to bifurcate the value of a convertible note, allocating a portion to long-term debt and a portion to equity. Under US GAAP, the convertible debt security is classified in its entirety as debt. Under Canadian GAAP, this discount accretion was capitalized. To reconcile to US GAAP, the entire $2.1 million recorded in equity as well as the unamortized discount of $0.7 million and the accreted discount that was capitalized in the amount of $1.4 million are reversed. In addition, because the convertible note is not denominated in US currency the re-measurement of the different carrying value for US GAAP results in an adjustment to net income. The foreign exchange gain of $0.1 million is shown as a separate amount in the US GAAP reconciliation of the Company’s consolidated balance sheet shown above and is adjusted to the Foreign Exchange Loss line item in the US GAAP reconciliation of the consolidated statement of operations below.

Shareholders’ Equity

(iv)

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

(v)

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

(vi)

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

(vii)

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

Consolidated Statements of Operations

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


	Three Months Ended September 30, 2010										Three Months Ended September 30, 2009
	Canadian			Increase				US			Canadian			Increase				US
	GAAP			(Decrease)			Notes	GAAP			GAAP			(Decrease)			Notes	GAAP
Revenue
Oil	$	4,177			—			$	4,177		$	7,917			—			$	7,917
Gain (loss) on derivative instruments		—			634		(vi)		634			72			(1,165	)	(vi)		(1,093	)
Interest		88			—				88			2			—				2

		4,265			634				4,899			7,991			(1,165	)			6,826


Expenses
Operating		1,975			—				1,975			2,907			—				2,907
General and administrative		6,055			—				6,055			4,412			—				4,412
Business and technology development		3,045			—				3,045			2,301			—				2,301
Depletion and depreciation		2,079			(877	)	(ix)		1,202			5,308			(2,887	)	(ix)		2,421
Foreign exchange (gain) loss		(1,188	)		18		(iii)		(1,170	)		2,815			104		(iii)		2,919
Interest and financing		6			—				6			177			—				177
Provision for impairment		—			—				—			948			(26	)			922

Total expenses		11,972			(859	)			11,113			18,868			(2,809	)			16,059


Loss from continuing operations before income tax		(7,707	)		1,493				(6,214	)		(10,877	)		1,644				(9,233	)

Recovery of (provision for) income tax
Current		—			—				—			(618	)		—				(618	)
Future		479			—				479			8,700			—				8,700

		479			—				479			8,082			—				8,082

Net loss from continuing operations		(7,228	)		1,493				(5,735	)		(2,795	)		1,644				(1,151	)
Net loss from discontinued operations		—			—				—			(23,290	)		22,601		(x)		(689	)

Net loss and comprehensive loss	$	(7,228	)		1,493			$	(5,735	)	$	(26,085	)		24,245			$	(1,840	)


Net loss per share
Net loss from continuing operations, basic and diluted	$	(0.02	)		—			$	(0.02	)	$	(0.01	)		0.01			$	—
Net loss from discontinued operations, basic and diluted		—			—				—			(0.08	)		0.08				—


Net loss per share, basic and diluted	$	(0.02	)		—			$	(0.02	)	$	(0.09	)		0.09			$	—

Weighted average number of shares Basic and diluted (in thousands)		334,012			—				334,012			279,427			—				279,427


	Nine Months Ended September 30, 2010										Nine Months Ended September 30, 2009
	Canadian			Increase				US			Canadian			Increase				US
	GAAP			(Decrease)			Notes	GAAP			GAAP			(Decrease)			Notes	GAAP
Revenue
Oil	$	15,554			—			$	15,554		$	19,659			—			$	19,659
Gain (loss) on derivative instruments		—			15,972		(vi)		15,972			(1,020	)		(3,770	)	(vi)		(4,790	)
Interest		130			—				130			20			—				20

		15,684			15,972				31,656			18,659			(3,770	)			14,889


Expenses
Operating		6,577			—				6,577			8,052			—				8,052
General and administrative		16,510			—				16,510			14,126			—				14,126
Business and technology development		7,979			—				7,979			6,104			151		(ix)		6,255
Depletion and depreciation		6,744			(3,189	)	(ix)		3,555			17,308			(9,241	)	(ix)		8,067
Foreign exchange (gain) loss		(2,289	)		22		(iii)		(2,267	)		4,501			(176	)	(iii)		4,325
Interest and financing		14			—				14			512			—				512
Provision for impairment		—			—				—			948			(26	)			922

		35,535			(3,167	)			32,368			51,551			(9,292	)			42,259


Loss from continuing operations before income tax		(19,851	)		19,139				(712	)		(32,892	)		5,522				(27,370	)

Provision for (recovery of) income tax
Current		(115	)		—				(115	)		(1,624	)		—				(1,624	)
Future		19			—				19			8,700			—				8,700

		(96	)		—				(96	)		7,076			—				7,076


Net loss from continuing operations		(19,947	)		19,139				(808	)		(25,816	)		5,522				(20,294	)
Net income (loss) from discontinued operations		—			—				—			(23,921	)		24,849		(x)		928

Net loss and comprehensive loss	$	(19,947	)		19,139			$	(808	)	$	(49,737	)		30,371			$	(19,366	)


Net income (loss) per share
Net income (loss) from continuing operations, basic and diluted	$	(0.06	)		0.06			$	—		$	(0.09	)		0.02			$	(0.07	)
Net income from discontinued operations, basic and diluted		—			—							(0.09	)		0.09				—

Net income (loss) per share, basic and diluted	$	(0.06	)		0.06			$	—		$	(0.18	)		0.11			$	(0.07	)


Weighted average number of shares Basic and diluted (in thousands)		325,153			—				325,153			279,381			—				279,381

Development Costs

(viii)

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

Depletion and Depreciation

(ix)

As discussed under “Oil and Gas Properties and Development Costs” in this note, there is a difference between US 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 US GAAP has resulted in an accumulated net increase in impairment provisions on the Company’s US and China oil and gas properties. This net increase in US GAAP impairment provisions has resulted in lower depletion rates for US GAAP purposes and a reduction in the net loss for the three and nine months ended September 30, 2010 and 2009.

Discontinued Operations

(x)

For the three and nine months ended September 30, 2009, a $22.6 million and $24.8 million adjustment related to discontinued operations mainly resulting from depletion and impairment differences as more fully described in note (ii).

Consolidated Statements of Cash Flow

There would be no material difference in cash flow presentation between Canadian and US GAAP for the three and nine months ended September 30, 2010 and 2009.

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

Forward-Looking Statements

With the exception of historical information, certain matters discussed in this Quarterly Report on Form 10-Q (“Form 10-Q”), including those within this Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”), are forward-looking statements that involve risks and uncertainties. Certain statements contained in this Form 10-Q, including statements which may contain words such as “anticipate,” “could,” “propose,” “should,” “intend,” “seeks to,” “is pursuing,” “expect,” “believe,” “will” and similar expressions may be indicative of forward-looking statements. Although the Company believes that its expectations are based on reasonable assumptions, forward-looking statements involve known and unknown risks and uncertainties that may cause the actual future results, performances or achievements to be materially different from management’s current expectations. These known and unknown risks and uncertainties may include, but are not limited to, the ability to raise capital as and when required, the timing and extent of changes in prices for oil and gas, competition, environmental risks, drilling and operating risks, uncertainties about the estimates of reserves and the potential success of the Company’s heavy-to-light technology, the prices of goods and services, the availability of drilling rigs and other support services, legislative and government regulations, political and economic factors in countries in which the Company operates and implementation of its capital investment program. Except as required by law, the Company undertakes no obligation to update publicly or revise any forward-looking statements contained in this report. All subsequent forward-looking statements, whether written or oral, attributable to the Company, or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

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

Special Note to Canadian Investors

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

Advisories

The Form 10-Q report should be read in conjunction with the Company’s unaudited consolidated financial statements contained herein, and the audited consolidated financial statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations, contained in the 2009 Form 10-K. Any terms used but not defined in the following discussion have the same meaning given to them in the 2009 Form 10-K. The unaudited 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 US GAAP on the unaudited consolidated financial statements is disclosed in Note 13 of the unaudited interim consolidated financial statements contained herein.

Non-GAAP Financial Measures

Oil revenue per barrel is calculated by dividing oil revenue by the Company’s total production for the respective periods presented. Net operating revenue per barrel is calculated by dividing oil revenue less operating costs by total production for the respective periods presented. Net revenue (loss) from operations per barrel is calculated by subtracting depletion from net operating revenue and dividing by total production for the respective periods presented. The Company believes oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel are important to investors to evaluate operating results and the Company’s ability to generate cash. Each of the components used in these calculations can be reconciled directly to the unaudited interim consolidated statement of operations. The calculations of oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel may differ from similar calculations of other companies in the oil and gas industry, thereby limiting its usefulness as a comparative measure.

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

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


bbl		= barrel
bbls/d		= barrels per day
bopd		= barrels of oil per day
boe		= barrel of oil equivalent
boe/d		= barrels of oil equivalent per day
mbbl		= thousand barrels
mbbls/d		= thousand barrels per day
mboe		= thousands of barrels of oil equivalent
mboe/d		= thousands of barrels of oil equivalent per day
mmbbl		= million barrels
mmbls/d		= million barrels per day
mcf		= thousand cubic feet
mcf/d		= thousand cubic feet per day
mmbtu		= million British thermal units
mmcf		= million cubic feet
mmcf/d		= million cubic feet per day

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

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

HIGHLIGHTS


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009

Average daily production (bbls/d)		610			1,413			760			1,421
Realized oil prices ($/bbl)	$	74.41		$	61.34		$	74.92		$	50.66
Oil revenue	$	4,177		$	7,917		$	15,554		$	19,659

Working capital (continuing operations⁽¹⁾)	$	46,346		$	33,439		$	46,346		$	33,439
Capital expenditures (continuing operations)	$	20,428		$	5,823		$	60,991		$	17,723

Cash flow used in operating activities (continuing operations)	$	(5,421	)	$	(1,066	)	$	(13,762	)	$	(10,863	)

Net loss (continuing operations)	$	(7,228	)	$	(2,795	)	$	(19,947	)	$	(25,816	)
Net loss per share, basic and diluted (continuing operations)	$	(0.02	)	$	(0.01	)	$	(0.06	)	$	(0.09	)


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

Production declined in 2010 as Ivanhoe’s working interest at Dagang, China decreased to 49% upon the Company recovering its development costs. Revenue decreased in comparison to prior periods as a result of the lower production volumes despite higher realized oil prices in 2010.

The net loss from continuing operations in the nine months ended September 30, 2010 was $19.9 million, an improvement over the comparable period. Lower depletion expense and an unrealized foreign exchange gain compensated for the decrease in revenue and the elimination of a future income tax recovery. In the third quarter of 2010, the Company’s net loss was $7.2 million, higher than in the third quarter of 2009. Decreased revenue and the elimination of a future tax recovery were partially offset by lower depletion costs and an unrealized foreign exchange gain.

Capital expenditures totaled $61.0 million through the nine months ended September 30, 2010. Drilling at Zitong-1 continued in China’s Sichuan Province and drilling commenced on a second well, Yixin-2. Ivanhoe’s second well in Ecuador, IP-5b, was drilled to total depth and steam injection operations were performed. Progress was also made on the Company’s Environmental Impact Assessment for the Tamarack project.

Changes in Net Loss

The following provides an analysis of the changes in net losses for the three and nine months ended September 30, 2010, as compared to 2009:


	Three Months Ended September 30,									Nine Months Ended September 30,
	2010			Change			2009			2010			Change			2009

Cash items
Oil revenues	$	4,177					$	7,917		$	15,554					$	19,659
Production volumes					(4,474	)								(9,141	)
Oil prices					734									5,036
Operating costs		(1,975	)		932			(2,907	)		(6,577	)		1,475			(8,052	)
G&A less stock based compensation		(5,171	)		(1,926	)		(3,245	)		(14,092	)		(2,017	)		(12,075	)
Business and technology development less stock based compensation		(2,877	)		(679	)		(2,198	)		(7,787	)		(1,874	)		(5,913	)
Realized foreign exchange loss		(308	)		(279	)		(29	)		(545	)		(476	)		(69	)
Realized derivative instruments gain		—			—			—			—			(612	)		612
Net interest		88			164			(76	)		130			370			(240	)
Current income tax provision		—			618			(618	)		(115	)		1,509			(1,624	)

Total cash changes		(6,066	)		(4,910	)		(1,156	)		(13,432	)		(5,730	)		(7,702	)


Non-cash items
Unrealized (loss) gain on derivatives		—			(72	)		72			—			1,632			(1,632	)
Unrealized foreign exchange gain (loss)		1,496			4,282			(2,786	)		2,834			7,266			(4,432	)
Depletion and depreciation		(2,079	)		3,229			(5,308	)		(6,744	)		10,564			(17,308	)
Stock based compensation		(1,052	)		218			(1,270	)		(2,610	)		(368	)		(2,242	)
Future income tax recovery		479			(8,221	)		8,700			19			(8,681	)		8,700
Provision for impairment		—			948			(948	)		—			948			(948	)
Discontinued operations (net of tax)		—			23,290			(23,290	)		—			23,921			(23,921	)
Other		(6	)		93			(99	)		(14	)		238			(252	)

Total non-cash changes		(1,162	)		23,767			(24,929	)		(6,515	)		35,520			(42,035	)


Net loss	$	(7,228	)		18,857		$	(26,085	)	$	(19,947	)		29,790		$	(49,737	)

Oil Production

Three Months

Nine Months

Ended September 30,

2010

2009

2010

2009

Asia (net bbls)

Dagang

52,420

125,079

195,424

377,451

Daqing

3,711

3,995

12,172

10,582

56,131

129,074

207,596

388,033

Average daily production (bbls/d)

610

1,403

760

1,421

Ivanhoe’s oil production originates in Asia, specifically the Dagang and Daqing fields in China. Production in 2010 was lower than in the prior year due to Ivanhoe’s working interest in the Dagang field decreasing from 82% to 49% as stipulated by the governing production sharing contracts upon the Company having completed the recovery of its development investments in September 2009. The Company received a 2010 net production quota of approximately 247,950 bbl or 680 bbls/d. The Company is taking advantage of this quota situation and is performing certain maintenance workovers that normally would have been delayed.

Net Revenue From Operations


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
($/bbl)	2010			2009			2010			2009

Oil revenue⁽¹⁾	$	74.41		$	61.34		$	74.92		$	50.66
Less operating costs
Field operating		(22.15	)		(15.47	)		(19.01	)		(17.06	)
Windfall Levy		(11.34	)		(6.32	)		(11.16	)		(2.99	)
Engineering and support costs		(1.69	)		(0.73	)		(1.50	)		(0.70	)

Net operating revenue⁽¹⁾		39.23			38.82			43.25			29.91
Depletion		(33.69	)		(39.74	)		(32.05	)		(40.32	)

Net revenue (loss) from operations⁽¹⁾	$	5.54		$	(0.92	)	$	11.20		$	(10.41	)


(1)		Oil revenue per barrel, net operating revenue per barrel and net revenue (loss) from operations per barrel do not have standardized meanings prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Financial Measures under the Advisories section in the MD&A for more details.

Oil Revenue

Ivanhoe’s oil revenue in the three and nine months ended September 30, 2010, declined from prior periods due to lower production volumes, despite realized prices increasing as the result of stronger benchmark commodity prices.

Operating Costs

On a per barrel basis, operating costs in China rose in the three and nine months ended September 30, 2010, primarily due to an increase in the Windfall Levy administered by the Peoples Republic of China (“PRC”). According to the Windfall Levy, enterprises exploiting and selling crude oil in the PRC are subject to a windfall gain levy if the monthly weighted average price of crude oil is above $40/bbl. The Windfall Levy is imposed at progressive rates from 20% to 40% on the portion of the weighted average sales price exceeding $40/bbl.

General and Administrative

General and administrative expenses (“G&A”) were higher in both the three and nine months ended September 30, 2010, in comparison to the prior year, primarily as a result of higher staff and office costs incurred with the Company’s growing commitments to its projects around the world.

In the nine months ended September 30, 2010, G&A was higher than in 2009 due to increased staff and office costs of $4.3 million incurred across all operating segments, a $0.8 million rise in corporate costs, such as stock exchange filing fees, director costs and non-cash stock based compensation, offset by a decrease of $2.8 million in corporate legal costs incurred in 2009 in respect of the Grynberg legal proceedings. In the third quarter of 2010, G&A rose in comparison to the prior year due primarily to an increase of $1.6 million in staff and office costs across all operating segments.

Business and Technology Development

Business and technology development expenses increased when compared to the same periods in 2009 as a result of Feedstock Test Facility evaluations of production samples. Costs were also incurred in 2010 in connection with pursuing HTL^TM heavy oil and selected conventional oil opportunities in North and South America, the Middle East and North Africa.

Depletion and Depreciation

Depletion and depreciation in the three and nine months ended September 30, 2010, decreased compared to 2009. The reduction is predominantly attributable to lower depletion in Asia. In the three and nine months ended September 30, 2010, depletion declined $3 million and $9 million respectively in comparison to 2009 due to lower net production volumes and higher Dagang proved reserves at January 1, 2010.

Foreign Exchange

The Company incurred a foreign exchange gain in the three and nine months ended September 30, 2010 on the translation of its Canadian dollar term deposit as a result of the Canadian dollar strengthening relative to the US dollar.

Interest and Financing Costs

Interest expense for both the three and nine months ended September 30, 2010, was lower than in 2009 due to the repayment of loan obligations associated with the Company’s China and US operations during the course of 2009.

Unrealized Gain (Loss) on Derivative Instruments

The Company was previously required to hedge a substantial portion of its Dagang production as a condition of its loan facility. Following the repayment of borrowings in 2009, the Company does not hold any derivative positions.

Discontinued Operations

In July 2009, management sold all of the Company’s US oil and gas exploration and production operations for total proceeds of $39.2 million. The net proceeds totaled approximately $33.1 million, after repayment of debt in the amount of $5.2 million and transaction expenses of $1.2 million.

Provision for/Recovery of Income Taxes

Asia

Provisions for current income taxes in the three and nine months ended September 30, 2010, decreased in comparison to 2009 driven by a one time retrospective change in the first quarter of 2009 to the minimum depreciation and amortization periods required by Chinese tax law.

Business and Technology Development

Prior to the Company selling its US operating segment in July 2009, as further described in Note 12 to the accompanying unaudited consolidated financial statements, the Company had future tax assets arising from net operating loss carry-forwards generated by the business segment. These future income tax assets were partially offset by certain future income tax liabilities in the US and by a valuation allowance. As at September 30, 2009, as a result of the pending sale of the business segment, the Company was no longer able to offset these tax assets and liabilities. The future income tax assets classified as “assets from discontinued operations” were ultimately included in the $23.4 million loss on disposition. Revisions have since been made to the future income tax liability due to revised projections of taxable income and the Company’s utilization of net operating loss carryforwards.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations


	Payments Due by Year
											After
	Total		2010		2011		2012		2013		2013

Included in balance sheet
Debt	$	38,279	$	—	$	38,279	$	—	$	—	$	—
Asset retirement obligation⁽¹⁾		1,337		—		—		166		—		1,171
Long term obligation		1,900		—		—		—		1,900		—

Other commitments
Interest payable		1,929		—		1,929		—		—		—
Lease commitments		3,055		313		1,601		828		313		—
Zitong exploration commitment⁽²⁾		11,777		11,777		—		—		—		—
Nyalga exploration commitment		294		—		—		—		294		—

	$	58,571	$	12,090	$	41,809	$	994	$	2,507	$	1,171


(1)		Represents undiscounted asset retirement obligations after inflation. The discounted value ($0.5 million) of these estimated obligations is provided for in the unaudited consolidated financial statements.

(2)		Estimated expenditures to complete Phase II of the Zitong block minimum work program.

Sources and Uses of Cash

The Company’s cash flows from operating, investing and financing activities, as reflected in the unaudited consolidated statements of cash flow, are summarized in the following table:


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009

Cash used in operating activities (continuing operations)	$	(5,421	)	$	(1,066	)	$	(13,762	)	$	(10,863	)
Cash used in investing activities (continuing operations)	$	(20,345	)	$	(8,524	)	$	(58,921	)	$	(21,264	)
Cash provided by (used in) financing activities (continuing operations)	$	(102	)	$	98		$	137,796		$	(444	)

Ivanhoe’s cash flow from operating activities from continuing operations is not sufficient to meet its operating and capital obligations over the next twelve months. The Company intends to use its working capital of $46.3 million at September 30, 2010, to meet its commitments. However, additional sources of funding will be required to grow the Company’s major projects and fully develop its oil and gas properties, either at a parent company level or at a project level. Historically, Ivanhoe has used external sources of funding such as public and private equity and debt markets. However, there is no assurance that these sources of funding will be available to the Company in the future on acceptable terms, or at all.

		Operating Activities

		In the three and nine months ended September 30, 2010, cash used in operating activities from continuing operations, excluding the impact of changes in non-cash working capital, was higher than in 2009. Reductions in operating costs and current taxes in 2010 were offset by lower oil revenue and higher G&A and business and technology development costs.

Investing Activities


	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2010			2009		2010		2009

Oil and gas activities
Canada	$	3,600		$	3,186	$	26,762	$	9,263
Ecuador		5,722			1,333		15,004		2,883
Asia		10,951			1,179		18,317		3,702
Business and technology development		172			125		537		1,818
Corporate		(17	)		—		371		57

Total capital expenditures	$	20,428		$	5,823	$	60,991	$	17,723

		*Canada*

		Activity during the third quarter of 2010 focused on completing the Company’s Environmental Impact Assessment for the Tamarack project. The Class III (+25/-20%) capital cost estimate based on engineering for the upstream production, surface facilities, the HTL upgrading unit and infrastructure (power and access) has been completed.

		*Ecuador*

		In the third quarter, the second appraisal well in Block 20, IP-5b, was drilled to total depth and cased. The Hollin formation was perforated and steam injection operations were performed on the well. Subsequent to quarter end, oil was successfully produced from the IP-5b appraisal well and will be sent to the Company’s Feedstock Test Facility.

		Preparations began for the seismic survey of Block 20. The seismic program is essential to defining the location and orientation of fault blocks that exist due to the close proximity of the Andes Mountains, directly west of Block 20.

		*Asia*

		Drilling at Zitong-1 in China’s Sichuan Province continued in the third quarter, reaching a depth of 4,000 meters. Plans to core and open hole test the Xu4 formation were modified due to the high formation pressures. The well casing and drilling program was amended to allow for casing to be set and cemented in the Xu3 formation before drilling continues. The Company started drilling Yixin-2 in August 2010, reaching a depth of 2,860 meters by the end of September. The fracture stimulation program continued at Dagang and preparatory activities commenced to drill two development wells.

		In the Nyalga basin of Mongolia, preparations for a five well drilling program commenced and preparations for a seismic acquisition program commenced.

		Financing Activities

		In February and March 2010, the Company raised $135.8 million, net of issuance costs, through a private placement of 50 million Special Warrants at price of Cdn $3.00 per Special Warrant. Each Special Warrant was converted during the first quarter of 2010, for no additional consideration, into one common share and one-quarter of a share purchase warrant of the Company.

Capital Structure


	September 30,		December 31,
	2010		2009

Short term debt	$	38,279	$	—
Long term debt	$	—	$	36,934

Shareholders’ equity	$	329,290	$	208,029

The recorded value of the Company’s Canadian dollar convertible promissory note increased from December 31, 2009, due to a combination of the Canadian dollar strengthening relative to the US dollar and the amortization of the interest discount.

Equity increased when the Company raised $135.8 million, net of issuance costs, through a private placement of 50 million special warrants in February and March 2010 at price of Cdn $3.00 per special warrant. Each special warrant was converted during the first quarter of 2010, for no additional consideration, into one common share and one quarter of a share purchase warrant of the Company.

Outlook for 2010

During the remainder of 2010, it is expected that Ivanhoe’s capital program will focus on concluding the current steaming operations and production testing in Ecuador. The Company expects to conclude drilling the wells currently underway in Zitong and Yixin and will initiate completion activities. Expenditures for drilling development wells in the Dagang oil field in China to enhance production will also be incurred. In Mongolia, activities will continue in preparation for a 2D seismic program and the drilling of an exploration well. Minor expenditures may be necessary for development costs relating to the enhancement of the Company’s HTL^TMupgrading process. The Company is continuing to pursue ongoing discussions related to other HTL^TM heavy oil and selected conventional oil opportunities in North and South America, the Middle East and North Africa.

Management’s plans for financing future expenditures include traditional project financing, debt and mezzanine financing or the sale of equity securities as well as the potential for alliances or other arrangements with strategic partners. Discussions with potential strategic partners are focused primarily on national oil companies and other sovereign or government entities from Asian and Middle Eastern countries that have approached Ivanhoe and expressed interest in participating in the Company’s heavy oil activities in Ecuador, Canada and around the world. However, no assurances can be given that Ivanhoe will be able to enter into one or more strategic business alliances with third parties or that the Company will be able to raise sufficient additional capital. If the Company is unable to enter into such business alliances or obtain adequate additional financing, the Company may be required to curtail its operations, which may include the sale of assets.

International Financial Reporting Standards (“IFRS”)

In 2009, the Canadian Accounting Standards Board confirmed that IFRS will be required for interim and annual reporting by publicly accountable enterprises effective for January 1, 2011, including 2010 comparative information. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policy, which must be addressed. The Company’s IFRS changeover plan is in place and a detailed discussion of the project can be found in the Company’s 2009 Form 10-K under “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

During the third quarter of 2010, the Company worked towards quantifying the IFRS opening balance sheet retrospective adjustments. The Company’s IFRS Steering Committee has recommended these adjustments for final approval by the Audit Committee at its next meeting. The process of drafting IFRS interim consolidated financial statements and note disclosures is ongoing. The Company is on schedule to implement IFRS on January 1, 2011.

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, 2010. Based upon this evaluation, management concluded that these controls and procedures were (1) designed to ensure that material information relating to the Company is made known to the Company’s Chief Executive Officer and Chief Financial Officer as appropriate to allow timely decisions regarding disclosure and (2) effective, in that they provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the 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.

There were no changes in the Company’s internal control over financial reporting in the quarter ended September 30, 2010, that have materially affected, or are reasonably likely to have a material effect on the Company’s internal control over financial reporting.

Part II OTHER INFORMATION

Item 1. Legal Proceedings

The Company is a defendant in a lawsuit filed November 20, 2008, in the US District Court for the District of Colorado by Jack J. Grynberg and three affiliated companies. The suit alleged bribery and other misconduct and challenged the propriety of a contract awarded to the Company’s wholly-owned subsidiary Ivanhoe Energy Ecuador Inc. to develop Ecuador’s Pungarayacu heavy oil field. The plaintiff’s claims were for unspecified damages or ownership of the Company’s interest in the Pungarayacu field. The Company and related defendants filed motions to dismiss the lawsuit for lack of jurisdiction. The Court granted the motion and dismissed the case without prejudice. The Court granted Mr. Robert Friedland’s request to sanction plaintiffs and plaintiffs’ counsel for their conduct related to bringing the suit by awarding Mr. Friedland fees and costs. The Ivanhoe corporate defendants, including the Company, have been awarded their costs in defending the suit and have requested an award of attorneys’ fees.

On October 16, 2009, the plaintiffs filed a motion requesting that the Court vacate its judgment and allow discovery on jurisdictional issues on the grounds that plaintiffs had discovered new evidence. On July 15, 2010, the Court denied the plaintiffs’ motion to vacate the judgment. The request for attorneys’ fees remains pending before the Court. On August 13, 2010, the plaintiffs filed a notice of appeal challenging the district court’s judgment and some of its orders. The appeal is currently pending in the US Court of Appeals for the Tenth Circuit, and briefing on the appeal is scheduled to begin with plaintiffs’ opening brief on November 1, 2010. The likelihood of loss or gain resulting from the lawsuit, and the estimated amount of ultimate loss or gain, are not determinable or reasonably estimable at this time.

Item 6. Exhibits


Exhibit
Number		Description

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

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

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

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

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.


IVANHOE ENERGY INC.

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

Dated: November 9, 2010

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