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

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

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

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

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

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


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

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

As at July 31, 2010, Ivanhoe Energy Inc. had 334,011,588 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 June 30, 2010 and December 31, 2009		3

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

Unaudited Consolidated Statements of Cash Flows for the Three and Six Months Ended June 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		23

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)


	June 30,			December 31,
	2010			2009

Assets
Current Assets
Cash and cash equivalents	$	113,817		$	21,512
Accounts receivable		5,355			5,021
Note receivable		256			225
Prepaid and other current assets		1,366			771
Restricted cash		2,850			2,850

		123,644			30,379

Oil and gas properties and development costs, net (Note 2)		195,060			158,392
Intangible assets — HTL^TM technology (Note 3)		92,153			92,153
Long term assets		1,682			839

	$	412,539		$	281,763


Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities	$	14,342		$	10,779
Income tax payable (Note 11)		8			530
Asset retirement obligations (Note 5)		50			753

		14,400			12,062

Long term debt (Note 4)		37,255			36,934
Asset retirement obligations (Note 5)		353			195
Long term obligation (Note 6)		1,900			1,900
Future income tax liability (Note 11)		23,104			22,643

		77,012			73,734

Commitments and contingencies (Note 6)

Going concern and basis of presentation (Note 1)

Shareholders’ Equity
Share capital, issued 334,011,588 common shares
December 31, 2009 282,558,593 common shares		549,281			422,322
Purchase warrants (Note 7)		33,423			19,427
Contributed surplus		19,291			20,029
Convertible note		2,086			2,086
Accumulated deficit		(268,554	)		(255,835	)

		335,527			208,029

	$	412,539		$	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						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009
				(Note 12)						(Note 12)

Revenue
Oil revenue	$	6,047		$	6,009		$	11,377		$	11,742
Loss on derivative instruments		—			(1,173	)		—			(1,092	)
Interest		23			8			42			18

		6,070			4,844			11,419			10,668

Expenses
Operating		2,327			2,444			4,602			5,145
General and administrative (Note 2)		5,478			3,834			10,455			9,714
Business and technology development		2,423			1,766			4,934			3,803
Depletion and depreciation		2,582			6,045			4,665			12,000
Foreign exchange loss (gain)		3,086			2,680			(1,101	)		1,686
Interest and financing		4			158			8			335

		15,900			16,927			23,563			32,683


Loss from continuing operations before income taxes		(9,830	)		(12,083	)		(12,144	)		(22,015	)


Provision for income taxes
Current		(36	)		639			(115	)		(1,006	)
Future		(286	)		—			(460	)		—

		(322	)		639			(575	)		(1,006	)


Net loss from continuing operations	$	(10,152	)	$	(11,444	)	$	(12,719	)	$	(23,021	)
Net income (loss) from discontinued operations (Note 12)		—			66			—			(631	)

Net loss and comprehensive loss		(10,152	)		(11,378	)		(12,719	)		(23,652	)

Accumulated deficit, beginning of period		(258,402	)		(206,457	)		(255,835	)		(194,183	)

Accumulated deficit, end of period	$	(268,554	)	$	(217,835	)	$	(268,554	)	$	(217,835	)


Net loss per share
Net loss from continuing operations, basic and diluted	$	(0.03	)	$	(0.04	)	$	(0.04	)	$	(0.08	)
Net loss from discontinued operations, basic and diluted		—			—			—			—

Net loss per share, basic and diluted	$	(0.03	)	$	(0.04	)	$	(0.04	)	$	(0.08	)


Weighted average number of shares
Basic and diluted (in thousands)		333,922			279,381			320,651			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						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009

Operating Activities
Net loss	$	(10,152	)	$	(11,378	)	$	(12,719	)	$	(23,652	)
Net (income) loss from discontinued operations		—			(66	)		—			631
Items not requiring use of cash
Depletion and depreciation		2,582			6,045			4,665			12,000
Stock based compensation		1,021			526			1,558			987
Unrealized loss on derivative instruments		—			1,249			—			1,704
Unrealized foreign exchange (gain) loss		3,035			2,620			(1,338	)		1,646
Future income tax expense		286			—			460			—
Other		(182	)		72			10			164
Abandonment costs settled (Note 5)		(124	)		—			(182	)		—
Changes in non-cash working capital items (Note 10)		(813	)		(3,985	)		(795	)		(3,277	)

Net cash used in operating activities from continuing operations		(4,347	)		(4,917	)		(8,341	)		(9,797	)
Net cash provided by operating activities from discontinued operations		—			2,031			—			2,823

Net cash used in operating activities		(4,347	)		(2,886	)		(8,341	)		(6,974	)


Investing Activities
Additions to oil and gas properties and development costs		(15,226	)		(6,692	)		(40,563	)		(11,900	)
Other		(498	)		(153	)		(846	)		(153	)
Changes in non-cash working capital items (Note 10)		1,953			35			2,833			(672	)

Net cash used in investing from continuing operations		(13,771	)		(6,810	)		(38,576	)		(12,725	)
Net cash used in investing activities from discontinued operations		—			(233	)		—			(586	)

Net cash provided by (used in) investing activities		(13,771	)		(7,043	)		(38,576	)		(13,311	)


Financing Activities
Shares issued on private placements, net of share issue costs		(556	)		—			135,765			—
Proceeds from exercise of options and warrants		458			—			2,094			—
Payments of debt obligations		—			—			—			(416	)
Other		—			(25	)		—			(100	)
Changes in non-cash working capital items (Note 10)		39			(3	)		39			(26	)

Net cash (used in) provided by financing activities from continuing operations		(59	)		(28	)		137,898			(542	)
Net cash provided by financing activities from discontinued operations		—			—			—			—

Net cash (used in) provided by financing activities		(59	)		(28	)		137,898			(542	)


Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency		(4,391	)		(4	)		1,324			(35	)


Increase (decrease) in cash and cash equivalents, for the period		(22,568	)		(9,961	)		92,305			(20,862	)
Cash and cash equivalents, beginning of period		136,385			28,364			21,512			39,265

Cash and cash equivalents, end of period	$	113,817		$	18,403		$	113,817		$	18,403


Cash and cash equivalents, end of period — continuing operations	$	113,817		$	16,135		$	113,817		$	16,135

Cash and cash equivalents, end of period — discontinued operations	$	—		$	2,268		$	—		$	2,268

(See Notes to the Unaudited Consolidated Financial Statements)

Notes to the Unaudited Consolidated Financial Statements

June 30, 2010

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

1. GOING CONCERN AND BASIS OF PRESENTATION

Ivanhoe Energy Inc.’s (the “Company” or “Ivanhoe”) accounting policies are in accordance with accounting principles generally accepted in Canada. These policies are consistent with accounting principles generally accepted in the United States (“US”), except as outlined in Note 13. These interim unaudited 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 interim unaudited 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 consolidated financial statements showing the financial position as at June 30, 2010, and the results of operations and cash flows for the three and six months ended June 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 $10.2 million for the three months ended June 30, 2010, and as of June 30, 2010, had an accumulated deficit of $268.6 million. Cash flow consumed in operating activities for the second quarter of 2010 was $4.3 million. The Company currently anticipates incurring substantial expenditures to further its capital development programs, particularly those related to the development of exploration opportunities in China and Mongolia, the development of an oil sands project in Alberta and the development of a heavy oil field in Ecuador. The Company’s cash flow from operating activities will not be sufficient to both satisfy its current obligations and meet the requirements of these capital investment programs. Completion of these projects by the Company is dependent upon its ability to obtain capital to fund further development of these projects and others in the portfolio and also to meet ongoing obligations. Ivanhoe intends to finance its future funding requirements primarily through a combination of strategic private investors and/or public equity markets. Given the expectation of rising interest rates and tighter credit markets, public and/or private debt issuance will be a secondary source of funds. Without access to financing, there is a chance that the Company may not be able to continue as a going concern. These 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

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. Capital assets categorized by segment are as follows:


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

Oil and Gas Properties
Proved	$	—		$	—		$	151,851		$	—		$	—		$	151,851
Unproved		118,086			16,755			17,871			—			—			152,712

		118,086			16,755			169,722			—			—			304,563
Accumulated depletion		—			—			(104,507	)		—			—			(104,507	)
Accumulated provision for impairment		—			—			(16,550	)		—			—			(16,550	)

		118,086			16,755			48,665			—			—			183,506


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		—			—			—			—			11,255			11,255
Accumulated depreciation and impairment		—			—			—			—			(657	)		(657	)

		—			—			—			—			10,598			10,598


Furniture and equipment		27			256			300			1,308			16			1,907
Accumulated depreciation		(12	)		(69	)		(129	)		(733	)		(8	)		(951	)

		15			187			171			575			8			956

	$	118,101		$	16,942		$	48,836		$	575		$	10,606		$	195,060


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

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

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

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


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

		—			—			—			—			10,475			10,475


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

		16			116			43			318			11			504

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

As at June 30, 2010, $152.7 million ($115.6 million at December 31, 2009) of costs related to unproved oil and gas properties are excluded from costs subject to depletion and depreciation. For the three and six months ended June 30, 2010, the Company capitalized $1.2 million and $2.3 million ($1.1 million and $2.0 million for 2009) of general and administrative expenses related directly to oil and gas acquisition, exploration and development activities. During the three and six months ended June 30, 2010, interest of $0.6 million and $1.2 million ($0.5 million and $1.1 million for 2009) was capitalized on debt related to oil and gas acquisition activities.

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 June 30, 2010, is $92.2 million (December 31, 2009 — $92.2 million). Since Ivanhoe acquired the technology, it has continued to expand its patent coverage to protect innovations to the HTL^TM Technology as they are developed and to significantly extend the Company’s portfolio of HTL^TM intellectual property. The Company is the assignee of three granted patents and currently has five patent applications pending in the US. The Company also has multiple patents in other countries. This intangible asset was not amortized and its carrying value was not impaired for the three month and six months ended June 20, 2010 and 2009.

4. LONG TERM DEBT

Long term debt consisted of the following as at:


	June 30,			December 31,
	2010			2009

Convertible note (4.5% at June 30, 2010) due July 2011	$	37,990		$	38,005
Less: Unamortized discount		(735	)		(1,071	)

	$	37,255		$	36,934

5. ASSET RETIREMENT OBLIGATIONS

The Company provides for the expected costs required to abandon its oil and gas assets. Historically, this provision has encompassed only the Commercial Demonstration Facility (“CDF”) and the Feedstock Test Facility (“FTF”). However, during the first quarter of 2010, these estimates were expanded to include costs attributed to the abandonment of eight delineation wells associated with the Tamarack project that were completed but not abandoned during the first quarter of 2010. The undiscounted value of expected future costs required to settle the Company’s asset retirement obligations are $0.7 million at June 30, 2010. To calculate the present value of these obligations, the expected future costs were derived by estimating current costs and escalating based on inflation rates of 1% to 2% and discounted at credit-adjusted rates of 3.5% and 5.3%, respectively, for Tamarack and the FTF. Changes in the carrying amount of the asset retirement obligations associated with oil and gas properties are as follows:


	June 30,			December 31,
	2010			2009

Carrying balance, beginning of period	$	948		$	1,928
Liabilities incurred		150			185
Liabilities settled		(182	)		(118	)
Accretion expense		8			79
Revisions in estimated cash flows		(521	)		(1,126	)

Carrying balance, end of period		403			948
Less: current portion		(50	)		(753	)

Carrying balance, end of period	$	353		$	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 $21.1 million at June 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 at the first of two locations commenced in the second quarter 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 $10.4 million at June 30, 2010. Following the completion of Phase II, the Zitong Partners must relinquish all of the remaining property except any areas identified for development and future production.

Nyalga Block Exploration Commitment

The exploration period for the Nyalga Block XVI in Mongolia is 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. Currently, year three of the exploration period, being year one of phase two, has been adjusted to begin July 20, 2010. Under the PSC obligations the Company must relinquish 25% of the block’s acreage by August 20, 2010. As at June 30, 2010, the Company has spent in excess of the commitments for the first phase. The minimum work obligation as at June 30, 2010, is $1.5 million.

Long Term Obligation

As part of its acquisition of the HTL^TM Technology license, the Company assumed an obligation to pay $1.9 million in the event, and at such time that, the sale of units incorporating the HTL^TM Technology for petroleum applications reach a total of $100 million. This obligation is recorded in the Company’s unaudited consolidated balance sheet.

Income Taxes

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

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

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

No amounts have been recorded in the unaudited consolidated 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.

Lease Commitments

For the three and six months ended June 30, 2010, the Company expended $0.7 million and $1.2 million ($0.4 million and $0.8 million for 2009) on operating leases relating to the rental of office space, which expire between July 2010 and September 2013. Such leases frequently provide for renewal options and require the Company to pay for utilities, taxes, insurance and maintenance expenses.

As at June 30, 2010, future net minimum payments for operating leases (excluding oil and gas and other mineral leases) due by year were the following:


											After
	Total		2010		2011		2012		2013		2013
Lease commitments	$	2,323	$	582	$	1,153	$	462	$	126		—

7. SHARE CAPITAL AND WARRANTS

Following is a summary of the changes in shareholder’s equity (excluding accumulated deficit) and stock options outstanding for the six months ended June 30, 2010:


													Stock Options
	Common Shares															Wtd. Avg
	Number				Purchase			Contributed			Convertible		Number			Exercise Price
	(000s)		Amount		Warrants			Surplus			Note		(000s)			(Cdn $)
Balance Dec. 31, 2009		282,559	$	422,322	$	19,427		$	20,029		$	2,086		15,013		$	2.27
Shares issued for
Private placement, net of share issue costs		50,000		121,766		13,999			—			—		—			—
Services		280		799		—			—			—		(280	)	$	2.44
Exercise of options		1,171		4,385		—			(2,296	)		—		(1,727	)	$	2.86
Exercise of purchase warrants		2		9		(3	)		—			—		—			—
Options
Granted		—		—		—			—			—		2,306		$	2.75
Forfeited		—		—		—			—			—		(108	)	$	2.20
Cancelled		—		—		—			—			—		(428	)	$	2.90
Compensation for stock option grants		—		—		—			1,558			—		—		$	—

Balance June 30, 2010		334,012	$	549,281	$	33,423		$	19,291		$	2,086		14,776		$	2.28

As at June 30, 2010, the following purchase warrants were exercisable to purchase common shares of the Company until the expiry date at the price per share as indicated below:


							Common							Cash
	Price per						Shares					Exercise		Value on
Year of	Special		Issued		Exercisable		Issuable		Value		Expiry	Price per		Exercise
Issue	Warrant		(000s)		(000s)		(000s)		($US 000s)		Date	Share		($US 000s)

2006		U.S.$2.23		11,400		11,398		11,398	$	18,802	May 2011	Cdn.$2.93	⁽¹⁾	$	31,488
2009		N/A		735		735		735		622	Feb 2011	Cdn.$4.05			2,807
2010	Cdn.$3.00			10,417		10,417		10,417		11,419	Feb 2011	Cdn.$3.16			31,036
2010	Cdn.$3.00			2,083		2,083		2,083		2,580	Mar 2011	Cdn.$3.16			6,207

				24,635		24,633		24,633	$	33,423				$	71,538


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

In January 2010, 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 investors right to exercise the option is contingent upon the occurrence of specific trigger events that are specified in the contract, and the share purchase option does not become exercisable, if at all, until the first quarter of 2011. The 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 June 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.

Oil and Gas

Integrated

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

Conventional

The Company explores for, develops and produces crude oil and natural gas in China, and recently acquired an exploration block in Mongolia. In China, the Company’s development and production activities are conducted at the Dagang oil field located in Hebei Province and its exploration activities are conducted on the Zitong block located in Sichuan Province. In Mongolia, the exploration activity is being conducted in Block XVI in the Nyalga Basin.

Business and Technology Development

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

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

Corporate

Ivanhoe’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 and six months ended June 30, 2010 and June 30, 2009, and identifiable assets as at June 30, 2010, and December 31, 2009:


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

Revenue
Oil	$	—		$	—		$	6,047		$	—	$	—		$	—		$	6,047
Interest		—			—			2			—		—			21			23

		—			—			6,049			—		—			21			6,070


Expenses
Operating		—			—			2,327			—		—			—			2,327
General and administrative		458			598			874			—		—			3,548			5,478
Business and technology development		—			24			—			—		2,399			—			2,423
Depletion and depreciation		2			9			2,532			—		(22	)		61			2,582
Foreign exchange (gain) loss		5			—			78			—		—			3,003			3,086
Interest and financing		2			—			—			—		2			—			4

		467			631			5,811			—		2,379			6,612			15,900


Loss from continuing operations before income taxes		(467	)		(631	)		238			—		(2,379	)		(6,591	)		(9,830	)


Provision for income taxes
Current		—			—			(33	)		—		—			(3	)		(36	)
Future		—			—			—			—		(286	)		—			(286	)

		—			—			(33	)		—		(286	)		(3	)		(322	)

Net income (loss) from continuing operations		(467	)		(631	)		205			—		(2,665	)		(6,594	)		(10,152	)
Net loss from discontinued operations		—			—			—			—		—			—			—

Net income (loss) and comprehensive loss	$	(467	)	$	(631	)	$	205		$	—	$	(2,665	)	$	(6,594	)	$	(10,152	)


Capital Investments	$	5,250		$	5,107		$	4,563		$	—	$	140		$	166		$	15,226


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

Revenue
Oil	$	—		$	—		$	11,377		$	—	$	—		$	—		$	11,377
Interest		—			—			4			—		—			38			42

		—			—			11,381			—		—			38			11,419


Expenses
Operating		—			—			4,602			—		—			—			4,602
General and administrative		872			1,098			1,561			—		—			6,924			10,455
Business and technology development		23			26			—			—		4,885			—			4,934
Depletion and depreciation		4			16			4,790			—		(254	)		109			4,665
Foreign exchange (gain) loss		(3	)		—			87			—		—			(1,185	)		(1,101	)
Interest and financing		3			—			—			—		5			—			8

		899			1,140			11,040			—		4,636			5,848			23,563


Loss from continuing operations before income taxes		(899	)		(1,140	)		341			—		(4,636	)		(5,810	)		(12,144	)


Provision for income taxes
Current		—			—			(111	)		—		—			(4	)		(115	)
Future		—			—			—			—		(460	)		—			(460	)

		—			—			(111	)		—		(460	)		(4	)		(575	)

Net income (loss) from continuing operations		(899	)		(1,140	)		230			—		(5,096	)		(5,814	)		(12,719	)
Net loss from discontinued operations		—			—			—			—		—			—			—

Net income (loss) and comprehensive loss	$	(899	)	$	(1,140	)	$	230		$	—	$	(5,096	)	$	(5,814	)	$	(12,719	)


Capital Investments	$	23,162		$	9,282		$	7,366		$	—	$	365		$	388		$	40,563


Identifiable Assets
As at June 30, 2010	$	118,207		$	18,447		$	60,938		$	—	$	102,970		$	111,977		$	412,539
As at December 31, 2009	$	94,594		$	7,597		$	57,528		$	—	$	102,878		$	19,166		$	281,763


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

Revenue
Oil	$	—		$	—		$	6,009		$	—	$	—		$	—		$	6,009
Loss on derivative instruments		—			—			(1,173	)		—		—			—			(1,173	)
Interest		—			—			2			—		—			6			8

		—			—			4,838			—		—			6			4,844


Expenses
Operating		—			—			2,444			—		—			—			2,444
General and administrative		196			459			630			—		—			2,549			3,834
Business and technology development		93			—			—			—		1,673			—			1,766
Depletion and depreciation		1			22			5,242			—		744			36			6,045
Foreign exchange (gain) loss		(5	)		—			15			—		—			2,670			2,680
Interest and financing		—			—			131			—		26			1			158

		285			481			8,462			—		2,443			5,256			16,927


Loss from continuing operations before income taxes		(285	)		(481	)		(3,624	)		—		(2,443	)		(5,250	)		(12,083	)


Current provision for income taxes		—			—			639			—		—			—			639


Net loss from continuing operations		(285	)		(481	)		(2,985	)		—		(2,443	)		(5,250	)		(11,444	)
Net income from discontinued operations		—			—			—			66		—			—			66

Net income (loss) and comprehensive loss	$	(285	)	$	(481	)	$	(2,985	)	$	66	$	(2,443	)	$	(5,250	)	$	(11,378	)


Capital Investments	$	4,009		$	895		$	1,368		$	—	$	420		$	—		$	6,692


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

Revenue
Oil	$	—		$	—		$	11,742		$	—		$	—		$	—		$	11,742
Loss on derivative instruments		—			—			(1,092	)		—			—			—			(1,092	)
Interest		—			—			4			—			—			14			18

		—			—			10,654			—			—			14			10,668


Expenses
Operating		—			—			5,145			—			—			—			5,145
General and administrative		334			977			1,027			—			—			7,376			9,714
Business and technology development		387			—			—			—			3,416			—			3,803
Depletion and depreciation		2			36			10,516			—			1,373			73			12,000
Foreign exchange (gain) loss		(5	)		—			36			—			—			1,655			1,686
Interest and financing		—			—			279			—			51			5			335

		718			1,013			17,003			—			4,840			9,109			32,683


Loss from continuing operations before income taxes		(718	)		(1,013	)		(6,349	)		—			(4,840	)		(9,095	)		(22,015	)


Current provision for income taxes		—			—			(997	)		—			—			(9	)		(1,006	)


Net loss from continuing operations		(718	)		(1,013	)		(7,346	)		—			(4,840	)		(9,104	)		(23,021	)
Net loss from discontinued operations		—			—			—			(631	)		—			—			(631	)

Net loss and comprehensive loss	$	(718	)	$	(1,013	)	$	(7,346	)	$	(631	)	$	(4,840	)	$	(9,104	)	$	(23,652	)


Capital Investments	$	6,077		$	1,551		$	2,524		$	—		$	1,694		$	54		$	11,900

9. FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

Financial instruments are comprised of cash and cash equivalents, accounts receivable, note receivable, restricted cash, accounts payable and accrued liabilities, long term debt 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 long term debt. Upon considering the Company’s credit risk, the fair value of long term debt at June 30, 2010, is $35.8 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

Supplemental cash flow information for the three and six months ended June 30, 2010:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009

Cash paid during the period for
Income taxes	$	211		$	1,647		$	638		$	1,655
Interest	$	10		$	64		$	815		$	1,195


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


Changes in non-cash working capital items
Operating activities
Accounts receivable	$	(553	)	$	(697	)	$	(309	)	$	(1,361	)
Note receivable		5			—			(31	)		—
Prepaid and other current assets		(801	)		(56	)		(678	)		(22	)
Accounts payable and accrued liabilities		708			(946	)		745			(1,244	)
Income tax payable		(172	)		(2,286	)		(522	)		(650	)

		(813	)		(3,985	)		(795	)		(3,277	)


Investing activities
Accounts receivable		(4	)		9			(29	)		46
Prepaid and other current assets		—			33			83			26
Accounts payable and accrued liabilities		1,957			(7	)		2,779			(744	)

		1,953			35			2,833			(672	)


Financing activities
Accounts payable and accrued liabilities		39			(3	)		39			(26	)

	$	1,179		$	(3,951	)	$	2,077		$	(3,975	)


	June 30,		December 31,
As at	2010		2009

Cash and cash equivalents
Bank accounts	$	8,405	$	21,512
Term deposit		105,412		—

	$	113,817	$	21,512

Cash and cash equivalents at June 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 13, the Company had future tax assets arising from net operating losses carry-forwards generated by this business segment. These future income tax assets were partially offset by certain future income tax liabilities in the 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 reclasify 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 carryforwards to reduce associated future income tax liabilities. Based on these assessments at June 30, 2010, the Company’s future income tax liability is $23.1 million in the accompanying unaudited consolidated balance sheet.

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.

An escrow deposit in the amount 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. It has not yet been determined whether the purchaser’s claims have any merit and the purchaser has not, to date, instituted any formal legal proceedings to pursue these claims. Accordingly, the likelihood of any loss resulting from these claims, and the estimated amount of any such loss, are not determinable or reasonably estimable at this time.

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

In conjunction with the disposition of the US assets and the Company’s focus on heavy oil opportunities, the Company 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, are expected to be $0.5 million.

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


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2010		2009		2010		2009
Revenue
Oil and gas	$	—	$	2,933	$	—	$	4,899
Gain on derivative instruments		—		3		—		189
Interest		—		5		—		8

		—		2,941		—		5,096


Expenses
Operating		—		941		—		1,968
General and administrative		—		63		—		130
Depletion and depreciation		—		1,792		—		3,469
Interest and financing		—		79		—		160

		—		2,875		—		5,727

Net income (loss)	$	—	$	66	$	—	$	(631	)

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 June 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	$	113,817		$	—			$	113,817		$	21,512		$	—			$	21,512
Accounts receivable		5,355			—				5,355			5,021			—				5,021
Note receivable		256			—				256			225			—				225
Prepaid and other current assets		1,366			—				1,366			771			—				771
Restricted cash		2,850			—				2,850			2,850			—				2,850

		123,644			—				123,644			30,379			—				30,379

Oil and gas properties and development costs, net		195,060			(38,500	)	(i)		177,984			158,392			(38,500	)	(i)		139,346
					22,627		(ii)								20,315		(ii)
					(1,203	)	(iii)								(861	)	(iii)
Intangible assets — technology		92,153			—				92,153			92,153			—				92,153
Long term assets		1,682			—				1,682			839			—				839

Total Assets	$	412,539		$	(17,076	)		$	395,463		$	281,763		$	(19,046	)		$	262,717


Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities	$	14,342		$	—			$	14,342		$	10,779		$	—			$	10,779
Income tax payable		8			—				8			530			—				530
Derivative instruments		—			6,907		(vi)		6,907			—			8,249		(vi)		8,249
Asset retirement obligations		50			—				50			753			—				753

		14,400			6,907				21,307			12,062			8,249				20,311

Long term debt		37,255			883		(iii)		37,988			36,934			1,225		(iii)		38,005
					(150	)	(iii)								(154	)	(iii)
Asset retirement obligations		353			—				353			195			—				195
Long term obligation		1,900			—				1,900			1,900			—				1,900
Future income tax liability		23,104			—				23,104			22,643			—				22,643

		77,012			7,640				84,652			73,734			9,320				83,054


Shareholders’ Equity
Share capital		549,281			74,455		(iv)		637,266			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		19,291			(2,720	)	(v)		13,624			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		(268,554	)		(71,525	)			(340,079	)		(255,835	)		(89,171	)			(345,006	)

		335,527			(24,716	)			310,811			208,029			(28,366	)			179,663

	$	412,539		$	(17,076	)		$	395,463		$	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 June 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 June 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 is reversed as well as the unamortized discount of $0.7 million and the accreted discount that was capitalized in the amount of $1.2 million. 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 $0.2 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 June 30, 2010										Three Months Ended June 30, 2009
	Canadian			Increase				US			Canadian			Increase				US
	GAAP			(Decrease)			Notes	GAAP			GAAP			(Decrease)			Notes	GAAP
Revenue
Oil	$	6,047		$	—			$	6,047		$	6,009		$	—			$	6,009
Gain (loss) on derivative instruments		—			15,465		(vi)		15,465			(1,173	)		(564	)	(vi)		(1,737	)
Interest		23			—				23			8			—				8

		6,070			15,465				21,535			4,844			(564	)			4,280


Expenses
Operating		2,327			—				2,327			2,444			—				2,444
General and administrative		5,478			—				5,478			3,834			—				3,834
Business and technology development		2,423			—				2,423			1,766			—				1,766
Depletion and depreciation		2,582			(1,219	)	(ix)		1,363			6,045			(3,140	)	(ix)		2,905
Foreign exchange (gain) loss		3,086			(115	)	(iii)		2,971			2,680			112		(iii)		2,792
Interest and financing		4			—				4			158			—				158
Provision for impairment of intangible asset and development costs		—			—				—			—			5		(viii)		5

		15,900			(1,334	)			14,566			16,927			(3,023	)			13,904


Loss from continuing operations before income tax		(9,830	)		16,799				6,969			(12,083	)		2,459				(9,624	)

Provision for income tax
Current		(36	)		—				(36	)		639			—				639
Future		(286	)		—				(286	)		—			—				—

		(322	)		—				(322	)		639			—				639


Net income (loss) from continuing operations		(10,152	)		16,799				6,647			(11,444	)		2,459				(8,985	)
Net income (loss) from discontinued operations		—			—				—			66			1,085		(x)		1,151

Net loss and comprehensive loss	$	(10,152	)	$	16,799			$	6,647		$	(11,378	)	$	3,544			$	(7,834	)


Net income (loss) per share
Net income (loss) from continuing operations, basic and diluted	$	(0.03	)	$	0.05			$	0.02		$	(0.04	)	$	0.01			$	(0.03	)
Net income from discontinued operations, basic and diluted		—			—				—			—			—				—

Net income (loss) per share, basic and diluted	$	(0.03	)	$	0.05			$	0.02		$	(0.04	)	$	0.01			$	(0.03	)


Weighted average number of shares (in thousands)
Basic and diluted		333, 922							333,922			279,381							279,381


	Six Months Ended June 30, 2010										Six Months Ended June 30, 2009
	Canadian			Increase				US			Canadian			Increase				US
	GAAP			(Decrease)			Notes	GAAP			GAAP			(Decrease)			Notes	GAAP
Revenue
Oil	$	11,377		$	—			$	11,377		$	11,742		$	—			$	11,742
Gain (loss) on derivative instruments		—			15,338		(vi)		15,338			(1,092	)		(2,605	)	(vi)		(3,697	)
Interest		42			—				42			18			—				18

		11,419			15,338				26,757			10,668			(2,605	)			8,063


Expenses
Operating		4,602			—				4,602			5,145			—				5,145
General and administrative		10,455			—				10,455			9,714			—				9,714
Business and technology development		4,934			—				4,934			3,803			—				3,803
Depletion and depreciation		4,665			(2,312	)	(ix)		2,353			12,000			(6,354	)	(ix)		5,646
Foreign exchange (gain) loss		(1,101	)		4		(iii)		(1,097	)		1,686			(280	)	(iii)		1,406
Interest and financing		8			—				8			335			—				335
Provision for impairment of intangible asset and development costs		—			—				—			—			151		(viii)		151

		23,563			(2,308	)			21,255			32,683			(6,483	)			26,200


Loss from continuing operations before income tax		(12,144	)		17,646				5,502			(22,015	)		3,878				(18,137	)

Provision for income tax
Current		(115	)		—				(115	)		(1,006	)		—				(1,006	)
Future		(460	)		—				(460	)		—			—				—

		(575	)		—				(575	)		(1,006	)		—				(1,006	)


Net income (loss) from continuing operations		(12,719	)		17,646				4,927			(23,021	)		3,878				(19,143	)
Net income (loss) from discontinued operations		—			—				—			(631	)		2,248		(x)		1,617

Net loss and comprehensive loss	$	(12,719	)	$	17,646			$	4,927		$	(23,652	)	$	6,126			$	(17,526	)


Net income (loss) per share
Net income (loss) from continuing operations, basic and diluted	$	(0.04	)	$	0.06			$	0.02		$	(0.08	)	$	0.01			$	(0.07	)
Net income from discontinued operations, basic and diluted		—			—				—			—			0.01				0.01

Net income (loss) per share, basic and diluted	$	(0.04	)	$	0.06			$	0.02		$	(0.08	)	$	0.02			$	(0.06	)


Weighted average number of shares (in thousands)
Basic and diluted		320,651							320,651			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 six months ended June 30, 2010 and 2009.

Discontinued Operations

(x)

For the six months ended June 30, 2009, a $2.2 million adjustment related to discontinued operations resulting from depletion 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 six months ended June 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, 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 section entitled “Risk Factors” in Item 1A and “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of the Company’s 2009 Annual Report on Form 10-K (“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 Annual Report on 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 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.

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

The following table provides certain financial data for the three and six months ended June 30, 2010, compared to the prior periods in 2009.


	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009

Average daily production (bbls/d)		869			1,405			837			1,431
Realized oil prices ($/bbl)	$	76.47		$	46.99		$	75.11		$	45.34
Oil revenue	$	6,047		$	6,009		$	11,377		$	11,742

Working capital (continuing operations⁽¹⁾)	$	109,244		$	13,254		$	109,244		$	13,254
Capital expenditures (continuing operations)	$	15,226		$	6,692		$	40,563		$	11,900

Cash flow used in operating activities (continuing operations)	$	(4,347	)	$	(4,917	)	$	(8,341	)	$	(9,797	)

Net loss (continuing operations)	$	(10,152	)	$	(11,378	)	$	(12,719	)	$	(23,652	)
Net loss per share, basic and diluted (continuing operations)	$	(0.03	)	$	(0.04	)	$	(0.04	)	$	(0.08	)


(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. Realized oil prices in the first half of 2010 increased to $75.11/bbl as a result of stronger benchmark commodity prices.

Working capital increased to $109.2 million at June 30, 2010, primarily as the result of raising net proceeds of $135.8 million through a private placement in the first quarter of 2010. Capital expenditures totaled $40.6 million in the first half of 2010, with progress made across all segments. Drilling at Zitong-1 commenced in China’s Sichuan Province and preparations for a second well, Yixin-2, are underway. Ivanhoe’s second well in Ecuador, IP-5B, successfully reached total depth and logging will commence shortly. Reservoir and geological modeling work for Tamarak is underway following the completion of the winter delineation program.

Net loss from continuing operations was $12.7 million for the first half of 2010. Lower depletion expense, elimination of the unrealized loss on derivatives and a foreign exchange gain were key contributors to the improvement over the prior year. In the second quarter of 2010, the Company’s net loss was $10.2 million, a slight improvement over the second quarter of 2009. Lower depletion and the elimination of the unrealized loss on derivatives were partially offset by higher G&A and business and technology costs.

Changes in Net Loss

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


	Three Months Ended June 30,									Six Months Ended June 30,
	2010			Change			2009			2010			Change			2009
Cash items
Oil revenues	$	6,047					$	6,009		$	11,377					$	11,742
Production volumes					(2,286	)								(4,847	)
Oil prices					2,324									4,482
Realized loss-derivative instruments		—			(76	)		76			—			(612	)		612
Operating costs		(2,327	)		117			(2,444	)		(4,602	)		543			(5,145	)
G&A less stock based compensation		(4,460	)		(1,128	)		(3,332	)		(8,921	)		(142	)		(8,779	)
Business and technology development less stock based compensation		(2,420	)		(678	)		(1,742	)		(4,910	)		(1,159	)		(3,751	)
Foreign exchange (loss) gain		(51	)		9			(60	)		(237	)		(197	)		(40	)
Net interest		19			100			(81	)		34			198			(164	)
Current income tax provision		(36	)		(675	)		639			(115	)		891			(1,006	)

Total cash changes		(3,228	)		(2,293	)		(935	)		(7,374	)		(843	)		(6,531	)


Non-cash items
Unrealized loss on derivatives		—			1,249			(1,249	)		—			1,704			(1,704	)
Foreign exchange (loss) gain		(3,035	)		(415	)		(2,620	)		1,338			2,984			(1,646	)
Depletion and depreciation		(2,582	)		3,463			(6,045	)		(4,665	)		7,335			(12,000	)
Stock based compensation		(1,021	)		(495	)		(526	)		(1,558	)		(571	)		(987	)
Future income tax expense		(286	)		(286	)		—			(460	)		(460	)		—
Discontinued operations (net of tax)		—			(66	)		66			—			631			(631	)
Other		—			69			(69	)		—			153			(153	)

Total non-cash changes		(6,924	)		3,519			(10,443	)		(5,345	)		11,776			(17,121	)


Net loss	$	(10,152	)		1,226		$	(11,378	)	$	(12,719	)		10,933		$	(23,652	)

Oil Production

Production volumes for the three and six month periods ending June 30, 2010, in comparison to the prior year are as follows:

Three Months

Six Months

Ended June 30,

2010

2009

2010

2009

Asia (net bbls)

Dagang

75,210

123,894

143,004

252,372

Daqing

3,861

3,987

8,463

6,587

79,071

127,881

151,467

258,959

Average daily production (bbls/d)

869

1,405

837

1,430

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 when the Company recovered its development investments in September 2009. The number of wells on production at June 30, 2010, was 35 compared to 39 producing wells at June 30, 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

Operating highlights on a per barrel basis are:


	Three Months						Six Months
	Ended June 30,						Ended June 30,
($/bbl)	2010			2009			2010			2009

Oil revenue	$	76.47		$	46.99		$	75.11		$	45.34
Less operating costs:
Field operating		(17.31	)		(16.74	)		(17.85	)		(17.86	)
Windfall Levy		(11.00	)		(1.71	)		(11.09	)		(1.33	)
Engineering and support costs		(1.12	)		(0.66	)		(1.43	)		(0.69	)

Net operating revenue		47.04			27.88			44.74			25.46
Depletion		(31.81	)		(40.99	)		(31.44	)		(40.60	)

Net revenue (loss) from operations	$	15.23		$	(13.11	)	$	13.30		$	(15.14	)

Oil Revenue

Ivanhoe’s oil revenue in the three and six months ended June 30, 2010, remained relatively consistent with the prior year, despite lower net production volumes. The Company’s realized prices increased nearly $30/bbl, following the rising trend in world oil prices in 2010.

Operating Costs

Operating costs in China rose in the three and six months ended June 30, 2010, as the Windfall Levy administered by the Peoples Republic of China (“PRC”) increased. 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 six months ended June 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 second quarter of 2010, G&A rose $1.6 million compared to the second quarter of 2009 due to an increase of $1.8 million in staff and office costs across all operating segments and other minor movements. In the first half of 2010, G&A increased $0.7 million over the first half of 2009 due to higher staff and office costs of $2.7 million incurred across all operating segments, a $0.6 million increase in corporate costs, such as stock exchange filing fees, director costs and non-cash stock based compensation, offset by a decrease of $2.7 million in corporate legal services incurred in 2009 in regards to the Grynberg legal proceedings.

Business and Technology Development

Business and technology development expenses increased when compared to the same periods in 2009 mainly as a result of higher operating costs attributed to FTF evaluations of Tamarack and Pungarayacu production samples.

Depletion and Depreciation

Depletion and depreciation in the three and six months ended June 30, 2010, decreased compared to 2009. The reduction is attributable to lower depletion in Asia and the absence of $0.6 million per quarter of depreciation on the CDF that was retired in 2009.

Asia

China’s depletion decreased in comparison to the prior year due to lower net production volumes and higher Dagang proved reserves at January 1, 2010. For the three months ended June 30, 2010, depletion declined by $2.7 million compared to 2009. Lower net production volumes accounted for $2.0 million of the decrease while a rate decrease of $9.18/bbl accounted for the remaining $0.7 million reduction. Depletion in the six months ended June 30, 2010, was $5.8 million lower than the first half of 2009. Lower net production volumes accounted for $4.4 million of the decrease while a rate decrease of $9.16/bbl accounted for the remaining $1.4 million decrease.

Foreign Exchange

Ivanhoe holds monetary assets that are principally in the form of a Canadian dollar term deposit and monetary liabilities that are primarily associated with its Canadian dollar denominated debt obligation. Since the Company prepares its consolidated balance sheet on a US dollar functional currency basis, it must translate these balances from Canadian dollars to a US dollar equivalent basis at the period end exchange rate. These translations give rise to unrealized foreign exchange gains or losses depending on whether the Canadian dollar strengthened or weakened relative to the US dollar between the comparative balance sheet dates. Any unrealized foreign exchange gains or losses flow through to the consolidated income statement.

Similarly, since Ivanhoe conducts its operations in a variety of currencies but reports in US dollars, realized foreign exchange gains or losses may be incurred depending on the relative strengthening or weakening of foreign currencies relative to the US dollar.

The net impact of these foreign exchange effects on the Company’s unaudited consolidated income statement is a $3.1 million loss and $1.1 million gain respectively in the three and six months ended June 30, 2010, as a result of the Canadian dollar strengthening against the US dollar in the first quarter and subsequently weakening against the US dollar in the second quarter of 2010.

Interest and Financing Costs

Interest expense for both the three and six months ended June 30, 2010, was lower in comparison to 2009 as a result of 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 no longer holds derivative positions. The three and six months ended June 30, 2009, included a mark-to-market loss on derivatives of $1.2 million and $1.1 million respectively.

Provision for/Recovery of Income Taxes

Asia

Provisions for current income taxes in the first six months of 2010 decreased in comparison to the first half of 2009. The decrease is 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 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 pending sale of the business segment, the Company was no longer able to offset these tax assets and liabilities but was required to present these future income tax assets as “assets from discontinued operations” and a future income tax liability both in the amount of $29.6 million in the June 30, 2009, consolidated balance sheet. 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.

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.

FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations

The following is a summary of the Company’s contractual obligations at June 30, 2010.


	Payments Due by Year
	Total		2010		2011		2012		2013		After 2013

Included in balance sheet
Long term debt	$	37,255	$	—	$	37,255	$	—	$	—	$	—
Asset retirement obligation		710		50		—		160		—		500
Long term obligation		1,900		—		—		—		1,900		—

Other commitments
Interest payable		1,748		—		1,748		—		—		—
Lease commitments		2,323		582		1,153		462		126		—
Zitong exploration commitment		21,076		21,076		—		—		—		—
Nyalga exploration commitment		1,464		—		—		—		1,464		—

	$	66,476	$	21,708	$	40,156	$	622	$	3,490	$	500

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						Six Months
	Ended June 30,						Ended June 30,
	2010			2009			2010			2009

Cash used in operating activities (continuing operations)	$	(4,347	)	$	(4,917	)	$	(8,341	)	$	(9,797	)
Cash used in investing activities (continuing operations)	$	(13,771	)	$	(6,810	)	$	(38,576	)	$	(12,725	)
Cash provided by (used in) financing activities (continuing operations)	$	(59	)	$	(28	)	$	137,898		$	(542	)

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 $109 million at June 30, 2010, to meet its commitments outlined above. 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 second quarter of 2010, cash from operating activities from continuing operations, excluding the impact of changes in working capital, declined in comparison to the second quarter of 2009 due to higher G&A and business and technology costs. Similarly, higher G&A and business and technology costs in the first half of 2010 compared to the first half of 2009 decreased cash from operating activities, excluding the impact of changes in working capital.

Investing Activities


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2010		2009		2010		2009

Oil and gas activities
Canada	$	5,250	$	4,009	$	23,162	$	6,077
Ecuador		5,107		895		9,282		1,551
Asia		4,563		1,368		7,366		2,524
Business and technology development		140		420		365		1,694
Corporate		166		—		388		54

Total capital expenditures	$	15,226	$	6,692	$	40,563	$	11,900

Canada

Activity during the second quarter of 2010 focused on the analysis of the data gathered from the 28 delineation wells drilled in the first quarter of the year. Activity in the first half of 2009 consisted of seismic and environmental work.

Ecuador

In the second quarter of 2010, Ivanhoe drilled its second well in Ecuador, IP-5B. The Company conducted coring and logging programs, as well as steam testing on the IP-15 well. In the first six months of 2009, an environmental assessment was conducted and planning activities for an appraisal well commenced.

Asia

In the second quarter of 2010, drilling at Zitong-1 commenced in China’s Sichuan Province and preparations for a second well, Yixin-2, were underway. In the first quarter of 2010, activities focused on preparatory activities for Zitong-1 as well as a seismic program in the Nyalga basin of Mongolia. In the first half of 2009, the fracture stimulation program was underway at Dagang and the Company was obtaining drilling locations and waiting for Phase 2 Exploration approval at Zitong.

Business and Technology Development

The FTF was reconfigured in the second quarter of 2010 to test different samples from the Tamarack and Pungarayacu projects. Activities in the first quarter of 2010 tested operating conditions under different environments. Expenditures were higher in 2009 as costs were incurred for the construction and delivery of the FTF in the second quarter of 2009.

Corporate

Capital expenditures in the Corporate segment consisted of computer equipment, furniture and leasehold improvements for the Company’s corporate offices in Calgary, Alberta.

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


	June 30,		December 31,
	2010		2009

Long term debt	$	37,255	$	36,934

Shareholders’ equity	$	335,527	$	208,029

Long term debt, composed of a convertible note, increased by $0.3 million due to 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. The exercise of stock options contributed $2.0 million to equity in the first half of 2010.

Outlook for 2010

In the second half of 2010, it is expected that Ivanhoe’s capital program will focus on the continued advancement of the Tamarack and Pungarayacu heavy oil projects, exploration drilling in the Zitong Block in China and the commencement of drilling in Mongolia in Block XVI. Minor expenditures may be incurred for development costs relating to the enhancement of the Company’s HTL^TMupgrading process as well as maintenance in the Dagang oil field in China. 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 alternative business alliances with other parties or raise additional capital. If the Company is unable to enter into such business alliances or obtain adequate additional financing, the Company will 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 used 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 complete discussion of the project can be found in the Company’s 2009 Form 10-K under “Management’s Discussion and Analysis.”

During the second quarter of 2010, IFRS accounting policy recommendations were presented to the Company’s IFRS Steering Committee and the policies were recommended for final approval by the Audit Committee at their next meeting. The process of drafting IFRS consolidated financial statements and note disclosures is underway. Ivanhoe continues to work with advisors to finalize the January 1, 2010 opening balance sheet retrospective adjustments. The Company’s IFRS project will continue through 2010 and is on schedule for a January 1, 2011 implementation date.

At this time, Ivanhoe cannot quantify the impact that the adoption of IFRS will have on the future consolidated financial statements as it will depend upon the accounting policy choices made by the Company as well as IFRS standards existing as at 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 June 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 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.

There were no changes in the Company’s internal control over financial reporting in the quarter ended June 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. 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: August 9, 2010

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