Edgar Filing: IVANHOE ENERGY INC

Form 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

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 (IRS Employer Identification No.)

654-999 Canada Place
Vancouver, BC, Canada V6C 3E1
(604) 688-8323
(Address and telephone number of the registrant’s principal executive offices)

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

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 29, 2011, Ivanhoe Energy Inc. had 344,139,428 Common Shares outstanding with no par value.

TABLE OF CONTENTS



PART I

ITEM 1: Financial Statements

Unaudited Condensed Consolidated Statements of Financial Position			3

Unaudited Condensed Consolidated Statements of Loss and Comprehensive Loss			4

Unaudited Condensed Consolidated Statements of Changes in Equity			5

Unaudited Condensed Consolidated Statements of Cash Flows			6

Notes to the Unaudited Condensed Consolidated Financial Statements			7

ITEM 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations			25

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			34

ITEM 4: Controls and Procedures			34

PART II

ITEM 1: Legal Proceedings			35

ITEM 6: Exhibits			36

Exhibit 1.1
Exhibit 4.1
Exhibit 10.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I FINANCIAL INFORMATION


ITEM 1.		FINANCIAL STATEMENTS

IVANHOE ENERGY INC.

Condensed Consolidated Statements of Financial Position

(Unaudited)


		June 30,			December 31,			January 1,
(US$000s)	Notes	2011			2010			2010

Assets
Current Assets
Cash and cash equivalents	3		133,308			68,317			24,362
Accounts receivable			8,453			6,359			5,021
Note receivable			231			264			225
Prepaid and other			766			2,859			771

			142,758			77,799			30,379

Intangible	4		299,061			273,568			207,750
Property, plant and equipment	5		44,401			40,618			41,983
Long term receivables			2,899			2,433			839

			489,119			394,418			280,951



Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities			28,555			21,482			10,779
Debt	6		41,441			39,832			—
Derivative instruments	7		316			8,447			13,023
Income taxes			475			—			530
Decommissioning costs			—			—			753

			70,787			69,761			25,085

Long term debt	6		64,322			—			36,934
Long term derivative instruments	7		7,595			—			—
Long term provisions			3,081			3,008			2,187
Deferred income taxes			21,872			21,165			22,336

			167,657			93,934			86,542


Shareholders’ Equity
Share capital	10		585,773			550,562			422,322
Contributed surplus	11		24,145			23,141			18,724
Accumulated deficit			(288,456	)		(273,219	)		(246,637	)

			321,462			300,484			194,409

			489,119			394,418			280,951


Nature of operations and going concern	1

(See accompanying Notes to the Unaudited Condensed Consolidated Financial Statements)

IVANHOE ENERGY INC.

Condensed Consolidated Statements of (Loss) Income and Comprehensive (Loss) Income

(Unaudited)


		Three Months Ended						Six Months Ended
		June 30,						June 30,
(US$000s, except share and per share amounts)	Note	2011			2010			2011			2010

Revenue
Oil			9,389			6,047			17,508			11,377
Interest			143			23			210			42

			9,532			6,070			17,718			11,419


Expenses
Operating	13		5,339			3,252			9,862			6,706
Exploration and evaluation	4		—			984			—			1,590
General and administrative			11,744			9,093			25,161			17,525
Depletion and depreciation	5		1,891			1,921			3,722			3,458
Foreign currency exchange (gain) loss			(238	)		3,086			(463	)		(1,101	)
Derivative instruments gain	7		(6,071	)		(21,840	)		(7,200	)		(19,783	)
Interest			359			4			367			8

			13,024			(3,500	)		31,449			8,403


(Loss) income before income taxes			(3,492	)		9,570			(13,731	)		3,016

Provision for income taxes
Current			(477	)		(36	)		(799	)		(115	)
Deferred			(142	)		(275	)		(707	)		(447	)

			(619	)		(311	)		(1,506	)		(562	)


Net (loss) income and comprehensive (loss) income			(4,111	)		9,259			(15,237	)		2,454


Net (loss) income per common share
Basic	14		(0.01	)		0.03			(0.04	)		0.01
Diluted	14		(0.01	)		0.01			(0.04	)		(0.05	)

Weighted average number of common shares (000s)
Basic	14		338,432			333,922			341,197			320,651
Diluted	14		338,432			349,705			341,197			339,072

(See accompanying Notes to the Unaudited Condensed Consolidated Financial Statements)

IVANHOE ENERGY INC.

Condensed Consolidated Statements of Changes in Equity

(Unaudited)


		Share Capital
		Shares				Contributed			Accumulated
(US$000s, except share amounts)	Note	(000s)		Amount		Surplus			Deficit			Total

Balance January 1, 2010			282,559		422,322		18,724			(246,637	)		194,409
Net income and comprehensive income			—		—		—			2,454			2,454
Shares issued for cash, net of share issue costs			50,000		121,766		—			—			121,766
Shares issued for services			280		799		—			—			799
Exercise of stock options	11		1,171		4,315		(2,225	)		—			2,090
Exercise of purchase warrants			2		9		—			—			9
Share-based compensation expense	11		—		—		2,432			—			2,432

Balance June 30, 2010			334,012		549,211		18,931			(244,183	)		323,959


		Share Capital
		Shares				Contributed			Accumulated
(US$000s, except share amounts)	Note	(000s)		Amount		Surplus			Deficit			Total

Balance January 1, 2011			334,365		550,562		23,141			(273,219	)		300,484
Net loss and comprehensive loss			—		—		—			(15,237	)		(15,237	)
Exercise of stock options	11		984		4,164		(2,231	)		—			1,933
Exercise of purchase warrants			8,621		31,047		—			—			31,047
Share-based compensation expense	11		—		—		3,235			—			3,235

Balance June 30, 2011			343,970		585,773		24,145			(288,456	)		321,462

(See accompanying Notes to the Unaudited Condensed Consolidated Financial Statements)

IVANHOE ENERGY INC.

Condensed Consolidated Statements of Cash Flows

(Unaudited)


		Three Months Ended						Six Months Ended
		June 30,						June 30,
(US$000s)	Note	2011			2010			2011			2010

Operating Activities
Net (loss) income			(4,111	)		9,259			(15,237	)		2,454
Adjustments to reconcile net loss to cash from operating activities
Depletion and depreciation	5		1,891			1,921			3,722			3,458
Share-based compensation expense	11		1,471			1,209			3,247			2,432
Unrealized foreign currency exchange (gain) loss			(1,553	)		3,035			(1,780	)		(1,338	)
Unrealized gain on derivative instruments	7		(6,071	)		(21,840	)		(7,200	)		(19,783	)
Current income tax expense			477			36			799			115
Deferred income tax expense			142			275			707			447
Exploration and evaluation expense	4		—			984			—			1,590
Interest expense			359			4			367			8
Finance costs			269			—			269			—
Other			(106	)		(186	)		(12	)		2
Current income tax paid			(267	)		(210	)		(324	)		(638	)
Decommissioning costs settled			—			(124	)		—			(182	)
Changes in non-cash working capital items	15		1,044			(639	)		1,978			(272	)

Net cash used in operating activities			(6,455	)		(6,276	)		(13,464	)		(11,707	)


Investing Activities
Intangible expenditures			(13,906	)		(11,460	)		(23,772	)		(34,140	)
Property, plant and equipment expenditures			(3,514	)		(1,417	)		(7,463	)		(2,235	)
Long term receivables			(316	)		(498	)		(463	)		(846	)
Interest paid			15			—			(1,003	)		(844	)
Changes in non-cash working capital items	15		1,082			1,533			4,578			2,855

Net cash used in investing activities			(16,639	)		(11,842	)		(28,123	)		(35,210	)


Financing Activities
Shares and warrants issued on private placements, net of share issue costs			—			(556	)		—			135,765
Convertible debentures issued, net of issue costs	6		72,914			—			72,914			—
Proceeds from exercise of options and warrants	7,11		59			458			29,873			2,094
Changes in non-cash working capital items	15		(28	)		39			(47	)		39

Net cash provided by (used in) financing activities			72,945			(59	)		102,740			137,898


Foreign exchange gain (loss) on cash and cash equivalents held in a foreign currency			2,659			(4,391	)		3,838			1,324

Increase in cash and cash equivalents, for the period			52,510			(22,568	)		64,991			92,305
Cash and cash equivalents, beginning of period			80,798			139,235			68,317			24,362

Cash and cash equivalents, end of period			133,308			116,667			133,308			116,667

(See accompanying Notes to the Unaudited Condensed Consolidated Financial Statements)

IVANHOE ENERGY INC.

Notes to the Unaudited Condensed Consolidated Financial Statements

(tabular amounts in US$000s, except share and per share amounts)

1. NATURE OF OPERATIONS AND GOING CONCERN

Ivanhoe Energy Inc. (the “Company” or “Ivanhoe”) is a publicly listed company incorporated in Canada, with limited liability under the legislation of the Yukon. Ivanhoe’s common shares are listed on the Toronto Stock Exchange (“TSX”) and the NASDAQ Stock Market (“NASDAQ”). The head office, principal address and registered and records office of the Company are located at 999 Canada Place, Suite 654, Vancouver, British Columbia, V6C 3E1.

Ivanhoe is an independent international heavy oil development and production company focused on pursuing long term growth in its reserves and production. Ivanhoe plans to utilize advanced technologies, such as its HTL^TM technology, that are designed to significantly improve recovery of heavy oil resources. In addition, the Company seeks to expand its reserve base and production through conventional exploration and production of oil and gas.

The June 30, 2011 unaudited condensed consolidated interim financial statements (“Financial Statements”) have been prepared using International Financial Reporting Standards (“IFRS”) applicable to a going concern, which contemplates the realization of assets and settlement of liabilities in the normal course of business as they become due and assumes that Ivanhoe will be able to meet its obligations and continue operations for at least its next fiscal year. Realization values may be substantially different from carrying values as shown and these Financial Statements do not give effect to adjustments that may be necessary to the carrying values and classification of assets and liabilities should the Company be unable to continue as a going concern. Such adjustments could be material.

At June 30, 2011, Ivanhoe had an accumulated deficit of $288.5 million and working capital of $72.3 million excluding derivative financial liabilities. In the first six months of 2011, cash used in operating activities was $13.5 million and the Company expects to incur further losses in the development of its business. Continuing as a going concern is dependent upon attaining future profitable operations to repay liabilities arising in the normal course of operations and accessing additional capital to develop the Company’s properties. Ivanhoe intends to finance its future funding requirements through a combination of strategic investors and/or public and private debt and equity markets, either at a parent company level or at the project level. There is no assurance that Ivanhoe will be able to obtain such financing or obtain it on favorable terms. Without access to additional financing or other cash generating activities in 2012, there is significant doubt that the Company will be able to continue as a going concern.

The June 30, 2011 Financial Statements were approved by the Board of Directors and authorized for issue on July 28, 2011.

The Financial Statements are presented in US dollars and all values are rounded to the nearest thousand dollars except where otherwise indicated.

2. BASIS OF PRESENTATION

2.1 Statement of Compliance

The Financial Statements have been prepared in accordance with IAS 34, “Interim Financial Reporting” (“IAS 34”), using accounting policies consistent with IFRS as issued by the International Accounting Standards Board (“IASB”) that the Company expects to adopt in its consolidated financial statements for the year ending December 31, 2011. The Financial Statements are not subject to qualification relating to the application of IFRS as issued by the IASB.

2.2 Basis of Presentation

The Company adopted IFRS on January 1, 2011, with a transition date of January 1, 2010. Comparative financial information has been restated to comply with IFRS as detailed in Note 19. The accounting policies adopted by Ivanhoe as a result of IFRS may be found in Note 3 of the Company’s March 31, 2011 financial statements.

The Financial Statements have been prepared on an historical cost basis, except financial instruments, which are measured at fair value.

The Company has reviewed new and revised accounting pronouncements listed below, that have been issued but are not yet effective. The Company has not yet evaluated the impact of these changes on its financial statements.

IFRS 9 Financial Instruments (“IFRS 9”)

IFRS 9 was issued in November 2009 and is intended to replace IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”) in phases. IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, as opposed to the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments given its business model and the contractual cash flow characteristics of the financial assets. The standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39. IFRS 9 is effective for reporting periods beginning on or after January 1, 2013.

IFRS 10 Consolidated Financial Statements (“IFRS 10”)

IFRS 10 was issued in May 2011 and sets a single basis for consolidation, that being control of an entity. IFRS 10 replaces portions of IAS 27, “Consolidated and Separate Financial Statements” that address how entities should prepare consolidated financial statements. This standard is effective for reporting periods on or after January 1, 2013 with earlier adoption permitted.

IFRS 11 Joint Arrangements (“IFRS 11”)

IFRS 11, issued in May 2011, establishes principles for financial reporting by entities involved in a joint arrangement. IFRS 11 supersedes the current IAS 31, “Interests in Joint Ventures” and SIC 13, “Jointly Controlled Entities-Non Monetary Contributions by Venturers” and is effective for reporting periods beginning on or after January 1, 2013. Earlier application is permitted.

IFRS 12 Disclosure of Interests in Other Entities (“IFRS 12”)

IFRS 12, issued in May 2011, establishes a single set of disclosure objectives, and requires minimum disclosures designed to meet those objectives, regarding interests in subsidiaries, joint arrangements, associates or unconsolidated structured entities. IFRS 12 is intended to combine the disclosure requirements on interests in other entities currently located throughout different standards. This standard is effective for reporting periods on or after January 1, 2013 with earlier adoption permitted.

IFRS 13 Fair Value Measurements (“IFRS 13”)

IFRS 13, issued in May 2011, defines fair value, sets out a single IFRS framework for measuring fair value and requires disclosures about fair value measurements. IFRS 13 applies to IFRS that require or permit fair value measurements or related disclosures, except in specified circumstances. IFRS 13 is to be applied for reporting periods beginning on or after January 1, 2013. Earlier application is permitted.

IAS 12 Income Taxes (“IAS 12”)

IAS 12 was amended in December 2010 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset. The amendment introduces a presumption that an entity will assess whether or not the carrying value of an asset will be recovered through the sale of the asset. The amendment to IAS 12 is effective for reporting periods beginning on or after January 1, 2012.

IAS 28 Investments in Associates and Joint Ventures (“IAS 28”)

IAS 28 was amended in 2011 which prescribes the accounting for investments in associates and sets out the requirements for the application of the equity method when accounting for investments in associates and joint ventures. IAS 28 is effective for reporting periods beginning on or after January 1, 2013. Earlier application is permitted.

There are no other standards or interpretations in issue but not yet adopted that are anticipated to have a material effect on the reported income or net assets of the Company.

3. CASH AND CASH EQUIVALENTS


	June 30,		December 31,		January 1,
	2011		2010		2010
Cash at banks and on hand		132,285		10,147		6,797
Term deposits		—		57,670		—
Money market accounts		—		—		14,715
Restricted cash		1,023		500		2,850

		133,308		68,317		24,362

Restricted cash includes funds pledged as security for a letter of credit with a short term maturity and cash held in escrow.

4. INTANGIBLE ASSETS


	Exploration and Evaluation Assets
						Latin						HTL^TM		Total Intangible
	Asia			Canada		America			Total			Technology		Assets
Cost
Balance January 1, 2010		14,411			94,431		6,755			115,597			92,153		207,750
Additions during the period		27,261			29,324		17,704			74,289			—		74,289
Exploration and evaluation expense		(3,537	)		—		(4,934	)		(8,471	)		—		(8,471	)

Balance December 31, 2010		38,135			123,755		19,525			181,415			92,153		273,568
Additions during the period		14,106			5,233		6,154			25,493			—		25,493

Balance June 30, 2011		52,241			128,988		25,679			206,908			92,153		299,061

Amortization of the Heavy-to-Light (“HTL^TM”) technology has not commenced and its carrying value had not been impaired since it was acquired in 2005.

In the six months ended June 30, 2011, $1.2 million (year ended December 31, 2010 — $2.1 million) in direct and incremental employee benefits attributable to E&E assets were capitalized.

5. PROPERTY, PLANT AND EQUIPMENT


	Oil and Gas Property and Equipment
					Latin				Other			Total
	Asia		Canada		America		Total		Assets			PP&E

Cost
Balance January 1, 2010		31,816		—		—		31,816		11,373			43,189
Additions during the period		4,123		—		—		4,123		1,648			5,771
Disposals		—		—		—		—		(12	)		(12	)

Balance December 31, 2010		35,939		—		—		35,939		13,009			48,948
Additions during the period		6,279		—		—		6,279		1,234			7,513
Disposals		—		—		—		—		(5	)		(5	)

Balance June 30, 2011		42,218		—		—		42,218		14,238			56,456


Accumulated Depreciation
Balance January 1, 2010		—		—		—		—		1,206			1,206
Depletion and depreciation for the period		6,196		—		—		6,196		934			7,130
Disposals		—		—		—		—		(6	)		(6	)

Balance December 31, 2010		6,196		—		—		6,196		2,134			8,330
Depletion and depreciation for the period		3,176		—		—		3,176		550			3,726
Disposals		—		—		—		—		(1	)		(1	)

Balance June 30, 2011		9,372		—		—		9,372		2,683			12,055


Net Book Value
As at January 1, 2010		31,816		—		—		31,816		10,167			41,983
As at December 31, 2010		29,743		—		—		29,743		10,875			40,618
As at June 30, 2011		32,846		—		—		32,846		11,555			44,401

Oil and Gas Property and Equipment

In the six months ended June 30, 2011, nil (year ended December 31, 2010 — $0.1 million) in employee benefits directly attributable to property, plant and equipment (“PP&E”) were capitalized.

Other Assets

Other assets include the Company’s Feedstock Test Facility (“FTF”) at the Southwest Research Institute in San Antonio, Texas, and general furniture and fixtures.

6. DEBT

The Company’s debt consists of a Cdn$40.0 million convertible note and Cdn$73.3 million in convertible debentures.

6.1 Convertible Note


	June 30,			December 31,			January 1,
	2011			2010			2010
Convertible note		41,472			40,217			38,005
Unamortized discount		(31	)		(385	)		(1,071	)

Carrying amount		41,441			39,832			36,934

In connection with the acquisition of the Tamarack leases in July 2008 from Talisman Energy Canada (“Talisman”), the Company issued a Cdn$40.0 million convertible promissory note (the “Convertible Note”). The Convertible Note matured on July 11, 2011 and was repaid in full.

Interest at the prime rate plus 2% was calculated daily. The interest rate on the Convertible Note at June 30, 2011 was 5.00% (December 31, 2010 — 5.00%).

The Company’s obligations under the Convertible Note were secured by a first fixed charge and security interest in favor of Talisman against the acquired Talisman leases and the related assets acquired by the Company pursuant to the Talisman lease acquisition.

In the six months ended June 30, 2011, $1.4 million (year ended December 31, 2010 — $2.5 million) of interest from the Convertible Note was capitalized to E&E assets. No interest from the Convertible Note was recorded as interest expense in the three months and six months ended June 30, 2011 (three months and six months ended June 30, 2010 — nil).

6.2 Convertible Debentures

June 30,

December 31,

January 1,

2011

2010

Convertible debentures

76,008

—

Unamortized financing costs and derivative instrument

(11,686

)

—

Carrying amount

64,322

—

On June 9, 2011, the Company issued Cdn$73.3 million in 5.75% convertible unsecured subordinated debentures (“Convertible Debentures”) at a price of $1,000 per debenture. The issuance included a bought deal of Cdn$50.0 million. The issuance also included Cdn$23.3 million in privately placed debentures with the same terms as the public offering.

The Convertible Debentures mature on June 30, 2016, pay interest semi-annually on June 30 and December 31 and are convertible at a price of Cdn$3.36 per share. They are redeemable after June 30, 2014 at Ivanhoe’s option.

The carrying amount of the Convertible Debentures at June 30, 2011 was $64.3 million. The Canadian dollar denominated debt is considered an embedded derivative since the functional currency of the Company is the US dollar and, as such, the option was separated and recognized at fair value as a long term derivative liability as further described in Note 8.3. The unamortized financing costs in the table above include $9.8 million related to the option as well as $1.8 million in transaction costs. Transaction costs of $0.3 million were allocated to the derivative and charged to earnings in the period.

In the three and six months ended June 30, 2011, $0.4 million was recorded as interest expense (three and six months ended June 30, 2010 — nil).

7. FINANCIAL INSTRUMENTS

The following table presents the Company’s derivative financial instruments measured at fair value through profit and loss (“FVTPL”):


	Level 1			Level 2									Level 3
							2008			2011
	2006			2009 & 2010			Convertible			Convertible					Total
	Purchase			Purchase			Component			Component			Subsidiary		Fair
	Warrants			Warrants			of Debt			of Debentures			Option		Value
Balance January 1, 2010		7,582			667			4,774			—			—		13,023
Issuance of purchase warrants		—			13,999			—			—			—		13,999
Exercise of purchase warrants		(3	)		—			—			—			—		(3	)
Derivative gains through profit and loss		(1,964	)		(13,050	)		(3,558	)		—			—		(18,572	)

Balance December 31, 2010		5,615			1,616			1,216			—			—		8,447
Issuance of convertible debentures		—			—			—			9,771			—		9,771
Exercise of options		(2	)		(3,107	)		—			—			—		(3,109	)
Expiration of purchase warrants through profit and loss		(2,346	)		(1,477	)		—			—			—		(3,823	)
Derivative (gains) losses through profit and loss		(3,267	)		2,968			(1,216	)		(2,176	)		316		(3,375	)

Balance June 30, 2011		—			—			—			7,595			316		7,911

The gain on derivative instruments of $7.2 million for the six months ended June 30, 2011, (six months ended June 30, 2010 — $19.8 million, year ended December 31, 2010 — $18.6 million) originated from the expiration and revaluation of derivative financial instruments measured at FVTPL.

8. DERIVATIVE INSTRUMENTS

The Company’s derivative instruments are comprised of common share purchase warrants, the convertible component of the Convertible Note, the convertible component of the Convertible Debentures and the Subsidiary Option.

8.1 Purchase Warrants

The following table reflects the changes in the Company’s purchase warrants outstanding:


	Purchase			Shares
(000s)	Warrants			Issuable
Balance January 1, 2010		12,135			12,135
Private placements		12,500			12,500
Exercised		(2	)		(2	)

Balance December 31, 2010		24,633			24,633
Exercised		(8,620	)		(8,620	)
Expired		(16,013	)		(16,013	)

Balance June 30, 2011		—			—

All of the Company’s purchase warrants have expired in 2011 and no purchase warrants remain outstanding at June 30, 2011.

At December 31, 2010, the following purchase warrants were exercisable:

Price Per

Exercise

Cash Value on

Special

Outstanding⁽¹⁾

Fair Value

Price Per

Exercise

Valuation

Year of Issue

Warrant

(000s)

($US000s)

Expiry Date

Share

($US000s)

Method

2006

US$2.23

11,398

5,615

May 2011

Cdn$2.93

⁽²⁾

33,577

Quoted Market Price

2009

N/A

735

Feb 2011

Cdn$4.05

2,993

Black-Scholes

2010

Cdn$3.00

10,417

1,326

Feb 2011

Cdn$3.16

33,095

Black-Scholes

2010

Cdn$3.00

2,083

279

Feb 2011

Cdn$3.16

6,619

Black-Scholes

24,633

7,231

76,284


(1)		One common share is issuable for each purchase warrant upon exercise.

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

At December 31, 2010, the fair value of the purchase warrants issued in 2009 and 2010 was calculated using a weighted average risk-free interest rate of 1.0%, a dividend yield of 0.0%, a weighted average volatility factor of 66.6% and an expected life of two months. If the volatility used to fair value the purchase warrants decreased by 10%, the fair value would decrease by $0.4 million. Increasing the volatility by 10% would have had the opposite, but approximately equal, impact.

8.2 Convertible Note

The Company issued a Cdn$40.0 million Convertible Note, as described in Note 6.1. The outstanding principal amount was convertible, at Talisman’s option, into common shares of the Company. The fair value of the convertible component was nil at June 30, 2011 (December 31, 2010 — $1.2 million), calculated with the Black Scholes valuation method using a weighted average risk-free interest rate of 0.91%, a dividend yield of 0.0%, a weighted average volatility factor of 30% and an expected life of eleven days.

If the volatility used to fair value the convertible component increased or decreased by 10%, the fair value would not be affected.

8.3 Convertible Debentures

The Company issued Cdn$73.3 million in convertible debentures in the second quarter of 2011, as described in Note 6.2. The outstanding principal amount is convertible into common shares of the Company. The fair value of the convertible component was $7.6 million at June 30, 2011 (December 31, 2010 — nil), calculated with the Black Scholes valuation method using a weighted average risk-free interest rate of 2.33%, a dividend yield of 0.0%, a weighted average volatility factor of 40% and an expected life of approximately 5 years.

If the volatility used to fair value the convertible debt decreased by 10%, the fair value would decrease by $3.3 million. Increasing the volatility by 10% would have had the opposite, but approximately equal, impact.

8.4 Subsidiary Option

In January 2010, one of the Company’s subsidiaries granted a private investor an option (the “Subsidiary Option”) to acquire an equity interest in the subsidiary representing 20% of the subsidiary’s currently issued share capital (16.67% of the enlarged share capital immediately following the exercise of the Subsidiary Option) for Cdn$25.0 million. If the Subsidiary Option is exercised, Cdn$25 million of existing inter-corporate indebtedness owed by the subsidiary to the Company (through an intermediate subsidiary) will be converted into additional common shares of the subsidiary, thereby diluting the private investor’s equity interest to 14.286%. The Subsidiary Option is valid for one year and did not become exercisable until the first quarter of 2011. The option was determined to have a nominal value on the date of grant.

The fair value of the Subsidiary Option at June 30, 2011 was $0.3 million, calculated with the Black Scholes valuation method using an estimated share value of $17.11, an exercise price of $30.00 per share, a risk-free interest rate of 1.32%, a dividend yield of 0.0%, an expected life of approximately eight months and an estimated volatility of 52.0%, which is similar to Ivanhoe.

If the estimated volatility used to fair value the Subsidiary Option decreased by 10%, the fair value would decrease by $0.2 million. Increasing the volatility by 10% would have had the opposite, but approximately equal, impact.

9. COMMITMENTS AND CONTINGENCIES

9.1 Income Taxes

The Company has an uncertain tax position in China related to when it is entitled to take tax deductions on capitalized development costs that are amortized on a straight-line basis. To the extent that there is a different interpretation in the timing of the deductibility of development costs, this could potentially result in an increase in the current tax expense of $0.9 million.

The Company has an uncertain tax position related to the calculation of a gain on the consideration received from two farm-out transactions. To the extent that the calculation of the gain is interpreted differently and the amounts are subject to withholding tax, there would be an additional current tax expense of approximately $0.7 million.

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

9.2 Operating Lease Arrangements

In the three months and six months ended June 30, 2011, the Company expended $0.9 million and $1.4 million, respectively, (three months and six months ended June 30, 2010 — $0.7 million and $1.2 million, respectively) on operating leases relating to the rental of office space, which expire between 2011 and 2013.

At June 30, 2011, future net minimum payments for operating leases were:


Remainder of 2011			906
2012-2013			1,152

			2,058

9.3 Other

Should Ivanhoe receive government and other approvals necessary to develop the northern border of one of the Tamarack leases, the Company will be required to make a cash payment to Talisman of up to Cdn$15 million.

Occasionally, Ivanhoe enters into consulting agreements whereby a success fee may be payable if and when either a definitive agreement is signed or certain other contractual milestones are met. Under these agreements, the consultant may receive cash, common shares, stock options or some combination thereof.

From time to time, Ivanhoe is involved in litigation or has claims brought against it in the normal course of business. Management is currently not aware of any claims that would materially affect the reported financial position or results of operations.

10. SHARE CAPITAL


Authorized		Unlimited common shares with no par value Unlimited preferred shares with no par value

Issued and Outstanding		343,970,158 common shares (December 31, 2010 — 334,365,482) Nil preferred shares (December 31, 2010 — nil)

See the unaudited Condensed Consolidated Statements of Changes in Equity for the change in common shares issued for the six months ended June 30, 2011 and 2010.

11. SHARE-BASED PAYMENTS

Share-based transactions were charged to earnings as general and administrative or operating expenses and capitalized to E&E assets as follows:

Three months ended

Six months ended

June 30,

2011

2010

2011

2010

Share-based expense related to

Equity settled transactions

1,459

1,021

3,235

1,558

Cash settled transactions

—

Total share-based expense

1,471

1,021

3,247

1,558

Share-based payments capitalized as E&E assets

335

799

335

799

11.1 Stock Option Plan

Details of transactions under the Company’s stock option plan are as follows:

June 30, 2011

December 31, 2010

Number of

Weighted Average

Number of

Weighted Average

Stock Options

Exercise Price

Stock Options

Exercise Price

(000s)

(Cdn$)

(000s)

(Cdn$)

Outstanding, beginning of period

16,927

2.24

15,013

2.27

Granted

1,884

2.67

6,041

2.56

Exercised

(1,518

)

2.38

(2,743

)

2.28

Expired

(596

)

2.76

(635

)

2.60

Forfeited

(471

)

2.46

(749

)

2.64

Outstanding, end of period

16,226

2.24

16,927

2.24

Exercisable, end of period

6,845

2.11

7,324

2.19

The weighted average share price at the date of exercise for stock options exercised in the six months end June 30, 2011 was Cdn$3.28 (six months ended June 30, 2010 — Cdn$3.50).

The weighted average fair value of stock options granted from the stock option plan during the six months ended June 30, 2011 was Cdn$1.61 (six months ended June 30, 2010 — Cdn$2.15) per option at the grant date using the Black Scholes option pricing model. The weighted average assumptions used for the calculation were:


Six months ended June 30,	2011			2010
Expected life (in years)		6.3			6.0
Volatility ⁽¹⁾		74.5	%		76.3	%
Dividend yield		—			—
Risk-free rate		2.7	%		3.1	%
Estimated forfeiture rate		6.0	%		5.2	%


(1)		Expected volatility factor based on historical volatility of the Company’s publicly traded common shares.

The following table summarizes information in respect of stock options outstanding and exercisable at June 30, 2011:


			Weighted Average
			Remaining		Weighted Average
	Outstanding		Contractual Life		Exercise Price
Range of Exercise Prices (Cdn$)	(000s)		(years)		(Cdn$)
1.51 to 2.06		5,711		2.2		1.71
2.15 to 2.71		8,804		5.1		2.39
2.77 to 3.44		1,711		5.2		3.21

		16,226		4.1		2.24

11.2 Restricted Share Unit Plan

The Company adopted a restricted share unit (“RSU”) plan in the second quarter of 2011 under which it may issue restricted share units to directors and eligible employees. RSUs vest evenly over three years and are settled in shares or cash on the anniversary date. RSUs do not entitle the holder to voting rights until they have vested and shares have been provided to the participant.

Details of transactions under the Company’s RSU plan are as follows:


	June 30, 2011
			Weighted Average
	Number of RSUs		Fair Value
	(000s)⁽¹⁾		(Cdn$)
Outstanding, beginning of period		—		—
Granted		1,071		2.16

Outstanding, end of period		1,071		2.16


(1)		Includes RSUs that will be withheld on behalf of employees to satisfy statutory tax withholding requirements.

The weighted average fair value of RSU’s granted during the six months ended June 30, 2011 was Cdn$2.16 per RSU at the grant date using the Black Scholes option pricing model. The weighted average assumptions used for the calculation were:


	Six months ended
	June 30, 2011
Expected life (in years)		3.0
Volatility ⁽¹⁾		62.7	%
Dividend yield		—
Risk-free rate		1.7	%
Estimated forfeiture rate		6.1	%


(1)		Expected volatility factor based on historical volatility of the Company’s publicly traded common shares.

The liabilities arising from the RSUs to be settled by way of cash payments and the intrinsic value of those liabilities are:


	June 30,
	2011
Liabilities related to RSUs		12
Intrinsic value of vested RSUs		—

12. SEGMENT INFORMATION

Ivanhoe’s organizational structure reflects its various operating activities and the geographic areas in which it operates. Oil and gas operations are divided into three geographic segments: Asia, Canada and Latin America. Asian operations capture the Company’s oil production in Dagang and Daqing and exploration at Zitong in China as well as exploration in Mongolia. The Canadian segment comprises activities from Ivanhoe’s oil sands development project at Tamarack in Alberta, Canada. Latin America consists of exploration and development of Block 20 in Ecuador.

The Technology Development area captures costs incurred to develop, enhance and identify improvements in the application of the Company’s HTL™ technology. The Corporate area consists of costs that are not directly allocable to operating projects, such as executive officers, corporate financings and other general corporate activities.

In prior years, the Company’s business development activities were included in a combined Business and Technology Development segment. The comparative information below has been restated to reclassify business development activities to the Corporate segment.

The accounting policies of the segments are the same as the Company’s accounting policies. Segment results include transactions between business segments. Corporate activities undertaken on behalf of a segment are allocated at cost. Oil revenue is classified according to the geographic location of the production.

The following table presents the Company’s segment assets, segment income (loss) and segment revenues reconciled to the Company’s Financial Statements.


							Latin			Technology
	Asia			Canada			America			Development			Corporate			Total

Segment revenue ⁽¹⁾
For the three months ended June 30, 2011		9,391			—			—			—			141			9,532
For the three months ended June 30, 2010		6,049			—			—			—			21			6,070

For the six months ended June 30, 2011		17,511			—			—			—			207			17,718
For the six months ended June 30, 2010		11,382			—			—			—			37			11,419

Segment income (loss)
For the three months ended June 30, 2011		461			(979	)		(2,160	)		(2,759	)		1,326			(4,111	)
For the three months ended June 30, 2010		(1,087	)		(984	)		(1,984	)		(1,336	)		14,650			9,259

For the six months ended June 30, 2011		(1,711	)		(2,286	)		(3,867	)		(5,007	)		(2,366	)		(15,237	)
For the six months ended June 30, 2010		(1,620	)		(1,951	)		(3,666	)		(2,714	)		12,405			2,454

Segment assets ⁽²⁾
As at June 30, 2011		97,100			129,081			33,261			102,742			126,935			489,119
As at December 31, 2010		85,273			123,890			24,392			101,899			58,964			394,418
As at January 1, 2010		57,528			94,594			7,778			101,893			19,158			280,951

Segment liabilities ⁽³⁾
As at June 30, 2011		128,517			138,753			52,807			82,598			(235,018	)		167,657
As at December 31, 2010		114,980			131,277			42,162			76,747			(271,232	)		93,934
As at January 1, 2010		81,047			98,262			13,145			56,909			(162,821	)		86,542

Capital investments — Intangible
For the three months ended June 30, 2011		7,607			1,806			4,493			—			—			13,906
For the three months ended June 30, 2010		2,561			4,316			4,583			—			—			11,460

For the six months ended June 30, 2011		14,106			3,847			5,819			—			—			23,772
For the six months ended June 30, 2010		4,488			21,342			8,310			—			—			34,140

Capital investments — Property, plant and equipment
For the three months ended June 30, 2011		2,755			—			(5	)		764			—			3,514
For the three months ended June 30, 2010		1,075			—			76			100			166			1,417

For the six months ended June 30, 2011		6,301			—			58			1,104			—			7,463
For the six months ended June 30, 2010		1,451			3			87			306			388			2,235


(1)		All oil revenues in Asia are generated from the sale of oil production in China to one customer.

(2)		Segment assets include investments in subsidiaries that are eliminated for consolidation under Corporate.

(3)		Liabilities for Corporate include intercompany receivables of $383.4 million at June 30, 2011 (December 31, 2010 — $352.5 million; January 1, 2010 — $216.7 million) resulting in a negative balance.

13. OPERATING EXPENSES

Operating expenses for the Company are comprised of the following:

Three months ended

Six months ended

June 30,

2011

2010

2011

2010

Asia

Field operating

1,692

1,367

3,315

2,664

Windfall levy

2,182

869

3,759

1,680

Engineering support

103

112

213

240

3,977

2,348

7,287

4,584

Technology Development

FTF operating costs

1,362

904

2,575

2,122

Total operating costs

5,339

3,252

9,862

6,706

The windfall levy is imposed by China’s Ministry of Finance at the progressive rates from 20% to 40% on the portion of the monthly weighted average sales price of the crude oil lifted in China exceeding US$40.00 per barrel.

14. INCOME (LOSS) PER COMMON SHARE

Basic and diluted income or loss per common share are calculated as follows:


	Three months ended						Six months ended
	June 30,						June 30,
	2011			2010			2011			2010
Net income (loss)		(4,111	)		9,259			(15,237	)		2,454
Adjustment for derivative gains on dilutive equity instruments		—			(6,376	)		—			(19,139	)

Diluted net income (loss)		(4,111	)		2,883			(15,237	)		(16,685	)


Basic weighted average common shares		338,432			333,922			341,197			320,651
Adjustment for dilutive equity instruments
Convertible Note		—			12,780			—			12,780
Stock options		—			3,003			—			4,324
Purchase warrants		—			—			—			1,317

Diluted weighted average common shares		338,432			349,705			341,197			339,072


Net income (loss) per common share
Basic		(0.01	)		0.03			(0.04	)		0.01
Diluted		(0.01	)		0.01			(0.04	)		(0.05	)

15. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in Non-Cash Activities


	Three months ended						Six months ended
	June 30,						June 30,
	2011			2010			2011			2010
Operating activities
Accounts receivable		(2,022	)		(553	)		(2,646	)		(309	)
Note receivable		2			5			33			(31	)
Prepaid and other current assets		(214	)		(801	)		(148	)		(678	)
Accounts payable and accrued liabilities		3,278			710			4,739			746

		1,044			(639	)		1,978			(272	)


Investing activities
Accounts receivable		80			(4	)		556			(29	)
Prepaid and other current assets		1,509			—			2,241			83
Accounts payable and accrued liabilities		(507	)		1,537			1,781			2,801

		1,082			1,533			4,578			2,855


Financing activities
Accounts payable and accrued liabilities		(28	)		39			(47	)		39

		2,098			933			6,509			2,622

16. RELATED PARTY TRANSACTIONS

Ivanhoe is party to cost sharing agreements with other companies which are related or controlled through common directors or shareholders. Through these agreements, we share office space, furnishings, equipment, air travel and communications facilities in various international locations. We also share the costs of employing administrative and non-executive management personnel at these offices. The Company is billed on a cost recovery basis in most cases. These transactions have been measured at their exchange amount.

The breakdown of the related party expenses is as follows:


		Three months ended				Six months ended
		June 30,				June 30,
Related Party	Nature of Transaction	2011		2010		2011		2010
Global Mining Management Corp.	Administration		116		335		329		641
Ivanhoe Capital Aviation Ltd.	Aircraft		300		300		600		600
I2MS.Net PTE Ltd.	Information systems		50		152		108		184
Ivanhoe Capital Services Ltd.	Administration		29		58		121		83
SouthGobi Resources Ltd.	Administration		26		—		77		—
GoviEx Gold Inc.	Business development		—		9		—		33
1092155 Ontario Inc.	HTL^TM technology		8		13		20		27
Ensyn Technologies Inc.	HTL^TM technology		—		—		—		7
Ivanhoe Capital PTE Ltd.	Administration		46		7		115		9
Ivanhoe Mines Ltd.	Administration		—		11		—		13

			575		885		1,370		1,597

The liabilities of the Company include the following amounts due to related parties:


		June 30,		December 31,		January 1,
Related Party	Nature of Transaction	2011		2010		2010
Global Mining Management Corp.	Administration		75		86		40
I2MS.Net PTE Ltd.	Information systems		18		13		17
SouthGobi Resources Ltd.	Administration		13		38		—
Ivanhoe Capital Services Ltd.	Management		17		70		15
Ivanhoe Capital PTE Ltd.	Administration		9		—		—

			132		207		72

17. REMUNERATION OF KEY MANAGEMENT PERSONNEL

The remuneration of directors and other key members of management was:

Three months ended

Six months ended

June 30,

2011

2010

2011

2010

Base salaries or fees and other cash payments

1,600

1,483

2,380

2,188

Employer’s contributions to retirement plan

Share-based compensation expense

818

638

1,536

1,034

2,429

2,138

3,943

3,256

18. SUBSEQUENT EVENT

On July 11, 2011, the Cdn$40.0 million Convertible Note owed to Talisman was paid in full using the proceeds from the issuance of the Cdn$73.3 million Convertible Debentures.

19. FIRST-TIME ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS

The Company adopted IFRS on January 1, 2011, with a transition date of January 1, 2010. The accounting policies adopted by Ivanhoe as a result may be found in Note 3 of the Company’s March 31, 2011 financial statements.

Under IFRS 1, “First-time Adoption of International Financial Reporting Standards,” the standards are applied retrospectively at the transition date with all adjustments to assets and liabilities taken to retained earnings unless certain exemptions are applied.

19.1 Exemptions from Full Retrospective Application

IFRS 1 outlines specific guidelines that a first-time adopter must adhere to under certain circumstances. None of the mandatory exemptions from retrospective application were applicable to Ivanhoe. The Company has made the following exemptions to its opening statement of financial position dated January 1, 2010:

i. Deemed Cost

The Company elected to report oil and gas properties, recorded in PP&E and E&E assets, at a deemed cost instead of the actual cost as though IFRS had been adopted retroactively. The deemed cost will be the amounts previously reported under Canadian GAAP.

ii. Decommissioning Provisions Included in the Cost of Property, Plant and Equipment

The exemption provided in IFRS 1 from the full retrospective application of International Financial Reporting Committee 1 “Changes in Existing Decommissioning, Restoration and Similar Liabilities” was applied to decommissioning liabilities associated with our oil and gas properties recorded in PP&E and intangible assets. The Company elected to re-measure its FTF decommissioning provision under IFRS.

iii. Share-Based Payment

The Company elected to apply the share-based payment exemption and has applied IFRS 2, “Share-based Payments” only to those stock options that were issued after November 7, 2002, but that had not vested by the January 1, 2010 transition date.

iv. Business Combinations

The Company applied the business combinations exemption in IFRS 1 and has not restated business combinations that took place prior to the January 1, 2010 transition date.

v. Leases

The Company applied the lease exemption in IFRS 1 for contracts and agreements entered into before January 1, 2010. Where Ivanhoe has, under Canadian GAAP, made the same determination of whether an arrangement contains a lease as required by IFRIC 4, “Determining whether an Arrangement contains a Lease,” but that assessment was made at a date other than that required by IFRIC 4, the Company elected not to reassess that determination.

19.2 Reconciliations to IFRS

IFRS employs a conceptual framework that is similar to Canadian GAAP. While the adoption of IFRS has not changed the actual cash flows of the Company, the adoption has resulted in significant changes to the reported financial position and results of operations of the Company. Presented below are reconciliations prepared by the Company to reconcile to IFRS the Consolidated Statement of Financial Position and Consolidated Statement of Loss and Comprehensive Loss of the Company from those reported under Canadian GAAP.

Changes made to the statements of financial position and statements of (loss) income have resulted in reclassifications of various amounts on the statements of cash flows. Due to the reclassification of capitalized overhead under Canadian GAAP to operating costs or general and administrative (“G&A”) expenses under IFRS, cash used in investing activities under Canadian GAAP was reclassified to cash used in operating activities under IFRS. Since there was no change to the total increase in cash and cash equivalents, no reconciliation for the statements of cash flows was presented.

Certain amounts previously reported under Canadian GAAP have been reclassified to conform with IFRS presentation standards. Restricted cash was combined with cash and cash equivalents and asset retirement obligations were combined with other long term provisions. Other name changes have been made to certain financial statement line items to conform with the IFRS format standards.

Reconciliation of Consolidated Statements of Financial Position


	At January 1, 2010									At December 31, 2010									At June 30, 2010
	Canadian			Effect of			IFRS			Canadian			Effect of			IFRS			Canadian			Effect of			IFRS
(US$000s)	GAAP			Transition			Balances			GAAP			Transition			Balances			GAAP			Transition			Balances

Assets
Current Assets
Cash and cash equivalents		24,362			—			24,362			68,317			—			68,317			116,667			—			116,667
Accounts receivable		5,021			—			5,021			6,359			—			6,359			5,355			—			5,355
Note receivable		225			—			225			264			—			264			256			—			256
Prepaid and other current assets		771			—			771			2,859			—			2,859			1,366			—			1,366

		30,379			—			30,379			77,799			—			77,799			123,644			—			123,644

Intangible assets		92,153			115,597	a		207,750			92,153			197,193	a		273,568			92,153			154,810	a		242,423
					—									(7,482	)b								(2,950	)b
					—									175	c								(1,590	)g
					—									(8,471	)g								—
Property, plant and equipment, net		158,392			(115,597	)a		41,983			237,200			(197,193	)a		40,618			195,060			(154,810	)a		40,229
					(904	)b								(2,014	)b								(1,320	)b
					92	c								189	c								92	c
					—									2,436	f								1,207	f
Long term receivables		839			—			839			2,433			—			2,433			1,682			—			1,682

		281,763			(812	)		280,951			409,585			(15,167	)		394,418			412,539			(4,561	)		407,978


Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		10,779			—			10,779			21,482			—			21,482			14,342			—			14,342
Debt		—			—			—			39,832			—			39,832			—			—			—
Derivative financial instruments		—			13,023	d		13,023			—			8,447	d		8,447			—			7,235	d		7,235
Income tax payable		530			—			530			—			—			—			8			—			8
Decommissioning costs		753			—			753			—			—			—			50			—			50

		12,062			13,023			25,085			61,314			8,447			69,761			14,400			7,235			21,635

Long term debt		36,934			—			36,934			—			—			—			37,255			—			37,255
Long term provisions		2,095			92	c		2,187			2,644			364	c		3,008			2,253			92	c		2,345
Deferred income tax liability		22,643			(307	)b		22,336			21,518			(367	)b		21,165			23,104			(327	)b		22,784
					—									14	f								7	f

		73,734			12,808			86,542			85,476			8,458			93,934			77,012			7,007			84,019


Shareholders’ Equity
Share capital		422,322			—			422,322			550,562			—			550,562			549,281			(70	)e		549,211
Purchase warrants		19,427			(19,427	)d		—			33,423			(33,423	)d		—			33,423			(33,423	)d		—
Contributed surplus		20,029			(2,947	)d		18,724			22,983			(2,947	)d		23,141			19,291			(2,947	)d		18,931
					1,642	e								3,105	e								2,587	e
Convertible note		2,086			(2,086	)d		—			2,086			(2,086	)d		—			2,086			(2,086	)d		—
Accumulated deficit		(255,835	)		9,198			(246,637	)		(284,945	)		11,726			(273,219	)		(268,554	)		24,371			(244,183	)

		208,029			(13,620	)		194,409			324,109			(23,625	)		300,484			335,527			(11,568	)		323,959

		281,763			(812	)		280,951			409,585			(15,167	)		394,418			412,539			(4,561	)		407,978

Reconciliation of Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)


	Three months ended June 30, 2010									Six months ended June 30, 2010									Year ended December 31, 2010
	Canadian			Effect of			IFRS			Canadian			Effect of			IFRS			Canadian			Effect of			IFRS
(US$000s)	GAAP			Transition			Balances			GAAP			Transition			Balances			GAAP			Transition			Balances

Revenue
Oil		6,047			—			6,047			11,377			—			11,377			21,720			—			21,720
Interest		23			—			23			42			—			42			208			—			208

		6,070			—			6,070			11,419			—			11,419			21,928			—			21,928


Expenses
Operating		3,229			23	b		3,252			6,652			54	b		6,706			13,514			111	b		13,625
Exploration and evaluation		—			984	g		984			—			1,590	g		1,590			—			8,471	g		8,471
General and administrative		6,999			1,906	b		9,093			13,339			3,312	b		17,525			32,864			8,481	b		42,807
					188	e								874	e								1,462	e
Depletion and depreciation		2,582			(661	)f		1,921			4,665			(1,207	)f		3,458			8,960			(2,436	)f		6,524
Foreign currency exchange		3,086			—			3,086			(1,101	)		—			(1,101	)		(3,325	)		—			(3,325	)
Derivative instruments (gain) loss		—			(21,840	)d		(21,840	)		—			(19,783	)d		(19,783	)		—			(18,571	)d		(18,571	)
Interest		4			—			4			8			—			8			24			—			24

		15,900			(19,400	)		(3,500	)		23,563			(15,160	)		8,403			52,037			(2,482	)		49,555


Income (loss) before income taxes		(9,830	)		19,400			9,570			(12,144	)		15,160			3,016			(30,109	)		2,482			(27,627	)

(Provision for) recovery of income taxes
Current		(36	)		—			(36	)		(115	)		—			(115	)		(126	)		—			(126	)
Deferred		(286	)		14	b		(275	)		(460	)		20	b		(447	)		1,125			60	b		1,171
					(3	)f								(7	)f								(14	)f

		(322	)		11			(311	)		(575	)		13			(562	)		999			46			1,045


Net income (loss) and comprehensive income (loss)		(10,152	)		19,411			9,259			(12,719	)		15,173			2,454			(29,110	)		2,528			(26,582	)

Notes to reconciliation

Reclassification of Intangible Assets

Under Canadian GAAP, oil and gas properties in the exploration and evaluation stage were classified as oil and gas properties and development costs. In accordance with IFRS 6, these properties were reclassified as intangible assets.

Adjustment for Capitalized Overhead

Under Canadian GAAP, the Company capitalized employee benefits and overhead that were directly attributable to E&E assets and PP&E. A portion of the amounts capitalized under Canadian GAAP do not meet the threshold for capitalization under IAS 16, “Property, Plant and Equipment” and therefore have been reclassified as operating costs or general and administrative expenses, as appropriate.

Decommissioning Provisions

Under Canadian GAAP, the present value of the Company’s estimated future decommissioning costs was calculated using a credit-adjusted risk-free discount rate. The discount rate under IFRS does not permit company specific credit adjustments and therefore the decommissioning provision has been recalculated using a risk-free discount rate.

Derivative Financial Instruments

Under Canadian GAAP, the equity component of the Company’s Convertible Note and the purchase warrants were classified as shareholders’ equity. In accordance with IAS 32, “Financial Instruments: Presentation,” financial instruments with an exercise price denominated in a currency other than the Company’s functional currency are accounted for as derivatives. As a result, the equity component and purchase warrants have been reclassified as derivative financial instruments.

This resulted in the reclassification of the convertible portion of the Convertible Note and purchase from shareholders’ equity to liabilities under IFRS. Additionally, IFRS requires these items to be recorded at fair value with changes in their fair value recognized in the income statement.

Share-Based Payments

Stock options were accounted for using the fair value method under Canadian GAAP and charged to operations on a straight-line basis. Under IFRS 2, “Share-Based Payment,” share-based payments are charged to operations on a graded vesting basis thereby accelerating the compensation expense recognized in earnings.

Depletion

Under Canadian GAAP, the Company depleted its oil and gas assets using the unit-of-production method, based on proved reserves. For IFRS purposes, the Company is depleting its oil and gas assets using the unit-of-production method, based on proved plus probable reserves. This has resulted in a deferral of depletion expense.

Exploration and Evaluation Expense

Under Canadian GAAP, capitalization of unsuccessful exploration activities was permitted if the carrying value of the Company’s total capitalized oil and gas properties and development was not impaired. Under IFRS, unsuccessful exploration and evaluation wells and impaired geological and geophysical assets will be charged to earnings as E&E expense.

20. COMPARATIVES

Certain comparative figures have been reclassified to conform to the current period’s presentation.


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.

Statements that contain words such as “could”, “should”, “can”, “anticipate”, “estimate”, “propose”, “plan”, “expect”, “believe”, “will”, “may” and similar expressions and statements relating to matters that are not historical facts constitute “forward-looking statements” within the meaning of the “safe harbor” provisions of the United States Private Securities Litigation Reform Act of 1995. In particular, forward-looking statements contained in this Form 10-Q include, but are not limited to statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil prices; future production levels; future royalty and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for the Company’s capital programs; future debt levels; availability of future credit facilities; possible commerciality of the Company’s projects; development plans or capacity expansions; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected operating costs; the expectation of negotiating of an extension to certain of the Company’s production sharing agreements; the expectation of the Company’s ability to comply with the new safety and environmental rules enacted; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and the Company’s ability to comply therewith; dates by which certain areas will be developed, come on-stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements.

Statements relating to “reserves” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

The forward-looking statements contained in this Form 10-Q are based on certain assumptions and analysis made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. By their nature, forward-looking statements involve inherent risks and uncertainties and risk that forward-looking statements will not be achieved. Undue reliance should not be placed on forward-looking statements as a number of important factors could cause the actual results to differ materially from the beliefs, plans, objectives, expectations and anticipations, estimates and intentions expressed in the forward-looking statements, including those set out below and those detailed in Item 1A, “Risk Factors,” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010 (“2010 Form 10-K”). Such factors include, but are not limited to: the Company’s short history of limited revenue, losses and negative cash flow from its current exploration and development activities in Canada, Ecuador, China, Mongolia and the United States; the Company’s limited cash resources and consequent need for additional financing; the ability to raise capital as and when required on acceptable terms or at all; the timing and extent of changes in prices for oil and gas; competition for oil and gas exploration properties from larger, better financed oil and gas companies; environmental risks; title matters; drilling and operating risks; uncertainties about the estimates of reserves and the potential success of the Company’s Heavy-to-light (“HTL™”) technology; the potential success of the Company’s oil and gas properties in Canada, Ecuador, China and Mongolia; 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 the Company’s capital investment program.

The forward-looking statements contained in this From 10-Q are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking statements contained herein are expressly qualified in their entirety by this cautionary statement.

Special Note to Canadian Investors

The Company is a registrant under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and voluntarily files reports with the United States 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 in the 2010 Form 10-K.

Advisories

The Form 10-Q report should be read in conjunction with the Company’s June 30, 2011 unaudited condensed consolidated financial statements (the “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 2010 Form 10-K. The Financial Statements have been prepared using accounting policies consistent with International Financial Reporting Standards (“IFRS”) and in accordance with International Accounting Standard 34, Interim Financial Reporting (“IAS 34”). A reconciliation of the previously disclosed comparative periods’ financial statements, prepared in accordance with Canadian generally accepted accounting principles (“GAAP”), to IFRS is set out in Note 19 to the Financial Statements.

As a foreign private issuer in the US, Ivanhoe is permitted to file with the SEC financial statements prepared under IFRS without a reconciliation to US GAAP. The Company will no longer prepare a reconciliation of its results to US GAAP. It is possible that some of the Company’s accounting policies under IFRS could be different from US GAAP.

Non-IFRS 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 related 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 condensed consolidated statements of loss. 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 their usefulness as comparative measures.

THE DISCUSSION AND ANALYSIS OF THE COMPANY’S OIL AND GAS ACTIVITIES, WITH RESPECT TO OIL AND GAS VOLUMES, RESERVES AND RELATED PERFORMANCE MEASURES, PRESENT THE COMPANY’S NET 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	mcf	=	thousand cubic feet
bbls/d	=	barrels per day	mcf/d	=	thousand cubic feet per day
boe	=	barrel of oil equivalent	mmcf	=	million cubic feet
boe/d	=	barrels of oil equivalent per day	mmcf/d	=	million cubic feet per day
mbbls	=	thousand barrels	mmbbls	=	million barrels
mbbls/d	=	thousand barrels per day	mmbls/d	=	million barrels per day
mboe	=	thousands of barrels of oil equivalent	mmbtu	=	million British thermal units
mboe/d	=	thousands of barrels of oil equivalent per day	tcf	=	trillion cubic feet

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) 261-1700. 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. Copies of the charters for each of the committees of the Company’s board of directors are available through the Company’s website at www.ivanhoeenergy.com/index.php?page=mandate_of_the_boardcommittee_overview.

INTERNATIONAL FINANCIAL REPORTING STANDARDS

The Company adopted IFRS on January 1, 2011, with a transition date of January 1, 2010. IFRS employs a conceptual framework that is similar to Canadian GAAP, however, significant differences exist in certain matters of recognition, measurement and disclosure. The accounting policies and financial statement accounts of the Company that were materially affected by the adoption of IFRS, as well as the IFRS 1 “First-Time Adoption of International Financial Reporting Standards” exemptions utilized by the Company, were described in the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011.

The adoption of IFRS resulted in changes to the reported financial position and earnings of the Company and the 2010 comparative periods have been restated under IFRS. Reconciliations of the statements of financial position and statements of income (loss) presented under Canadian GAAP to IFRS is included in Note 19 to the Financial Statements. Changes made to the statements of financial position and statements of loss resulted in reclassifications of various amounts on the statements of cash flows. Due to the reclassification of capitalized overhead under Canadian GAAP to operating costs or general and administrative (“G&A”) expenses under IFRS, cash used in investing activities under Canadian GAAP was reclassified to cash used in operating activities under IFRS. Since there was no change to the total increase in cash and cash equivalents, no reconciliation for the statements of cash flows was presented.

HIGHLIGHTS


	Three months						Six months
	ended June 30,						ended June 30,
($000, except as stated)	2011			2010			2011			2010
Average daily production (bbls/d)		940			869			973			837
Realized oil prices ($/bbl)		109.71			76.47			99.38			75.11
Oil revenue		9,389			6,047			17,508			11,377
Capital expenditures		17,420			12,877			31,235			36,375

Cash flow used in operating activities		(6,455	)		(6,276	)		(13,464	)		(11,707	)
Net income (loss)		(4,111	)		9,259			(15,237	)		2,454
Net income (loss) per share, basic		(0.01	)		0.03			(0.04	)		0.01
Net income (loss) per share, diluted		(0.01	)		0.01			(0.04	)		(0.05	)

Oil production increased in the first half of 2011 as Ivanhoe received additional volumes to offset capital expenditures incurred at Dagang. Additional production in combination with stronger realized prices, resulted in higher oil revenue for the Company. The net loss in the first six months of 2011 was $15.2 million compared to $2.5 million net income in the first six months of 2010, resulting from higher operating and general administrative expenses and lower non-cash foreign currency exchange and derivative instrument gains in the first half of 2011.

In June 2011, the Company issued Cdn$73.3 million in 5.75% convertible unsecured subordinate debentures (“Convertible Debentures”). At the holder’s option, the Convertible Debentures may be converted into common shares prior to June 30, 2016, at a price of Cdn$3.36 per common share. The net proceeds were used to repay the Cdn$40 million convertible promissory note due to Talisman Energy Canada on July 11, 2011, in addition to funding operating expenses and capital expenditures.

Capital expenditures totaled $31.2 million in the six months ended June 30, 2011. In the second quarter, a 100-ton hydraulic fracture stimulation was performed on the Yixin-2 gas well at the Zitong Block in China. The Zitong-1 gas well was completed and a 200-ton hydraulic fracture stimulation was performed. Both the Yixin-2 and Zitong-1 gas wells were subsequently gas flow tested. At Dagang, a second well was drilled, completed and fracture stimulated. The Company’s ongoing fracture stimulation program at Dagang continued during the quarter.

In the Nyalga basin of Mongolia, mobilization activities of a drilling rig and associated equipment for the Company’s first drilling location were initiated in June 2011 and the well is expected to spud in August 2011.

In Canada, regulators completed their initial review of the Company’s Environmental Impact Assessment for Tamarack in May 2011 and the Company anticipates submitting its responses to supplemental information requests in the third quarter of 2011. Design of the surface facilities is ongoing with AMEC-BDR, with completion of the Front-End Engineering and Design anticipated in the fall of 2011.

In Ecuador, the Company commenced its 190-kilometre 2-D seismic survey of Block 20 during the second quarter of 2011. The seismic data will assist in the selection of future appraisal drilling locations. The initial phase of shooting was completed in July and processing will begin shortly.

RESULTS OF OPERATIONS

Three months

Six months

ended June 30,

2011

2010

2011

2010

Asia (net bbls)

Dagang

81,664

75,210

168,529

143,004

Daqing

3,917

3,861

7,651

8,463

Total production

85,581

79,071

176,180

151,467

Average daily production (bbls/d)

940

869

973

837

Pricing

Average realized oil price ($/bbl)

109.71

76.47

99.38

75.11

West Texas Intermediate (WTI) ($/bbl)

102.56

78.04

98.27

78.38

Oil Revenue

Ivanhoe’s oil revenue in the three and six months ended June 30, 2011, increased from the prior periods due to a combination of higher production volumes and stronger realized prices. Oil production from the Dagang field in China was relatively constant. However, the terms of the Company’s production sharing contract at Dagang with China National Petroleum Corporation (“CNPC”) stipulate that capital expenditures are to be funded 100% by Ivanhoe and CNPC’s portion of the costs are reimbursed through the receipt of additional oil sales. Due to increased capital activity at Dagang in the three and six months ended June 30, 2011, additional oil production was allocated to Ivanhoe.

Net Revenue from Operations


	Three months						Six months
	ended June 30,						ended June 30,
($/bbl)	2011			2010			2011			2010
Oil revenue⁽¹⁾		109.71			76.47			99.38			75.11
Less operating costs
Field operating		(19.76	)		(17.29	)		(18.81	)		(17.58	)
Windfall Levy		(25.51	)		(11.00	)		(21.34	)		(11.09	)
Engineering and support costs		(1.20	)		(1.42	)		(1.21	)		(1.58	)

Net operating revenue⁽¹⁾		63.24			46.76			58.02			44.86
Depletion		(18.74	)		(23.59	)		(23.62	)		(18.02	)

Net revenue (loss) from operations⁽¹⁾		44.50			23.17			34.40			26.84


(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 IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-IFRS Financial Measures under the Advisories section in this MD&A for more details.

Operating Costs

Three months

Six months

ended June 30,

2011

2010

2011

2010

Asia

Field operating

1,692

1,367

3,315

2,664

Windfall levy

2,182

869

3,759

1,680

Engineering support

103

112

213

240

3,977

2,348

7,287

4,584

Technology Development

FTF operating costs

1,362

904

2,575

2,122

Total operating costs

5,339

3,252

9,862

6,706

Operating costs in China rose $1.6 million and $2.7 million, respectively, in the three and six months ended June 30, 2011 over the comparable periods. The increase is primarily attributable to the additional Windfall Levy administered by the People’s Republic of China, which rises with higher oil prices.

Field operating costs in total increased over the prior periods due to a combination of additional production volumes and higher costs per barrel. On a per barrel basis, field operating costs rose $2.47/bbl and $1.23/bbl in the three and six months ended June 30, 2011, respectively, due to increased contractor servicing rates and higher than normal pumping equipment failures as a result of corrosion issues. Subsequent to quarter end, additional corrosion inhibition programs were implemented.

Operating costs in the Technology Development segment are incurred at the Company’s Feedstock Test Facility (“FTF”) at the Southwest Research Institute in San Antonio, Texas. Costs in the three and six months ended June 30, 2011, rose in comparison to the second quarter of 2010 due to planned costs associated with assay and analyses related to the successful upgrading of the heavy oil recovered from the Pungarayacu IP-5B well in Ecuador and planned maintenance costs associated with enhancements implemented at the FTF unit.

Exploration and Evaluation

Costs of exploring for, and evaluating, oil and gas properties are initially capitalized as intangible exploration and evaluation assets and charged to exploration and evaluation expense only if sufficient reserves cannot be established. Exploration and evaluation expenses were nil in the three months and six months ended June 30, 2011.

Following the drilling of the Zitong-1 and Yixin-2 wells, areas excluding those identified for development and future production were to be relinquished at the end of 2010. As a result, $1.6 million of geological costs incurred in prior periods were expensed as E&E costs in the first half of 2010.

General and Administrative

G&A expenses were higher in the three and six months ended June 30, 2011, than in the comparable periods. In the second quarter of 2011, staff, office and travel costs rose $1.3 million as a result of the Company’s growing commitments to its projects around the world. Professional fees rose $1.2 million as additional legal costs were incurred in connection with the proceedings described in Part II of this Form 10-Q and contract engineering costs related to Ivanhoe’s HTL^TM technology increased. G&A also included $0.3 million of financing fees associated with the portion of the recently issued Convertible Debentures classified as derivative liabilities.

In the first half of 2011, G&A rose from the prior period due to a $5.7 million increase in staff, office and travel costs, a $1.2 million increase in professional fees and the inclusion of $0.3 million of financing fees in the six months ended June 30, 2011.

Depletion and Depreciation

Depletion and depreciation in the three months ended June 30, 2011 was consistent with the second quarter of 2010 as lower depletion in Asia in the current quarter approximated a revision to the Commercial Demonstration Facility (“CDF”) salvage value lowering depletion in the second quarter of 2010.

Depletion and depreciation in the first half of 2011 increased in comparison to 2010. Depletion in Asia was $0.4 million lower in the first half of 2011 as a result of additional Dagang proved and probable reserves at January 1, 2011. In contrast, the depreciation expense associated with the CDF and FTF was $0.5 million higher in the current year due to revisions to the CDF salvage values reducing depreciation in the half quarter of 2010.

Foreign Exchange

Ivanhoe incurred a foreign exchange gain in the second quarter of 2011 compared to a loss in the second quarter of 2010. During the second quarter of 2011, the Canadian dollar strengthened slightly in comparison to the US dollar creating a gain on the translation of the Company’s Canadian dollar cash, working capital and debt into US dollars. In contrast, the Canadian dollar weakened against the US dollar during the second quarter of 2010 resulting in a foreign exchange loss.

In the first half of 2011, the foreign exchange gain was less than in the prior period. The $3.1 million loss incurred in the second quarter of 2010 was offset by a $4.2 million gain in the first quarter of 2010 due to the Canadian dollar strengthening against the US dollar in the first quarter of 2010.

Derivative Instruments

In the second quarter of 2011, the Company incurred an unrealized gain of $6.1 million on its derivative liabilities. The expiry of the Company’s 2006 purchase warrants resulted in a gain of $2.3 million. Due to the impending maturity of the Convertible Note, a gain of $0.7 million was recognized on the revaluation of the convertible portion at June 30, 2011, while the revaluation of the convertible portion of the Convertible Debentures created a gain of $2.2 million for the quarter. The revaluation of an option granted to a private investor in January 2010 to acquire an equity interest in one of the Company’s subsidiaries created a gain of $0.9 million in the second quarter of 2011. The $21.8 million unrealized gain recognized in the second quarter of 2010 stemmed from a $15.5 million and $6.4 million gain, respectively, on the revaluation of the purchase warrants and Convertible Note.

A combination of the expiry and revaluation of the 2009 and 2010 purchase warrants during the first quarter of 2011 contributed to the $7.2 million gain on derivative instruments recognized in the first half of 2011. A gain of $19.8 million was recognized in the first half of 2010 as a loss on the revaluation of the Convertible Note in the first quarter partially offset the second quarter 2010 gains on the revaluation of the Convertible Note.

Provision for Income Taxes

Current taxes in China increased in both the three and six months ended June 30, 2011, due to higher oil revenue than in the comparable periods. Ivanhoe incurred a future tax expense of $0.7 million in the first half of 2011 due to increases in the deferred tax liability in China net of operating loss carryforwards, which was partially offset by continuing operating loss carryforwards in the US.

LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations

The following information about the Company’s contractual obligations and other commitments summarizes certain liquidity and capital resource requirements. The information presented in the table below does not include planned, but not legally committed, capital expenditures or obligations that are discretionary and/or being performed under contracts which can be terminated on 30 days notice. Previous exploration commitments in Zitong and Nyalga have been fulfilled and therefore are not included below.


	Total		2011		2012		2013		2014		After 2014
Debt		41,472		41,472		—		—		—		—
Long term debt		76,024		—		—		—		—		76,024
Interest		23,148		3,484		4,371		4,371		4,371		6,551
Decommissioning provisions⁽¹⁾		2,081		—		—		344		—		1,737
Long term obligation		1,900		—		—		—		—		1,900
Lease commitments		2,059		906		886		267		—		—

		146,684		45,862		5,257		4,982		4,371		86,212


(1)		Represents undiscounted asset retirement obligations after inflation. The discounted value of these estimated obligations is provided for in the Financial Statements.

Debt

The Company’s Cdn$40.0 million Convertible Note matured in July 2011. The final interest payment was due on July 11, 2011.

Long Term Debt and Interest

As described in Note 6 to the Financial Statements, the Company issued Cdn$73.3 million of Convertible Debentures, maturing on June 30, 2016. The outstanding principal amount is convertible at the option of the holders, into a maximum of 21,818,452 Ivanhoe common shares at Cdn$3.36 per common share. The Convertible Debentures bear interest at an annual rate of 5.75%, payable semi-annually on the last day of June and December of each year, commencing on December 31, 2011.

Decommissioning Provisions

The Company is required to remedy the effect of our activities on the environment at its operating sites by dismantling and removing production facilities and remediating any damage caused. At June 30, 2011, Ivanhoe estimated the total undiscounted, inflated cost to settle its asset retirement obligations in Canada, for the FTF and in Ecuador was $2.1 million. These costs are expected to be incurred in 2013, 2029 and 2038, respectively. Ivanhoe does not make such a provision for decommissioning costs in connection with its oil and gas operations in China as dry holes are abandoned as they occur and the Company is under no obligation to contribute to the future costs to restore well sites or abandon the field.

Long Term Obligation

As part of its 2005 merger with Ensyn, the Company assumed an obligation to pay $1.9 million in the event that proceeds from the sale of units incorporating the HTL™ technology for petroleum applications reach a total of $100.0 million.

Operating Leases

The Company has long term operating leases for office space, which expire between 2011 and 2013.

Other

The Company may be required to make a payment of up to Cdn$15 million if, and when, the requisite governmental and other approvals are received to develop the northern border of one of the Tamarack leases.

From time to time, Ivanhoe enters into consulting agreements whereby a success fee may be payable if and when either a definitive agreement is signed or certain other contractual milestones are met. Under the agreements, the consultant may receive cash, common shares, stock options or some combination thereof. These fees are not considered to be material.

The Company may provide indemnities to third parties, in the ordinary course of business, that are customary in certain commercial transactions, such as purchase and sale agreements. The terms of these indemnities will vary based upon the contract, the nature of which prevents Ivanhoe from making a reasonable estimate of the maximum potential amounts that may be required to be paid. The Company’s management is of the opinion that any resulting settlements relating to indemnities are not likely to be material.

In the ordinary course of business, the Company is subject to legal proceedings being brought against it. While the final outcome of these proceedings is uncertain, the Company believes that these proceedings, in the aggregate, are not reasonably likely to have a material effect on its financial position or earnings.

Sources and Uses of Cash

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


	Three months						Six months
	ended June 30,						ended June 30,
	2011			2010			2011			2010
Cash used in operating activities		(6,455	)		(6,276	)		(13,464	)		(11,707	)
Cash used in investing activities		(16,639	)		(11,842	)		(28,123	)		(35,210	)
Cash provided by (used in) financing activities		72,945			(59	)		102,740			137,898

Ivanhoe’s cash flow from operating activities is not sufficient to meet its operating and capital obligations over the next twelve months. The Company intends to use its working capital 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 six months ended June 30, 2011, cash used in operating activities was higher than in 2010 as additional operating costs and G&A expenses were only partially offset by higher revenue in the current periods.

Investing Activities

E&E Expenditures

E&E expenditures in the first six months of 2011 totaled $23.8 million. At the Yixin-2 gas well, a 100-ton hydraulic fracture stimulation was performed after initial pre-stimulation gas testing of the Xu-4 formation. Subsequent to the post-fracture gas flow test, down-hole electronic recorders were installed to gather additional pressure data during an extended shut-in period.

Following initial gas testing operations performed on the Xu-4 and Xu-5 formations of the Zitong-1 gas well in the first quarter, the Xu-5 formation was hydraulic fracture stimulated with 200-tons and the zone was then gas flow tested. Coil tubing and nitrogen were used to assist in liquid unloading of the wellbore during the test period. Following the flow testing, down-hole electronic recorders were run and the well was shut-in for an extended pressure build-up.

In the Nyalga basin of Mongolia, mobilization activities of a drilling rig and associated equipment for the Company’s first drilling location were initiated in June 2011.

In Canada, regulators completed their initial review of the Company’s Environmental Impact Assessment for Tamarack and, as is customary, provided the Company with an initial set of Supplemental Information Requests in May 2011. Ivanhoe plans to submit its responses in the third quarter of 2011. The Company is continuing to work with numerous local and aboriginal stakeholders and identify economic and employment opportunities for residents of area communities. Design of the surface facilities is ongoing with AMEC-BDR, with completion of the Front-End Engineering and Design anticipated in the fall of 2011.

		In Ecuador, the Company commenced its 190-kilometre 2-D seismic survey of Block 20 during the second quarter of 2011. The seismic data will assist in the selection of future appraisal drilling locations. The initial phase of shooting was completed in July and processing will begin shortly.

		*PP&E Expenditures*

In the first six months of 2011, PP&E additions totaled $7.5 million. At Dagang, a second well was drilled, completed and fracture stimulated in addition to the 2010 well completed in the first quarter of 2011. The fracture stimulation program at Dagang also continued during the quarter.

Financing Activities

Cash provided by financing activities was higher in the three and six months ended June 30, 2011 than in the prior periods. In June 2011, the Company raised Cdn$71.3 million, net of issuance costs, through the issuance of Convertible Debentures. At the holder’s option, the Convertible Debentures may be converted into common shares prior to June 30, 2016, at a price of Cdn$3.36 per common share. The net proceeds were used to repay the Convertible Note due to Talisman Energy Canada on July 11, 2011, as well as operating expenses and capital expenditures. In the first quarter of 2011, cash proceeds of $29.8 million were raised through the exercise of purchase warrants and stock options.

In comparison, the Company raised $135.8 million, net of issuance costs, through a private placement of 50 million special warrants at a price of Cdn$3.00 per special warrant in the first six months of 2010.

Capital Structure


	June 30,		December 31,
As at	2011		2010
Debt		41,441		39,832
Long term debt		64,322		—
Shareholders’ equity		321,462		300,484

Ivanhoe intends to use its cash and cash equivalent balance to fulfill its commitments and partially fund operations in 2011. Cash flow may be insufficient to meet operating requirements in the next twelve months and additional sources of funding, either at a parent company level or at a project level, will be required to grow the Company’s major projects and fully develop its oil and gas properties. Historically, Ivanhoe has used external sources of funding, such as public and private equity and debt markets. There is no assurance that the Company will be able to obtain additional financing on favorable terms, if at all, and any future equity issuances may be dilutive to current investors. If Ivanhoe cannot secure additional financing, the Company may have to delay its capital programs and forfeit or dilute its rights in existing oil and gas property interests.

Outlook

In China, upon approval of the recently submitted provisional Overall Development Program, the Company is planning a 150-square-kilometre, 3-D seismic program to cover certain areas of the Zitong Block to help plan and design a horizontal well-path for two horizontal wells in the Guan and Wen structures. The Company’s plan is to drill a Guan East well with a horizontal leg as a first-stage test of the regional gas play. Re-entry into the Zitong-1 wellbore to complete a horizontal section in the Xu-4 Zone will also be reviewed. This program will be carried out over the next 24 months and will provide the groundwork for development of the Zitong Block.

In Mongolia, mobilization activities of a drilling rig and associated equipment for the Company’s first drilling location were initiated in June 2011, however heavy rains during the last week of June caused some delay in mobilization. The well is now expected to spud in August, 2011.

In Canada, regulators completed their initial review of the Ivanhoe’s Environmental Impact Assessment for Tamarack in May 2011 and the Company anticipates submitting its responses to supplemental information requests in the third quarter of 2011. Design of the surface facilities is ongoing with AMEC-BDR, with completion of the Front-End Engineering and Design anticipated in the fall of 2011. Progress to date indicates that the Tamarack Project remains on track for approval expected in the second half of 2012.

In Ecuador, the Company commenced its 190-kilometre 2-D seismic survey of Block 20 during the second quarter of 2011. The initial phase of shooting was completed in July and processing will begin shortly. A geologic interpretation suggests the heavy-oil field may extend further southward than previously expected and geologic evidence suggests that a deeper, lighter oil play may also exist on the block. The current 2-D seismic program is expected to provide additional information on these interpretations.

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.


ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There has been no material change in the Company’s assessment of its sensitivity to market risk since its presentation set forth in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” in the 2010 Form 10-K.


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, 2011. 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 Chief Executive Officer and Chief 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, 2011, 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 on November 20, 2008, in the United States 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 plaintiffs’ 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 United States Court of Appeals for the Tenth Circuit. Briefing on the appeal is complete; the plaintiffs have filed an opening and reply brief and the Company and related defendants have filed a response brief. The Court heard oral arguments on May 9, 2011, in Denver, Colorado, but has not yet ruled on the appeal. 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.

On December 30, 2010, the Company received a demand for arbitration from GAR Energy and Associates, Inc. (“GAR Energy”) and Gonzalo A. Ruiz and Janis S. Ruiz as successors in interest to and assignees of GAR Energy. GAR Energy subsequently abandoned its demand for arbitration and filed suit against the Company in the Superior Court for Kern County, California on March 11, 2011. The lawsuit alleges breach of contract, fraud and other misconduct arising from a consulting agreement and various other agreements between GAR Energy and the Company relating to the Pungarayacu heavy oil field. The Plaintiffs seek actual damages of $250,000, a portion of the Company’s interest in the Pungarayacu field and other miscellaneous relief. On June 2, 2011, the Company filed its Answer to the Complaint and on June 3, 2011 removed the lawsuit to the United States District Court for the Eastern District of California. After the lawsuit was removed to federal court, the Plaintiffs filed their First Amended Complaint and a motion asking the district court to remand the action to state court. The Company filed its Answer to the First Amended Complaint including a counterclaim for attorneys’ fees and a motion asking the court to dismiss some of the claims against it on July 11, 2011. The Company’s response to the motion to remand is due August 1, 2011. The likelihood of loss or gain resulting from this dispute, and the estimated amount of ultimate loss or gain, are not determinable or reasonably estimable at this time.


ITEM 6.		EXHIBITS


Exhibit Number		Description

	1.1	Underwriting Agreement, dated May 18, 2011, among Ivanhoe Energy Inc. and TD Securities Inc., Macquarie Capital Markets Canada Ltd., RBC Dominion Securities Inc., UBS Securities Canada Inc., CIBC World Markets Inc. and Byron Capital Markets Ltd.

	4.1	Debenture Indenture, dated as of June 9, 2011, between Ivanhoe Energy Inc. and BNY Trust Company of Canada, as trustee

	10.1	Restricted Share Unit Plan

	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
		Gerald D. Schiefelbein
		Chief Financial Officer

Date: August 9, 2011

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